JP2014515074A - System and method for controlling waste heat for CO2 capture - Google Patents

Abstract

The present invention relates to a system and method for providing steam to a gas recovery unit (130) in response to changes in steam flow to the power generation unit (119) and / or power generated by the power generation unit (119). The gas recovery unit (130) may be part of the thermoelectric generator unit (100) and may be an amine-based CO ₂ recovery unit that includes two or more regenerative heat exchanger columns (153).

Description

This application is a U.S. provisional application 61/469919, filed March 31, 2011, entitled “System and Method for Controlling Waste Heat for CO ₂ Capture”. Claim 35 benefits under Code 119 (e) of the 35th Code, the disclosure content of which is incorporated herein by reference in its entirety.

This application is related to this application in March 31, 2011, entitled “System and Method for Controlling Waste Heat for CO ₂ Capture”, assigned to the assignee of the present invention. It relates to US patent application Ser. No. 61 / 469,915, attorney docket number W09 / 078-0 (27849-0011), filed simultaneously and incorporated herein by reference in its entirety.

The present invention relates generally to thermal power plants. In particular, the present invention relates to a method and apparatus for integrating a process control system for capture of carbon dioxide by power plant steam to minimize waste heat.

BACKGROUND Fossil fuels and natural gas power plants conventionally use steam turbines and other machinery to convert heat to electricity. Combustion of these fuels produces a flue gas stream containing an acid gas containing carbon dioxide CO ₂ , nitrogen oxides NOx, and sulfur oxides SOx. Efforts have been made to reduce acid gas emissions from these power plants, particularly to reduce greenhouse gas emissions, including CO ₂ . For example, CO ₂ capture systems have been incorporated into these power plants. Many advances have been made in this regard, which leads to the partial or complete separation of CO ₂ generated during the combustion of fossil fuels from the combustion gases. More recently, there has been interest in aqueous absorption and stripping processes that use aqueous amines to remove acid gas contaminants from combustion gas streams.

  Gas absorption is a process in which soluble components of a gas mixture are dissolved in a liquid. The contact between the gas and the liquid can be countercurrent or cocurrent, and countercurrent contact is most commonly used. Stripping is substantially the opposite of absorption because it involves a change in the volatile components from the liquid mixture to the gas. In a typical carbon dioxide removal process, absorption is used to remove carbon dioxide from the combustion gas, and stripping is subsequently used to regenerate the solvent and capture the carbon dioxide contained in the solvent. Once the carbon dioxide is removed from the combustion gases and other gases, the carbon dioxide can be captured and compressed for use in many applications including sequestration, methanol production, and third oil recovery.

  In order to regenerate the absorbent solution, the concentrated solvent drawn from the bottom of the absorption column is introduced into the upper half from the stripping, and the concentrated solvent is maintained at or near boiling point under pressure. Is done. The heat needed to maintain the higher temperature is provided by reboiling the absorbent solution contained in the stripping column, which requires energy and increases the overall operating cost.

  Thus, there is a need to provide a reboiler with a cost-effective and operatively efficient energy source to regenerate a loaded aqueous amine stream.

SUMMARY OF THE INVENTION An object of the present invention is to provide a system and method for efficiently providing heat to an acid gas absorption / stripping process integrated with a steam power generation system.

  Another subject of the present invention is the overall arrangement by various arrangements of turbines and steam tapping (extraction points) from water and / or steam cycle locations to provide energy for the acid gas capture system. To optimize the performance of a typical power plant.

  Another object of the present invention is to provide various turbine stages to provide energy for an acid gas capture system that can be designed into a new power system design or can be retrofitted to an existing power system design. And providing a special arrangement of steam tapping (extraction points) from the water and / or steam cycle position.

  Another problem of the present disclosure is to provide a process control system for integrating steam power generation load and energy generation for acid gas capture.

  Thus, depending on the operating and design parameters of known techniques for acid gas capture, the problem of the present invention is to reduce energy.

  Furthermore, the subject of the present invention is the environmental, health and / or economic improvement of reduced emissions of chemicals used in such technology for acid gas absorption.

