JP2017519929A - System and method for adjustment of recirculated exhaust gas - Google Patents

Abstract

Includes a recirculation exhaust gas adjustment loop that sends exhaust gas from the heat recovery steam generator to the turbine compressor inlet, where the recirculation exhaust gas adjustment loop cools the exhaust gas and removes particulate matter from the exhaust gas A system that includes a device and a dehumidifier that dehumidifies exhaust gas. [Selection] Figure 1

Description

[Cross-reference to related applications]
This application is based on US Provisional Patent Application No. 61 / 970,766, filed Mar. 26, 2014, entitled “SYSTEM AND METHOD FOR THE CONDITIONING OF RECIRCULATED EXHAUST GAS”, which is incorporated herein by reference in its entirety. It claims priority interests.

  The present description relates generally to gas turbine systems, and more specifically to gas turbine driven power plants.

  Gas turbine engines are used in a wide variety of applications such as power generation, aircraft, and various mechanical devices. Gas turbine engines typically combust fuel with an oxidant (eg, air) in a combustor section to generate hot combustion products, thereby driving one or more turbine stages in the turbine section. The turbine section then drives one or more compressor stages of the compressor section, thereby compressing the oxidant for intake with the fuel into the combustor section. Again, the fuel and oxidant are mixed in the combustor section and then combusted to produce hot combustion products. These combustion products may contain unburned fuel, residual oxidant, and various emissions (eg, nitrogen oxides) depending on the conditions of combustion. In addition, gas turbine engines typically consume a large amount of air as an oxidant and output a significant amount of exhaust gas into the atmosphere. In other words, exhaust gas is typically wasted as a byproduct of gas turbine operation.

  Includes a recirculation exhaust gas adjustment loop that sends exhaust gas from the heat recovery steam generator to the turbine compressor inlet, where the recirculation exhaust gas adjustment loop cools the exhaust gas and removes particulate matter from the exhaust gas A system that includes a device and a dehumidifier that dehumidifies exhaust gas.

  The system can further include a separation section between the exhaust gas conditioning device and a dehumidifier that removes liquid introduced by the exhaust gas conditioning device from the exhaust gas.

  The exhaust gas conditioning device can include a vertical direct contact condenser having a spray column that generates a co-flow of exhaust gas and heat transfer liquid in the same downward direction.

  The system can further include a heat recovery steam generator, and the input to the recirculated gas conditioning loop is in fluid communication with the top back section of the heat recovery steam generator.

  The system can further include a bypass stack that provides atmospheric release of the exhaust gas and a damper assembly that delivers the exhaust gas to the bypass stack or the exhaust gas conditioning device prior to the exhaust gas conditioning device.

  The dehumidifier can include a flue gas condenser that cools and dehumidifies the exhaust gas.

  The system includes a protective stack that provides an atmospheric release of exhaust gas downstream from the dehumidifier and before the turbine compressor inlet, and a damper that sends the exhaust gas to the protective stack or turbine compressor inlet and downstream from the flue gas condenser An assembly.

  Recirculating the exhaust gas through a conditioning loop that sends the exhaust gas from the heat recovery steam generator to the turbine compressor inlet, the recirculating step cooling the exhaust gas with an exhaust gas conditioning device; A method comprising: removing particulate matter from exhaust gas using a gas conditioning device; and dehumidifying exhaust gas using a dehumidifier.

  The method may further include removing liquid introduced by the exhaust gas conditioning device from the exhaust gas using a separation section between the exhaust gas conditioning device and the dehumidifier.

  The exhaust gas conditioning device can include a vertical direct contact condenser having a spray column, and the method includes generating a co-flow of exhaust gas and heat transfer liquid discharged from the spray column in the same downward direction. be able to.

  The method further includes using a computer to control the damper assembly to route exhaust gas to a bypass stack or exhaust gas conditioning device that provides an atmospheric release of exhaust gas before the exhaust gas reaches the exhaust gas conditioning device. Can be included.

  The method uses a computer to direct exhaust gas to a protective stack or turbine compressor inlet that provides atmospheric emissions of exhaust gas downstream from the dehumidifier and before the turbine compressor inlet and downstream from the flue gas condenser. The method may further include controlling the damper assembly to deliver.

  The present disclosure is susceptible to various modifications and alternative forms, and these specific examples are illustrated in the drawings and are described in detail herein. However, the description herein of specific embodiments is not intended to limit the disclosure to the particular forms disclosed herein, but rather, the disclosure is defined by the appended claims. It should be understood that all modifications and equivalents as such are intended to be covered. It should also be understood that the drawings are not necessarily to scale, emphasis instead being placed upon clearly illustrating the principles of technical progress of the present invention. In addition, certain dimensions are exaggerated, helping to visually convey such principles.

FIG. 3 is a non-limiting example of a system having a turbine-based service system coupled to a hydrocarbon generation system. FIG. 4 is a non-limiting example of adjustment of recirculated exhaust gas. 2 is a flowchart of a non-limiting example of a process for adjusting recirculated exhaust gas. FIG. 2 is a diagram of a non-limiting example of a computer that can be used with the technical advances of the present invention. FIG. 4 is a flow chart of a non-limiting method for controlling recirculated gas adjustment.

  Non-limiting examples of technical advances of the present invention are described herein. The invention is not limited to the specific embodiments described below, but rather the invention includes all alternatives, modifications and equivalents that fall within the spirit and scope of the appended claims. .

  As part of an effort to provide a concise description of these embodiments, all features of an actual implementation may not be described herein. As with technology or design projects, in developing any such actual implementation, to achieve specific goals that may vary from implementation to implementation, such as compliance with system and / or business-related constraints It should be understood that many implementation specific decisions are made. Moreover, although such an effort may be complex and time consuming, it will be understood by those of ordinary skill in the art having the benefit of this disclosure that it is a routine task of design, fabrication, and manufacturing. I want to be.