  In one aspect, a boiler unit that generates steam, a power generation unit that includes at least one power generation turbine that receives steam from the boiler unit, a gas recovery unit that includes two or more regenerative heat exchanger columns, and two steams Disclosed is a plant having a secondary steam source that provides each of one or more regenerative heat exchanger columns in various proportions.

  In another aspect, steam is provided to the secondary steam source from either the boiler unit or the power generation unit, the steam is discharged from the secondary steam source, and the steam discharged from the secondary steam source is supplied to the two gas recovery units. Disclosed is a method for providing steam to a gas recovery unit that includes providing the regenerative heat exchanger column in various proportions.

  Reference will now be made to the drawings which are exemplary embodiments, in which like elements are designated with like numerals.

FIG. 3 shows a schematic simplified process diagram of a plant according to one embodiment of the disclosure. FIG. 4 shows a schematic simplified process diagram of a plant according to another embodiment of the disclosure. FIG. 4 shows a schematic simplified process diagram of a plant according to another embodiment of the disclosure. FIG. 4 shows a schematic simplified process diagram of a plant according to another embodiment of the disclosure. FIG. 4 shows a schematic simplified process diagram of a plant according to another embodiment of the disclosure. FIG. 4 shows a schematic simplified process diagram of a plant according to another embodiment of the disclosure. FIG. 4 shows a schematic simplified process diagram of a plant according to another embodiment of the disclosure. FIG. 4 shows a schematic simplified process diagram of a plant according to another embodiment of the disclosure. FIG. 4 shows a schematic simplified process diagram of a plant according to another embodiment of the disclosure.

DETAILED DESCRIPTION Specific embodiments of systems and processes for utilizing power generation steam to provide energy to an acid gas recovery unit according to the present invention are described below with reference to the drawings.

  FIG. 1 shows a schematic simplified process diagram of a plant 100 according to one embodiment of the disclosure. In one embodiment, the thermal system 100 may be a thermal power plant. In another embodiment, the plant 100 may be a plant or facility comprising a combustion facility that generates carbon dioxide-containing flue gas and at least one steam unit. The steam unit may be a steam turbine power generation unit.

  As seen in FIG. 1, the plant 100 includes a primary steam source 110, a power generation unit 119, and a gas recovery unit 130. In this exemplary embodiment, primary steam source 110 is a steam boiler unit. The steam boiler unit 110 may include one or more steam boilers that generate steam from fossil fuel. The fuel may be coal, peat, biomass, syngas / fuel, natural gas or other carbon fuel source that generates flue gas containing gas contaminants such as acid gases when burned.

  The power generation unit 119 includes a primary steam consumption unit 120 and a power generation unit (generator) 125. In the exemplary embodiment, primary steam consumer 120 is one or more steam turbines. One or more steam turbines 120 are coupled to the power generation unit 125, provide mechanical energy to the generator 125, and generate electricity 125A. Electricity may be provided to a power grid (not shown). In the exemplary embodiment, one or more steam turbines 120 include a high pressure (HP) turbine 121, an intermediate pressure (IP) turbine 122, and a low pressure (LP) turbine 123. In another embodiment, the one or more steam turbines 120 may include any number of turbine combinations at the same or different operating pressures.

  As further seen in FIG. 1, the power generation unit 119 further includes a secondary steam consumption unit 150. In the exemplary embodiment, secondary steam consumer 150 is an auxiliary steam turbine 124. The auxiliary steam turbine 124 may be a back pressure turbine. The auxiliary steam turbine 124 is connected to an auxiliary generator 152. The auxiliary generator 152 generates electricity 152A, which may be provided to a power grid, a plant local power network, or other local energy supply (not shown). The amount of energy provided to the power grid may be increased or decreased depending on the power grid load demand. The grid load request may provide a setpoint to a speed controller (not shown) of the auxiliary steam turbine 124. In one embodiment, the setpoint may have an override based on the pressure of the auxiliary turbine 124 exhaust steam.