  Detailed exemplary embodiments are disclosed herein. However, the specific structural and functional details disclosed herein are merely representative for purposes of describing example embodiments. However, embodiments of the technical advancement of the present invention may be embodied in many alternative forms and should not be construed as limited to only the embodiments set forth herein.

  The terminology used herein is for the purpose of describing particular embodiments only and is not intended to be limiting of example embodiments. As used herein, references to the singular or to the number are intended to include the plural unless the context clearly dictates otherwise. The terms “comprising”, “having”, and / or “including”, as used herein, identify the presence of a feature, integer, step, operation, element, and / or component, but 1 or 2 The presence or addition of other features, integers, steps, operations, elements, components, and / or groups thereof is not excluded.

  The terms first, second, first, second, etc. may be used herein to describe various elements, but these elements should not be limited to these terms. These terms are only used to distinguish one element from another. For example, without limitation, a first element can be referred to as a second element, and, similarly, a second element can be referred to as a first element, without departing from the scope of the exemplary embodiments. it can. As used herein, the term “and / or” includes any and all combinations of one or more of the associated items listed above.

  Certain terminology may be used herein for the convenience of the reader only and should not be taken to limit the scope of the invention. For example, “upper”, “lower”, “left”, “right”, “front”, “rear”, “top”, “bottom”, “horizontal”, “vertical”, “upstream”, “downstream” Words such as “,” “front” and “back” merely describe the configuration shown in the figure. Of course, one or more elements of embodiments of the present invention may be oriented in either direction, and thus the terminology is such a variation unless specifically stated otherwise. It should be understood as including.

As discussed in detail below, the disclosed embodiments generally relate to gas turbine systems with exhaust gas recirculation (EGR), and more particularly, the amount of gas turbine systems using EGR. Concerning theoretical operation. For example, a gas turbine system may recirculate exhaust gas along an exhaust gas recirculation path and quantitatively burn fuel and oxidant along with at least a portion of the recirculated exhaust gas to provide various target systems. The exhaust gas can be configured to be taken in for use. By recirculating the exhaust gas with stoichiometric combustion, it helps to increase the concentration level of carbon dioxide (CO ₂ ) in the exhaust gas, and CO ₂ and nitrogen (N ₂₎ for use in various target systems. ) Can be worked up to separate and purify. The gas turbine system also utilizes various exhaust gas processes (eg, heat recovery, catalytic reaction, etc.) along the exhaust gas recirculation path, thereby increasing the CO ₂ concentration level and other emissions (eg, , Carbon monoxide, nitrogen oxides, and unburned hydrocarbons) can be reduced in level and energy recovery (eg, using a heat recovery unit) can be improved. Further, the gas turbine engine may use one or more diffusion flames (eg, using diffusion fuel nozzles), a premixed flame (eg, using premix fuel nozzles) to burn fuel and oxidant. Can be configured. In certain embodiments, diffusion flames can help maintain stability and operation within certain limits of stoichiometric combustion, which in turn helps to increase CO ₂ production. For example, a gas turbine system that operates with a diffusion flame may allow a greater amount of EGR than a gas turbine system that operates with a premixed flame. Then, increase of the EGR serves to increase the CO ₂ generation. Possible target systems include pipelines such as crude oil secondary recovery (EOR) systems, storage tanks, carbon sequestration systems, and hydrocarbon production systems.

  In particular, embodiments of the invention relate to gas turbine systems, that is, stoichiometric exhaust gas recirculation (EGR) systems that include ultra-low emission technology (ULET) power plants. These systems generally include at least one gas turbine engine that is coupled to the distribution network and generates electrical output to the distribution network. For example, embodiments of the present invention include a ULET having one or more generators that convert a portion of the mechanical output provided by one or more EGR gas turbine engines into electrical output for delivery to a distribution network. Includes power plant.

  In view of the foregoing, FIG. 1 is a diagram of an embodiment of a system 10 having a hydrocarbon generation system 12 associated with a turbine-based service system 14. As discussed in more detail below, various embodiments of the turbine-based service system 14 provide various services, such as power, mechanical output, and fluid (eg, exhaust gas), to the hydrocarbon generation system 12. Configured to facilitate the production or removal of oil and / or gas. In the illustrated embodiment, the hydrocarbon production system 12 includes an oil / gas extraction system 16 and a crude oil secondary recovery (EOR) system 18 that includes an underground reservoir 20 (eg, an oil, gas, or hydrocarbon reservoir). Connected to The oil / gas extraction system 16 includes various out-of-well equipment (such as a Christmas tree or production tree 24) coupled to an oil / gas well 26. Further, the well 26 may include one or more tubes 28 that extend through the drilling bore 30 in the ground 32 to the underground reservoir 20. The tree 24 includes one or more valves, chokes, separation sleeves, blowout prevention devices, and various flow control devices that regulate pressure and control flow with the underground reservoir 20. The tree 24 is generally used to control the flow of production fluid (eg, oil or gas) out of the underground reservoir 20, while the EOR system 18 allows one or more fluids to flow into the underground reservoir 20. Oil or gas production can be increased.

  Accordingly, the EOR system 18 may include a fluid injection system 34 having one or more tubes 36 that extend into the underground reservoir 20 through a bore 38 in the ground 32. For example, the EOR system 18 can send one or more fluids 40 (gas, steam, water, chemicals, or some combination thereof) to the fluid injection system 34. For example, as will be discussed in more detail below, the EOR system 18 is coupled to a turbine-based service system 14 so that the system 14 is free of exhaust gas 42 (eg, substantially or completely free of oxygen). ) To the EOR system 18 and can be used as the infusion fluid 40. The fluid injection system 34 delivers fluid 40 (eg, exhaust gas 42) through one or more tubes 36 to the underground reservoir 20 as indicated by arrow 44. The infused fluid 40 flows into the underground reservoir 20 through a tube 36 that is separated from the tube 28 of the oil / gas well 26 by an offset distance 46. Accordingly, the infused fluid 40 moves oil / gas 48 disposed within the underground reservoir 20, causing the oil / gas 48 to move to one or more tubes 28 of the hydrocarbon generation system 12, as indicated by arrows 50. Through and through. As will be discussed in more detail below, the infusion fluid 40 removes exhaust gas 42 generated from a turbine-based service system 14 that can generate exhaust gas 42 within the facility as needed by the hydrocarbon generation system 12. Can be included. In other words, the turbine-based system 14 may include one or more services (eg, power, mechanical output, steam, water (eg, demineralized water)) and exhaust gases (eg, substantially Without oxygen), thereby reducing or eliminating the dependence of such services on external sources.

In the illustrated embodiment, the turbine-based service system 14 includes a stoichiometric exhaust gas recirculation (SEGR) gas turbine system 52 and an exhaust gas (EG) processing system 54. The gas turbine system 52 includes a stoichiometric combustion mode of operation (eg, stoichiometric control mode) and a non-stoichiometric combustion mode of operation (eg, non-stoichiometric control), such as a fuel lean control mode or a fuel rich control mode. Mode). In the stoichiometric control mode, combustion generally occurs at a substantially stoichiometric ratio of fuel and oxidant, thereby resulting in substantially stoichiometric combustion. In particular, stoichiometric combustion generally involves consuming substantially all of the fuel and oxidant in the combustion reaction such that the combustion products are substantially or completely free of unburned fuel and oxidant. . One measure of stoichiometric combustion is the equivalence ratio or phi (Φ), which is the ratio of the actual fuel / oxidizer ratio to the stoichiometric fuel / oxidizer ratio. An equivalence ratio greater than 1.0 results in fuel rich combustion of fuel and oxidant, while an equivalence ratio less than 1.0 results in fuel lean combustion of fuel and oxidant. In contrast, an equivalence ratio of 1.0 results in combustion that is neither fuel rich nor fuel lean, and thus consumes substantially all of the fuel and oxidant in the combustion reaction. In the context of the disclosed embodiments, the term “stoichiometric” or “substantially stoichiometric” can refer to an equivalent ratio of about 0.95 to about 1.05. However, the disclosed embodiments can also include equivalent ratios of 1.0 ± 0.01, 0.02, 0.03, 0.04, 0.05, or more. Again, stoichiometric combustion of fuel and oxidant in turbine-based service system 14 results in combustion products or exhaust gases (eg, 42) that are substantially free of residual unburned fuel or oxidant. Can bring. For example, the exhaust gas 42 may be less than 1, 2, 3, 4, or 5 volume percent oxidizer (eg, oxygen), unburned fuel or hydrocarbon (eg, HC), nitrogen oxide (eg, NOx), It can have carbon monoxide (CO), sulfur oxides (eg, SOx), hydrogen, and other incomplete combustion products. According to another embodiment, the exhaust gas 42 is about 10, 20, 30, 40, 50, 60, 70, 80, 90, 100, 200, 300, 400, 500, 1000, 2000, 3000, 4000, Or less than 5000 ppmv (parts per million) oxidizer (eg oxygen), unburned fuel or hydrocarbon (eg HC), nitrogen oxides (eg NOx), carbon monoxide (CO), sulfur oxidation Product (eg, SO _x ), hydrogen, and other incomplete combustion products. However, the disclosed embodiments also produce other ranges of residual fuel, oxidant, and other emission levels in the exhaust gas 42. As used herein, the terms “emission”, “emission level”, and “emission target” refer to specific combustion products (eg, NOx, CO, SOx, O ₂ , N ₂ , H ₂ , HCs). , Etc.), which are recirculated gas streams, discharged gas streams (eg, exhausted to the atmosphere), and various target systems (eg, hydrocarbon production systems) It can be present in the gas stream used in 12).

  Although the SEGR gas turbine system 52 and the EG processing system 54 may include various components in different embodiments, the illustrated EG processing system 54 includes a heat recovery steam generator (HRSG) 56 and an exhaust gas recirculation ( EGR) system 58, which receives and processes the exhaust gas 60 generated from the SEGR gas turbine system 52. The HRSG 56 can include one or more heat exchangers, condensers, and various heat recovery equipment, which collectively transfer heat from the exhaust gas 60 to the water stream to generate steam 62. It works as follows. Steam 62 may be used in one or more steam turbines, EOR system 18, or any other portion of hydrocarbon generation system 12. For example, the HRSG 56 can produce low pressure, medium pressure, and / or high pressure steam 62 that selectively apply to different applications of the low pressure, medium pressure, and high pressure steam turbine stages or EOR system 18. be able to. In addition to steam 62, treated water 64, such as demineralized water, can be generated by HRSG 56, EGR system 58, and / or another portion of EG processing system 54 or SEGR gas turbine system 52. Treated water 64 (eg, demineralized water) can be particularly useful in water-deficient areas such as inland or desert areas. The treated water 64 may be generated at least in part by a large amount of air that causes combustion of fuel within the SEGR gas turbine system 52. While on-site production of steam 62 and water 64 is beneficial for many applications (including hydrocarbon production system 12), on-site production of exhaust gases 42, 60 is from SEGR gas turbine system 52. Due to the low oxygen content, high pressure and heat produced, it can be particularly beneficial to the EOR system 18. Accordingly, the HRSG 56, EGR system 58, and / or another portion of the EG processing system 54 outputs or recirculates exhaust gas 60 to the SEGR gas turbine system 52 via a recirculated exhaust gas conditioning system (REGCS) 100. At the same time, the exhaust gas 42 can be sent to the EOR system 18 for use with the hydrocarbon generation system 12. Similarly, the exhaust gas 42 can be extracted directly from the SEGR gas turbine system 52 (ie, without passing through the EG processing system 54) for use in the EOR system 18 of the hydrocarbon generation system 12.