The gas recovery unit 130 may be an acid gas capture and recovery unit. The gas recovery unit 130 includes a CO ₂ absorption unit 130a and a CO ₂ regeneration unit 130b. In one embodiment, the gas recovery unit 130 may be an amine based scrubbing unit. In one embodiment, the gas recovery unit 130 may be a state-of-the-art amine process for CO ₂ capture. In one embodiment, the state-of-the-art amine process may be a double matrix system with a matrix stripping configuration.

The CO ₂ absorption unit 130 a includes a CO ₂ absorber (absorber) 231. The CO ₂ regenerative heat exchange unit 130b includes two or more regenerative heat exchanger columns 153. Each regenerative heat exchanger column of the two or more regenerative heat exchanger columns 153 includes two or more reboilers 140. In one embodiment, one or more of the regenerative heat exchanger columns may have more than one reboiler. An arrangement of two or more regenerative heat exchanger columns 153 may be referred to as a matrix stripping configuration. In this exemplary embodiment, the two or more regenerative heat exchanger columns 153 include a high pressure (HP) regenerative heat exchanger column 154 and associated first reboiler 141, and a low pressure (LP) regenerative heat. An exchanger column 155 and an associated second reboiler 142.

The absorber 231 is provided with a gas stream containing CO ₂ from the steam boiler unit 110 through the supply line 231a. The gas stream may be a flue gas stream. In one embodiment, the flue gas may be processed by a flue gas desulfurization unit (not shown) and / or a cooling unit (not shown) before being provided to the absorber 231. In the absorber 231 the flue gas is brought into contact with a solvent solution, which removes CO ₂ from the flue gas by absorption. The solvent solution may be an amine based solvent solution. The flue gas stream from which CO ₂ has been removed is discharged from the absorber 231 through the discharge line 231b. The absorber 231 may further include a fluid wash cycle 232 that may include a fluid wash pump 233 and a fluid wash cooler 234 to eliminate any solvent carry-out.

In order to perform regenerative heat exchange of the solvent solution, the concentrated CO ₂ solvent solution drawn from the bottom of the absorber 231 is introduced into the upper half of each of the two or more regenerative heat exchanger columns 153 and concentrated. The solvent is maintained at a temperature at which CO ₂ is boiled off under pressure in each column. The heat necessary to maintain the boiling point is provided by one or more reboilers associated with each regenerative heat exchanger column. The reboiling process is performed by indirect heat exchange between a portion of the solution being regenerated heat exchange and a hot fluid at an appropriate temperature. In the course of the regenerative heat exchange, the carbon dioxide contained in the concentrated solvent to be regenerated heat exchange, maintained at the boiling point, is released and stripped by the vapor of the absorbent solution. Vapor containing stripped CO ₂ exits the top of the regenerative heat exchanger column, passed through a condenser system, the condenser system exits the regenerative heat exchanger column with gaseous CO ₂ The liquid phase resulting from the condensation of the absorbent solution vapor is returned to the regenerative heat exchanger column. At the bottom of the regenerative heat exchanger column, a high temperature regenerative heat exchanged absorbent solution, also called a dilute solvent solution, is removed and recycled.

In this exemplary embodiment, the HP regenerative heat exchanger column 154 and the LP regenerative heat exchanger column 155 are coupled by a fluid interconnect system 235 that circulates a solvent solution for CO ₂ absorption / desorption. ₂ Interconnected with absorber 231. The fluid interconnect system includes a lean cooler 236, a semi-lean cooler 237, an LP concentrated solution pump 238, an HP concentrated solution pump 239, a semi-lean / rich heat exchanger 240, a semi-lean solution pump 241, It has a lean / rich heat exchanger 242, a lean solution pump 243, and various lines and supplies as shown.

CO ₂ is concentrated, is discharged from the CO ₂ absorber, from CO ₂ absorber 231, a solvent solution such as an amine solution, the CO ₂ rich solvent other words, HP regenerative heat exchanger column 154 and LP regenerative It is provided to a heat exchanger column 155 where CO ₂ is stripped from the solvent in this LP regenerative heat exchanger column 155. CO ₂ is exhausted from HP regenerative heat exchanger column 154 and LP regenerative heat exchanger column 155 via exhaust lines 244 and 245, respectively, which are combined to form exhaust line 246. Discharge line 246 is fed to the CO ₂ cooler, in the CO ₂ condenser, residual moisture is removed from the CO ₂ stream. The CO ₂ product stream is discharged from the gas recovery unit 130 through the CO ₂ product discharge line 248.