  The exhaust gas recirculation is processed by the EGR system 58 of the EG processing system 54. For example, the EGR system 58 can include one or more conduits, valves, blowers, exhaust gas treatment systems (eg, filters, particulate matter removal units, gas separation units, gas purification units, heat exchangers, heat recovery units, dehumidification units) Input from the output of the SEGR gas turbine system 52 (eg, exhausted exhaust gas 60) along an exhaust gas recirculation path (including a unit, catalyst unit, chemical injection unit, or combination thereof) and a controller. For example, the exhaust gas is recirculated to the inhaled exhaust gas 60). In the illustrated embodiment, the SEGR gas turbine system 52 draws exhaust gas 60 into a compressor section having one or more compressors, thereby compressing the exhaust gas 60 to produce oxidants 68 and 1 or 2. It is used in the combustor section together with the intake of the fuel 70 described above. The oxidant 68 can include ambient air, pure oxygen, oxygen-enriched air, anoxic air, oxygen-nitrogen mixture, or any suitable oxidant that promotes combustion of the fuel 70. The fuel 70 can include one or more gas fuels, liquid fuels, or some combination thereof. For example, fuel 70 can include natural gas, liquefied natural gas (LNG), syngas, methane, ethane, propane, butane, naphtha, kerosene, diesel fuel, ethanol, methanol, biofuel, or some combination thereof. .

The SEGR gas turbine system 52 mixes and combusts exhaust gas 60, oxidant 68, and fuel 70 in the combustor section, thereby driving one or more turbine stages in the turbine section. Gas 60 is generated. In certain embodiments, each combustor in the combustor section includes one or more premix fuel nozzles, one or more diffusion fuel nozzles, or some combination thereof. For example, each premix fuel nozzle mixes oxidant 68 and fuel 70 within the fuel nozzle and / or partially upstream of the fuel nozzle, thereby premixed combustion (eg, premixed flame). Thus, the oxidant-fuel mixture can be injected from the fuel nozzle into the combustion zone. According to another embodiment, each diffusion fuel nozzle separates the oxidant 68 and fuel 70 streams within the fuel nozzle, thereby fueling the oxidant 68 and fuel 70 for diffusion combustion (eg, diffusion flame). It can be configured to inject separately from the nozzle into the combustion zone. In particular, the diffusion combustion provided by the diffusion fuel nozzle delays the mixing of oxidant 68 and fuel 70 to the point of initial combustion or flame region. In embodiments utilizing a diffusion fuel nozzle, the diffusion flame is generally at a stoichiometric point between separate streams of oxidant 68 and fuel 70 (ie, when oxidant 68 and fuel 70 are mixed). Since it is formed, flame stability can be improved. In certain embodiments, one or more diluents (e.g., exhaust gas 60, steam, nitrogen, or another inert gas) are added to the oxidant 68, fuel, or fuel in either the diffusion fuel nozzle or the premix fuel nozzle. 70, or both. In addition, one or more diluents (e.g., exhaust gas 60, steam, nitrogen, or another inert gas) may be combusted at or downstream from the combustion point within each combustor. Can be injected into. The use of these diluents helps to temper flames (eg, premixed or diffusion flames), thereby helping to reduce NOx emissions such as nitric oxide (NO) and nitrogen dioxide (NO ₂ ). be able to. Regardless of the type of flame, combustion produces hot combustion gas or exhaust gas 60 to drive one or more turbine stages. As each turbine stage is driven by exhaust gas 60, SEGR gas turbine system 52 generates mechanical output 72 and / or electrical output 74 (eg, via a generator). The system 52 can also output exhaust gas 60 and further output water 64. Again, the water 64 can be treated water, such as demineralized water, which can be useful in a variety of applications within or outside the facility.

Exhaust gas extraction is also provided by the SEGR gas turbine system 52 using one or more extraction points 76. For example, the illustrated embodiment receives an exhaust gas 42 from an extraction point 76, processes the exhaust gas 42, and then supplies or distributes the exhaust gas 42 to various target systems 80. And an exhaust gas (EG) supply system 78 having an exhaust gas (EG) treatment system 82. The target system may include the EOR system 18 and / or other systems such as the pipeline 86, the storage tank 88, or the carbon sequestration system 90. The EG extraction system 80 may include one or more conduits, valves, controls, and flow separators that isolate the exhaust gas 42 from the oxidant 68, fuel 70, and other contaminants. At the same time, the temperature, pressure and flow rate of the extracted exhaust gas 42 can be controlled. The EG treatment system 82 may include one or more heat exchangers (eg, heat recovery units such as heat recovery steam generators, condensers, coolers, or heaters), catalyst systems (eg, oxidation catalyst systems), particulates Substance and / or water removal systems (eg, gas dehydration units, inertial force sorters, coagulation filters, water impervious filters, and other filters), chemical injection systems, solvent-based processing systems (eg, absorbers, flashes) Tanks, etc.), carbon capture systems, gas separation systems, gas purification systems, and / or solvent based processing systems, exhaust gas compressors, any combination thereof. These subsystems of the EG processing system 82 allow temperature, pressure, flow rate, moisture content (eg, moisture removal), particulate matter content (eg, particulate matter removal), and gas composition (eg, CO 2). ₂ , N ₂ , and other ratios) can be controlled.

The extracted exhaust gas 42 is processed by one or more subsystems of the EG processing system 82 depending on the target system. For example, the EG treatment system 82 can direct some or all of the exhaust gas 42 through a carbon capture system, gas separation system, gas purification system, and / or solvent-based treatment system for use in various target systems. The carbon-containing gas (for example, carbon dioxide) 92 and / or nitrogen (N ₂ ) 94 is controlled to be separated and purified. For example, an embodiment of the EG processing system 82 performs gas separation and purification and produces a plurality of different streams 95 of exhaust gas 42 such as a first stream 96, a second stream 97, and a third stream 98. Can be generated. The first stream 96 may have a first composition that is carbon dioxide rich and / or nitrogen lean (eg, a CO ₂ rich N ₂ lean stream). The second stream 97 can have a second composition that is an intermediate concentration level of carbon dioxide and / or nitrogen (eg, an intermediate concentration CO ₂ .N ₂ stream). The third stream 98 may have a third composition that is carbon dioxide lean and / or nitrogen rich (eg, a CO ₂ lean / N ₂ rich stream). Each stream 95 (eg, 96, 97, and 98) may include a gas dehydration unit, a filter, a gas compressor, or a combination thereof to facilitate delivery of stream 95 to the target system. In certain embodiments, the CO ₂ rich N ₂ lean stream 96 has a CO ₂ purity or concentration level greater than about 70, 75, 80, 85, 90, 95, 96, 97, 98, or 99 volume percent. Can have an N ₂ purity or concentration level less than about 1, 2, 3, 4, 5, 10, 15, 20, 25, or 30 volume percent. In contrast, the CO ₂ lean / N ₂ rich stream 98 has a CO ₂ purity or concentration level of less than about 1, 2, 3, 4, 5, 10, 15, 20, 25, or 30 volume percent, and about It can have an N ₂ purity or concentration level greater than 70, 75, 80, 85, 90, 95, 96, 97, 98, or 99 volume percent. Intermediate concentration CO ₂ · N ₂ stream 97 may have a CO ₂ purity or concentration level and / or an N ₂ purity or concentration level of about 30-70, 35-65, 40-60, or 45-55 volume percent. it can. The above ranges are merely non-limiting examples, and the CO ₂ rich and N ₂ lean stream 96 and the CO ₂ lean and N ₂ rich stream 98 are for use with the EOR system 18 and other systems 84. It can be particularly suitable. However, any of these rich, lean, or intermediate concentrations of CO ₂ stream 95 can be used with EOR system 18 and other systems 84 alone or in various combinations. For example, EOR system 18 and other systems 84 (e.g., a pipeline 86, a storage tank 88 and carbon sequestration system 90,) each, one or more of CO ₂ rich · N ₂ lean stream 96,1 or more CO ₂ lean / N ₂ rich stream 98, one or more intermediate concentration CO ₂ / N ₂ stream 97, and one or more untreated exhaust 42 streams (ie, bypassed EG treatment system 82) be able to.

  The EG extraction system 80 extracts exhaust gas 42 at one or more extraction points 76 along the compressor section, combustor section, and / or turbine section, where the exhaust gas 42 is at a suitable temperature and pressure. It can be used in the EOR system 18 and other systems 84. The EG extraction system 80 and / or the EG processing system 82 can also circulate a fluid stream (eg, exhaust gas 42) to and from the EG processing system 54. For example, a portion of the exhaust gas 42 that passes through the EG processing system 54 can be extracted by the EG extraction system 80 for use in the EOR system 18 and other systems 84. In certain embodiments, the EG delivery system 78 and the EG processing system 54 can be independent or integrated with each other, and thus independent subsystems or common subsystems can be used. For example, the EG processing system 82 can be used by both the EG supply system 78 and the EG processing system 54. The exhaust gas 42 extracted from the EG processing system 54 may be a plurality, such as one or more gas processing stages in the EG processing system 54 and one or more additional gas processing stages in the subsequent EG processing system 82. Gas treatment stages.

  At each extraction point 76, the extracted exhaust gas 42 is substantially oxidant 68 and fuel 70 (eg, unburned fuel) due to substantially stoichiometric combustion and / or gas processing in the EG processing system 54. Or hydrocarbon) may not be present. Further, depending on the target system, the extracted exhaust gas 42 is further processed in the EG processing system 82 of the EG supply system 78, thereby causing any residual oxidant 68, fuel 70, or other undesirable combustion production. Things can be further reduced. For example, before or after processing of the EG processing system 82, the extracted exhaust gas 42 may contain less than 1, 2, 3, 4, or 5 volume percent oxidant (eg, oxygen), unburned fuel or hydrocarbons. (Eg, HC), nitrogen oxides (eg, NOx), carbon monoxide (CO), sulfur oxides (eg, SOx), hydrogen, and other incomplete combustion products. According to another embodiment, the extracted exhaust gas 42 is about 10, 20, 30, 40, 50, 60, 70, 80, 90, 100, 200, before or after processing of the EG processing system 82. Less than 300, 400, 500, 1000, 2000, 3000, 4000, or 5000 ppmv (parts per million) oxidant (eg, oxygen), unburned fuel or hydrocarbon (eg, HC), nitrogen oxides (Eg, NOx), carbon monoxide (CO), sulfur oxides (eg, SOx), hydrogen, and other incomplete combustion products. Therefore, the exhaust gas 42 is particularly suitable for use with the EOR system 18.