  As further seen in FIG. 1, steam boiler unit 110 provides high pressure steam to high pressure turbine 121 through high pressure steam line 126. The pressure of the high pressure steam may be about 270 bar to 300 bar and the temperature may be about 600 ° C to 700 ° C. The flow of high pressure steam provided to the high pressure turbine 121 is proportional to the overall plant load. The overall plant load is the total amount of power generated by the plant 100. The high pressure steam is withdrawn from the high pressure steam line 126 through an auxiliary high pressure (HP) steam line 126A and supplied to an auxiliary turbine 124 connected to an auxiliary generator 152 to generate electricity.

  The reduced pressure steam is discharged from the auxiliary turbine 124 and provided to the gas recovery unit 130 through the auxiliary steam line 124a. The reduced pressure steam may be provided at a pressure of about 5 bar to about 20 bar and a temperature of less than about 300 ° C.

The reduced pressure steam provided to the gas recovery unit 130 is provided to the first reboiler 141 and the second reboiler 142 through the first and second auxiliary steam lines 124a ₂ and 124a ₁ , respectively. The The reduced pressure steam is provided to each of the two or more regenerative heat exchanger columns 153 simultaneously in different proportions. Providing steam at different rates includes providing steam at different pressures, temperatures and / or flow rates. Providing steam to each of the two or more regenerative heat exchanger columns 153 in different proportions increases the controllability of each regenerative heat exchanger column to increase the controllability of the two or more regenerative heat exchanger columns 153 Each may be utilized to provide a different amount of energy. Steam may be regenerated two or more by controlling the quality of the steam by using one or more steam controllers, such as but not limited to valves, expansion devices, throttling devices, and any combination thereof. Are provided in different proportions to the heat exchanger column 153. In order to optimize the gas capture and capture system 130 for CO ₂ capture and energy, the regenerative heat exchanger 153 functions in synchrony, but the CO ₂ stripping rate and column pressure are different. The first auxiliary steam line 124a ₂ and the second auxiliary steam line 124a ₁ provide steam to the first and second reboilers 141, 142 in different proportions, And the second reboilers 141, 142 are provided with different amounts of energy, thereby increasing the controllability of each reboiler, which in turn results in the HP regenerative heat exchanger column 154 and the LP regenerative heat exchanger. Each increases the controllability of the column 155. By increasing the control of the HP regenerative heat exchanger column 154 and the LP regenerative heat exchanger column 155 by controlling the ratio of steam to the first and second reboilers 141 and 142, respectively, Power generation is reduced to a minimum, or in other words results in a minimum penalty for power generation of the plant 100. Thus, thermal duty delivery is provided independently and is flexible to maintain system optimality. In another embodiment, the reduced pressure steam is provided to two or more reboilers 140 through two or more auxiliary steam lines.

  According to the systems and methods provided, the steam flow to the auxiliary turbine 124 is proportional to the power generated by the plant 100. In other words, as more power is generated by the plant 100, more available steam is provided to the auxiliary turbine 124, and more steam is available to the acid gas recovery unit 130. This provides a coarse program control operation when the plant load changes.

  In another embodiment, the ratio of steam to the auxiliary turbine 124 and steam provided to the HP turbine 121 may be calculated and maintained at a constant value. The calculated ratio may provide a set point for speed control of the HP turbine to minimize pressure loss by constricting flow to the auxiliary turbine. In another embodiment, the top stage column temperature of the low pressure (LP) regenerative heat exchanger column 155 may be used to set the reboiler duty in the second reboiler 142.

Steam flow from the auxiliary turbine 124 to the two or more reboilers 140 may be used to control the regenerative heat exchange of CO _{2 in} the HP and LP regenerative heat exchanger columns 154, 155. This is because the steam flow from the auxiliary turbine 124 to the first and second reboilers 141, 142 may be utilized to control the temperature of the HP and LP regenerative heat exchanger columns 154, 155. It is.

  As shown in FIG. 1, the location from which steam is withdrawn is generally indicated in the steam line. However, FIG. 1 and subsequent figures in this disclosure are intended to include extraction into steam at a line or component location that provides a steam source of the desired steam quality. For example, steam may be extracted from heat exchangers, condensers, bypasses, turbine structures, or other steam passage components that provide the desired quality of steam.

  FIG. 2 shows a schematic simplified process diagram of a plant 200 according to another embodiment of the disclosure. The primary components of the plant 200 are the same as those illustrated and described above with reference to the plant 100 of FIG. However, in this embodiment, steam to the auxiliary turbine 124 is withdrawn from the IP steam line 210 between the HP turbine 121 and the IP turbine 122 and through the auxiliary IP steam line 210A. 124. In one embodiment, the steam in the IP steam line 210 is between about 50 bar and about 60 bar. In another embodiment, the steam in the IP steam line 210 is between about 58 bar and about 60 bar. In another embodiment, the steam in IP steam line 210 is between about 450 ° C. and 620 ° C. In another embodiment, the steam in IP steam line 210 is between about 480 ° C and 520 ° C. In yet another embodiment, the temperature in the IP vapor line is about 500 ° C.

  FIG. 3 shows a schematic simplified process diagram of a plant 300 according to another embodiment of the disclosure. The primary components of the plant 300 are the same as those illustrated and described above with reference to the plant 100 of FIG. However, in this embodiment, steam to the auxiliary turbine 124 is withdrawn from the LP steam line 310 between the IP turbine 122 and the LP turbine 123.

  In one embodiment, the steam in the LP steam line 310 is from about 3 bar to about 7 bar. In another embodiment, the steam in LP steam line 310 is between about 4 bar and about 6 bar. In another embodiment, the steam in LP line 310 is about 5 bar. In another embodiment, the steam in the LP supply line 310 is between about 300 ° C and 400 ° C. In another embodiment, the steam in LP steam line 310 is between about 340 ° C and 400 ° C. In yet another embodiment, the temperature in the LP vapor line is about 400 ° C.

  FIG. 4 shows a schematic simplified process diagram of a plant 400 according to another embodiment of the disclosure. The primary components of the plant 400 are the same as those illustrated and described above with reference to the plant 100 of FIG. However, in this embodiment, the auxiliary turbine 124 is provided with steam from the auxiliary boiler 410. Because the auxiliary boiler 410 is provided, flue gas flow and heat input from the steam boiler unit 110 to the acid gas recovery unit 130 are decoupled. In one embodiment, when the load on the main boiler changes, the load on the auxiliary boiler 410 is changed. The load on the auxiliary boiler 410 may be varied to maintain the ratio of steam generated by the auxiliary boiler 410 and the steam boiler unit 110. In another embodiment, the load on the auxiliary boiler 410 is varied by changing the fuel supply to the auxiliary boiler 410 based on changes in the fuel supply to the steam boiler unit 110.

  FIG. 5 shows a schematic simplified process diagram of a plant 500 according to another embodiment of the disclosure. The primary components of the plant 500 are the same as those illustrated and described above with reference to the plant 100 of FIG. In this embodiment, the secondary steam consumption unit 524 is a steam mixer. The steam mixer 524 is a steam saturator. In another embodiment, the secondary steam consumer 524 is a steam device that receives one or more steam supplies of the same or various steam qualities and produces a resulting steam discharge of the desired steam quality. It's okay. The steam saturator 524 receives a steam supply of the same or similar steam quality and combines the various steam supplies to produce a steam discharge of the desired steam quality. In one embodiment, the steam discharge is a saturated steam discharge. The steam supply can be any combination of steam, saturated or supersaturated steam, and water. Steam is supplied to the steam saturator 524 from various steam taps in the steam boiler unit 110 and the power generation unit 119.

  The boiler unit 110 has a primary boiler loop 110a and a secondary boiler loop 110b. The primary boiler loop 110 a receives water through the primary supply line 111 a and discharges steam through the high-pressure steam line 126. The secondary boiler loop 110 b receives water through the secondary supply line 111 b and discharges steam through the secondary steam line 516. In one embodiment, the steam discharged through secondary steam line 516 is high pressure steam.