  The EGR operation of the turbine system 52 specifically enables exhaust gas extraction at multiple locations 76. For example, the compressor section of the system 52 can be used to compress the exhaust gas 60 without any oxidant 68 (ie, only compression of the exhaust gas 60), resulting in the oxidant 68 and the fuel 70. The exhaust gas 42 substantially free of oxygen can be extracted from the compressor section and / or the combustor section before the inflow of the exhaust gas. The extraction point 76 is located at an interstage port between adjacent compressor stages, at a port along the compressor exhaust casing, at a port along each combustor in the combustor section, or a combination thereof. be able to. In certain embodiments, the exhaust gas 60 may not be mixed with the oxidant 68 and the fuel 70 until it reaches the head end portion of each combustor and / or the fuel nozzle in the combustor section. In addition, one or more flow separators (eg, walls, dividers, baffles, or the like) can be used to isolate oxidant 68 and fuel 70 from extraction point 76. With these flow separators, the extraction points 76 can be placed directly along the walls of each combustor in the combustor section.

  As exhaust gas 60, oxidant 68, and fuel 70 flow through the head end portion (e.g., through the fuel nozzle) and into the combustor (e.g., combustion chamber) of each combustor, SEGR gas turbine system 52 is , Controlled to provide substantially stoichiometric combustion of the exhaust gas 60, the oxidant 68, and the fuel 70. For example, the system 52 can maintain an equivalence ratio of about 0.95 to about 1.05. As a result, the combustion products of the mixture of exhaust gas 60, oxidant 68, and fuel 70 in each combustor are substantially free of oxygen and unburned fuel. Accordingly, combustion products (or exhaust gases) can be extracted from the turbine section of the SEGR gas turbine system 52 for use as exhaust gas 42 that is sent to the EOR system 18. Along the turbine section, the extraction point 76 can be located in any turbine stage, such as an interstage port between adjacent turbine stages. Thus, using any of the extraction points 76 described above, the turbine-based service system 14 generates and extracts exhaust gas 42 and delivers it to the hydrocarbon generation system 12 (eg, EOR system 18) for underground reservoirs. Can be used to produce oil / gas 48 from 20.

  FIG. 2 is a non-limiting example of adjustment of the recirculated exhaust gas. Many challenges are associated with the use of recirculated exhaust gas (EGR) as an alternative to intake air for gas turbines or similar equipment. The EGR should be cooled to a temperature that will not damage the gas turbine rotor and other related components. In addition, EGR should be free of particulate matter as much as possible.

  In this non-limiting example, turbine exhaust gas 60 passes through HRSG 56 which reduces the temperature of the exhaust gas. Reactions due to the duct burner and the catalyst bed located within the HRSG 56 may contribute to soot and particulate matter formation in the exhaust gas 60. The HRSG 56 can be configured such that the exhaust gas 60 exits from the top of the rear end 56A of the HRSG 56. This configuration alleviates the problem of vapor accumulation in the region indicated by 56B. However, other configurations can be used with the technical progress of the present invention.

  Upon exiting the HRSG, the bypass stack damper 200 can send the turbine exhaust gas 60 to the atmosphere via the bypass stack 202. The sensor may be at or near the bypass stack damper 200. Such sensors can monitor temperature, water concentration, and / or particulate matter concentration and communicate information to one or more computers that control the system shown in FIGS. If the temperature, water concentration, and / or particulate matter concentration is outside the acceptable range, the computer can position the damper to send the exhaust gas to the atmosphere. Although temperature, water concentration, and / or particulate matter sensors are considered, these are merely illustrative and sensors that monitor other criteria can be used.

  If there is no reason to send the exhaust gas 60 to the atmosphere, the computer can position the bypass stack damper 200 to send the exhaust gas 60 to the recirculation piping and then to the soot cleaning / cooling section 204.

  Exhaust gas 60 may flow downward into the soot cleaning / cooling section 204. The soot washing / cooling section 204 includes a spray column 204a that sprays cold clean water downward. Pipeline 206 carries cold water from filtration system 230 (discussed below) and some more cold water for replenishment (source not shown). The cold purified water cools or prevents overheating of the exhaust gas 60 and cleans the exhaust gas 60 of particulate matter. The spray column 204a can be one or more jets, nozzles, or showerheads. Cold purified water is used as a heat transfer medium to cool the exhaust gas 60 in embodiments of the present invention, and other liquids or coolants can optionally be used as the heat transfer medium. Overheating prevention refers to the exhaust gas being cooled past its dew point.

  In a non-limiting embodiment, a co-current (e.g., exhaust gas and waste water that both flow in the same direction and downward) forms the basis of the design and removes particulate matter from the exhaust gas. Cool to remove. The container containing the soot cleaning / cooling section 204 may optionally further include an additional heat transfer medium that further cools the exhaust gas 60. Such additional heat transfer media include, but are not limited to, packaging trays and surface condensers.

  The soot cleaning / cooling section 204 also includes a water collector 208a. A water collector 208 a collects warm dirty water at the bottom of the soot wash / cool section 204. Gravity causes warm, dirty water to collect in the water collector 208a as a result of parallel flow. The warm dirty water can then be sent to the water filtration system 230 by collection of drains, pipes, valves, and / or pumps 210.

  Following the soot cleaning / cooling section 204, the exhaust gas flows into the detachment section 212. The withdrawal section 212 removes water / droplets that may have been carried over from the soot wash / cool section 204. The breakaway section 212 may include a single vane or a combination of vanes that entrain water / liquid and residual droplets and send them to the water collector 208b. In some configurations, the water collectors 208a and 208b can be in fluid communication with each other, or a common water collector can enable both the soot wash / cool section 204 and the disengagement section 212. Can do. Similarly, the water collected by the water collector 208b can be sent to a water filtration system.

  Following the detachment section 212, exhaust gas passes through the blower 214. The blower 214 can be a fan that pushes exhaust gas through the recirculation transfer pipe 216. Although the system of FIG. 2 shows one blower, the system can include multiple blowers positioned along the recirculation transfer piping 216 as needed.

  As it travels through recirculation transfer pipe 216, exhaust gas 60 then flows into flue gas condenser 218. The flue gas condenser 218 can be formed of a pipe having a bar that increases the heating surface and transfers heat to the cold purified water circulating through the cold purified water pipe 220. Alternatively, the flue gas condenser can be a dehumidifier that includes a condensing coil. The flue gas condenser 218 further cools and / or cools the exhaust gas to a predetermined temperature and / or humidity range suitable for entry to the compressor SEGR gas turbine system 52 through the use of appropriate temperature and / or humidity sensors. Can be controlled by computer to dehumidify.

  Following the flue gas condenser 218, the exhaust gas flows to the second separation section 222 by the water collector 208a. The second leaving section removes the condensate produced in the FGC. Optionally, another soot cleaning / cooling section can be used prior to the second release section 222.

  Following the second detachment section 222, the exhaust gas 60 flows to the protection stack damper 224 and the protection stack 226. The computer can use one or more sensors to monitor the exhaust gas quality or the condition of the SEGR gas turbine system 52 and control the damper to send the exhaust gas to the atmosphere as needed. The protective stack 226 downstream of the second separation section 222 allows for protection of the SEGR gas turbine system 52 if any aspect of the exhaust gas cannot provide the desired water content, particulate matter concentration, and temperature. . If the sensor and computer verify that the water content, particulate matter concentration, and temperature of the exhaust gas 60 are within acceptable limits, the computer sends the exhaust gas 60 to the inlet of the SEGR gas turbine system 52. The protective stack damper 224 can be controlled.

  The water filtration system 230 described above provides a means for purifying and recirculating the water used in the system of FIG. Warm dirty water collected by the water collectors 208 a and 208 b passes through the filter 232. Waste 234 is discarded. Warm clean water 236 is sent to a plate and frame heat exchanger 238. Warm clean water from the water collector 208 c is also sent to the plate and frame heat exchanger 238 via the pipe 240. The plate and frame heat exchanger outputs cold purified water to a pipe 206 that feeds the soot cleaning / cooling section 204 and a pipe 220 that cools the flue gas condenser 218. Elements 242 and 246 are an inlet from a coolant tank (not shown) and an outlet to the coolant tank, respectively.

  FIG. 3 is a flowchart of a non-limiting example of a process for adjusting the recirculated exhaust gas. Step 302 includes recirculating the exhaust gas through a conditioning loop that routes the exhaust gas from the heat recovery steam generator to the turbine compressor inlet. Step 304 includes using a computer to control the damper assembly to route exhaust gas to a bypass stack or exhaust gas conditioning device that provides atmospheric emission of exhaust gas. Step 306 includes cooling the exhaust gas using an exhaust gas conditioning device. Step 308 includes removing particulate matter from the exhaust gas using an exhaust gas conditioning device. Step 310 includes using the separation section to remove liquid introduced by the exhaust gas conditioning device from the exhaust gas. Step 312 includes cooling and dehumidifying the exhaust gas with a flue gas condenser. Step 314 uses the computer to send exhaust gas to a protective stack or turbine compressor inlet that provides atmospheric emissions of exhaust gas after the dehumidifier and before the turbine compressor inlet and downstream from the flue gas condenser. The step of controlling the damper assembly.

  FIG. 4 is a block diagram of a computer 400 that can be used to control the systems of FIGS. Central processing unit (CPU) 402 is coupled to system bus 404. The CPU 402 can be any general-purpose CPU, but other types of CPU 402 architecture (or other components of the exemplary system 400) are also described herein by the CPU 402 (and other components of the system 400). It can be used as long as it supports the operation described. Although only a single CPU 402 is shown in FIG. 4, those skilled in the art will recognize that additional CPUs may exist. Moreover, the computer 400 can include a networked multiprocessor computer that can include a hybrid parallel CPU / GPU system. The CPU 402 can execute various logical instructions in accordance with various teachings disclosed herein. For example, the CPU 402 can execute a machine level instruction for performing the process according to the described operation flow.

  Computer 400 may also include computer components such as non-transitory computer readable media. Examples of computer readable media include random access memory (RAM), which can be SRAM, DRAM, SDRAM, or the like. Computer 400 may also include additional non-transitory computer readable media such as read only memory (ROM) 408, which may be PROM, EPROM, EEPROM, or the like. RAM 406 and ROM 408 hold user and system data and programs, as is known in the art. The computer 400 may also include an input / output (I / O) adapter 410, a communication adapter 422, a user interface adapter 424, and a display adapter 418.

  The I / O adapter 410 connects additional non-transitory computer-readable media to the computer 400, such as storage devices 412 including, for example, hard drives, compact disk (CD) drives, floppy disk drives, tape drives, and the like. can do. The storage device can be used when the RAM 406 is insufficient for the memory requirements associated with storing data for operation of the present technology. The data storage of computer 400 can be used to store information and / or other data used or generated as disclosed herein. For example, the storage device 412 can be used to store configuration information or additional plug-ins in accordance with the present technology. Further, the user interface adapter 424 couples a user input device, such as a keyboard 428, a pointing device 426, and / or an output device to the computer 400. The display adapter 418 is driven by the CPU 402 and controls the display on the display device 420 to present information to the user, eg regarding available plug-ins.