  Steam saturator 524 receives steam from secondary steam line 516. In one embodiment, the steam from the secondary steam line 516 is provided to the steam saturator 524 at a pressure of about 250 bar to about 320 bar and a temperature of about 580 ° C. to about 700 ° C. In another embodiment, secondary steam line 516 provides steam to steam saturator 524 at a pressure of about 280 bar to about 300 bar and a temperature of about 600 ° C. to about 670 ° C.

  As seen in FIG. 5, steam saturator 524 further includes HP steam from HP steam line 126 through auxiliary HP steam line 126A, HP turbine 121 and IP turbine through auxiliary IP steam line 210A. IP steam from IP steam supply line 210 to 122, LP steam from LP steam line 310 between IP turbine 122 and LP turbine 123 through auxiliary LP steam line 310A, auxiliary exhaust steam line Steam from power generation unit 119 is provided, including exhaust steam from exhaust steam line 520 that exhausts steam from LP turbine 123 through 520A.

  In one embodiment, the steam from secondary steam line 516 is between about 500 degrees Celsius and about 600 degrees Celsius. In another embodiment, the steam from secondary steam line 516 is between about 510 degrees Celsius and about 565 degrees Celsius. In another embodiment, the steam from secondary steam line 516 is from about 150 bar to about 175 bar. In another embodiment, the steam from secondary steam line 516 is from about 160 bar to about 165 bar.

  Steam is provided to and combined with the steam saturator 524 in a manner that generates the desired steam flow to the acid gas recovery unit 130 through the auxiliary steam line 124a. In one embodiment, the reduced pressure steam may be provided at a pressure of about 5 bar to about 20 bar and a temperature of less than about 300 ° C. The steam whose pressure has been reduced is provided to the first reboiler 141 and the second reboiler 142. In another embodiment, the reduced pressure steam is provided to one or more reboilers. Depending on the demand of the power generation unit 119, one or more of the auxiliary steam lines and the secondary steam line 516 may be used or shut off.

  FIG. 6 shows a schematic simplified process diagram of a plant 600 according to another embodiment of the disclosure. The primary components of the plant 600 are the same as those illustrated and described above with reference to the plant 300 of FIG. However, in this embodiment, the flow controller 610 is replaced with an auxiliary turbine 124 (FIG. 3) as the secondary steam source 150. A flow controller 610 is provided in the auxiliary LP steam line 310A. The flow control device 610 may be a throttle valve. The flow controller 610 may be selected, controlled, and / or adjusted to adjust the amount of steam provided to the auxiliary turbine 124. In another embodiment, the flow control device 610 may be replaced with the auxiliary turbine 124 of FIG. 2 and may be provided in the auxiliary IP steam line 210A. In yet another embodiment, the flow control device 610 may be replaced with the auxiliary turbine 124 of FIG. 1 and may be provided in the auxiliary HP steam line 126A.

  FIG. 7 shows a schematic simplified process diagram of a plant 700 according to another embodiment of the disclosure. The primary components of the plant 700 are the same as those illustrated and described above with reference to the plant 100 of FIG. However, in this embodiment, the steam line to the auxiliary turbine 124 is an auxiliary combined steam line 762A instead of the auxiliary HP steam line 126A (FIG. 1). The auxiliary steam line 762A receives steam from the auxiliary HP steam line 126a, the auxiliary IP steam line 210a, and the auxiliary LP steam line 310a.

  FIG. 8 shows a schematic simplified process diagram of a plant 800 according to another embodiment of the disclosure. The primary components of the plant 800 are the same as those illustrated and described above with reference to the plant 200 of FIG. However, in this embodiment, the auxiliary steam line 124a provides steam only to the LP regenerative heat exchanger column 155, not the HP regenerative heat exchanger column 154. Instead, steam from the LP steam line 310 is provided to the second auxiliary steam turbine 824 through the auxiliary LP steam line 310A. The second auxiliary steam turbine 824 is coupled to the second auxiliary generator 852 for generating electricity 852A. In another embodiment, one or more second auxiliary steam turbines 824 may be used. Steam is exhausted from the second auxiliary steam turbine 824 through a second auxiliary steam line 824A that provides steam to the HP regenerative heat exchanger column 154. In another embodiment, steam from the HP steam line 126 is provided to the auxiliary turbine 124 through the auxiliary HP steam line 126A. In yet another embodiment, steam from the HP steam line 126 and the auxiliary LP steam line 210 is provided to the auxiliary turbine 124.