  The architecture of the system 400 can be changed as needed. For example, any suitable processor-based device can be used including, but not limited to, personal computers, laptop computers, computer workstations, and multiprocessor servers. Moreover, the technical advances of the present invention can be implemented on application specific integrated circuits or very large integrated (VLSI) circuits. In fact, one skilled in the art can use any number of suitable hardware structures that can perform logical operations with the technical advancement of the present invention. The term “processing circuit” includes hardware processors (such as those found in the hardware devices described above), ASICs, and VLSI circuits. Input data to the computer 400 can include various plug-ins and library files. Input data can additionally include configuration information.

  FIG. 5 illustrates a non-limiting method for controlling the regulation of the recirculated gas. The steps of FIG. 5 are not necessarily performed in the order listed, and some steps can be performed concurrently with others.

  In step 502, sensors are used to measure temperature, particulate matter concentration, humidity, and / or instrument operational status. In step 504, the computer compares the sensor readings to pre-established criteria and bypasses the exhaust gas 60 through the bypass stack 202 to the atmosphere or to the exhaust gas 60 soot / cool section 204. The stack damper 200 is controlled. In step 506, the computer 400 controls a valve that allows cold clean water to be supplied to the spray column 204a, which can then push the exhaust gas through the detachment section 212. In step 508, the computer 400 causes the blower 214 to push exhaust gas through the recirculation line 216. In step 510, the computer 400 controls the flue gas condenser to cool and / or dehumidify the exhaust gas 60 before passing through the separation section 22. In step 512, the sensor is used to measure temperature, particulate matter concentration, humidity, and / or instrument operational status. In step 514, the computer compares the sensor readings to pre-established criteria and sends the exhaust gas 60 to the atmosphere via the protection stack 226 or sends the exhaust gas 60 to the SEGR gas turbine system 52. The damper 224 is controlled. In step 516, the computer 400, as shown in FIG. 2, recirculates the water and supplies it to the various components, along with any associated valves that control the flowing water in the various pipes of the system. To control.

  The description herein describes the present invention, including the best mode, and also includes any person skilled in the art making and using any device or system to perform any of the incorporated methods. The example is used to make it possible to implement. The patentable scope of the invention is defined by the claims, and may include other examples that occur to those skilled in the art. Such other embodiments are equivalent structures where they have structural elements that do not differ from the literal language of the claims, or where they differ substantially from the literal language of the claims. Where elements are included, they are intended to be within the scope of the claims.

12 Hydrocarbon generation system 14 Turbine-based service system 18 Crude oil secondary recovery (EOR) system 20 Underground reservoir 30 Drilling bore

Claims (13)

A system,
A recirculation exhaust gas adjustment loop that sends exhaust gas from the heat recovery steam generator to the turbine compressor inlet,
The recirculation exhaust gas adjustment loop includes:
An exhaust gas adjusting device that cools the exhaust gas to remove particulate matter from the exhaust gas;
A dehumidifier for dehumidifying the exhaust gas,
A system characterized by that. A separation section that is between the exhaust gas conditioning device and the dehumidifier and that removes liquid introduced by the exhaust gas conditioning device from the exhaust gas;
The system of claim 1. The exhaust gas conditioning device comprises a vertical direct contact condenser having a spray column that generates a co-flow of the exhaust gas and heat transfer liquid in the same downward direction.
The system according to claim 1 or 2. The heat recovery steam generator further comprising a heat recovery steam generator, wherein the input to the recirculation gas regulation loop is in fluid communication with a top back section of the heat recovery steam generator;
The system according to any one of claims 1 to 3. Before the exhaust gas regulating device,
A bypass stack that provides atmospheric emission of the exhaust gas;
A damper assembly for sending the exhaust gas to the bypass stack or the exhaust gas conditioning device.
The system according to any one of claims 1 to 4. The dehumidifier includes a flue gas condenser,
The flue gas condenser cools and dehumidifies the exhaust gas;
The system according to any one of claims 1 to 5. A protective stack that provides atmospheric release of the exhaust gas downstream from the dehumidifier and before the turbine compressor inlet;
A damper assembly for sending the exhaust gas to the protective stack or the turbine compressor inlet and downstream from the flue gas condenser;
The system according to any one of claims 1 to 6. Recirculating the exhaust gas through a regulation loop that sends the exhaust gas from the heat recovery steam generator to the turbine compressor inlet;
The recycling step comprises:
Cooling the exhaust gas using an exhaust gas regulating device;
Removing particulate matter from the exhaust gas using the exhaust gas conditioning device;
Dehumidifying the exhaust gas using a dehumidifier,
A method characterized by that. Further comprising removing liquid introduced by the exhaust gas conditioning device from the exhaust gas using a separation section between the exhaust gas conditioning device and the dehumidifier.
The method of claim 8. The exhaust gas conditioning device includes a vertical direct contact condenser having a spray column;
Said method comprises
Generating a co-flow of the exhaust gas and heat transfer liquid discharged from the spray column in the same downward direction,
10. A method according to claim 8 or 9. Using a computer to control the damper assembly to route the exhaust gas to or to a bypass stack that provides atmospheric release of the exhaust gas before the exhaust gas reaches the exhaust gas conditioning device Further including
11. A method according to any one of claims 8 to 10. The dehumidifying step comprises using a flue gas condenser;
12. A method according to any one of claims 8 to 11. Using a computer to a protective stack that provides atmospheric release of the exhaust gas downstream from the dehumidifier and before the turbine compressor inlet and downstream from the flue gas condenser, or at the turbine compressor inlet Further comprising controlling the damper assembly to deliver the exhaust gas;
The method of claim 13.

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