  FIG. 9 shows a schematic simplified process diagram of a plant 900 according to another embodiment of the disclosure. The primary components of the plant 900 are the same as those illustrated and described above with reference to the plant 300 of FIG. However, in this embodiment, the auxiliary steam line 124a provides steam only to the LP regenerative heat exchanger column 155, not the HP regenerative heat exchanger column 154. Instead, at least some of the steam from the auxiliary steam line 124a is bypassed to the second auxiliary steam turbine 924 through the auxiliary steam bypass line 910A. In another embodiment, one or more second auxiliary steam turbines 924 may be used. The second auxiliary steam turbine 924 is coupled to a second auxiliary generator 952 to generate electricity 952A. Steam is exhausted from the second auxiliary steam turbine 924 through a second auxiliary steam line 924a that provides steam to the HP regenerative heat exchanger column 154. In another embodiment, steam from one or any combination of HP steam line 126, IP steam line 210 and LP steam line 310 may be provided to auxiliary turbine 124.

  Although the invention has been described with reference to various exemplary embodiments, various modifications may be made without departing from the scope of the invention, and equivalents may be substituted for elements in the embodiments. It will be appreciated. In addition, many modifications may be made to adapt a particular situation or material to the disclosure of the invention without departing from the basic scope thereof. Accordingly, the invention is not limited to the specific embodiments disclosed as the best mode contemplated for carrying out the invention, but the invention may include all embodiments falling within the scope of the appended claims. Is intended.

Claims (21)

A plant (100),
A boiler unit (110) for generating steam;
A power generation unit (119) including at least one power generation turbine (120) that receives the steam from the boiler unit (110);
A gas recovery unit (130) comprising two or more regenerative heat exchanger columns (153);
A plant (100) comprising a secondary steam source (124a) that provides steam to each of the two or more regenerative heat exchanger columns (153) in various proportions.   The plant (100) of any preceding claim, wherein the gas recovery unit (130) comprises an amine-based scrubbing process.   The plant (100) of any preceding claim, wherein the secondary steam source (124a) includes an auxiliary turbine (124).   The plant (100) of any preceding claim, wherein the secondary steam source (124a) includes a flow controller (610).   The plant (100) of claim 1, wherein the power generation unit (119) includes a high pressure turbine (121), and high pressure steam (126a) is provided to the secondary steam source from a high pressure steam supply to the high pressure turbine. ).   The power generation unit (119) includes a high pressure turbine (121) and an intermediate pressure turbine (122), and steam is supplied to the high pressure turbine (126a) and an intermediate pressure to the intermediate pressure turbine (122). The plant (100) of claim 1, wherein the plant (100) is provided to the secondary steam source (124a) from any one of the steam supplies.   The power generation unit (119) includes a high-pressure turbine (121), an intermediate-pressure turbine (122), and a low-pressure turbine (123). Steam is supplied to the high-pressure turbine (121), the intermediate-pressure turbine ( 122) to the secondary steam source (124a) from any one of a medium pressure steam supply to 122), a low pressure steam supply to the low pressure turbine (123), and any combination thereof. Item 1. The plant (100) according to item 1.   The plant (400) of any preceding claim, wherein the secondary steam source (124a) includes an auxiliary boiler (410) and an auxiliary turbine (124).   The secondary steam source (124a) includes a steam saturator (524), and the steam saturator (524) is a secondary from a high pressure supply line, a medium pressure supply line, a low pressure supply line, and a boiler unit (110). The plant (500) of claim 1, receiving steam from any one of a supply line and any combination thereof.   The plant (800) of claim 1, wherein the secondary steam source (124a) includes an auxiliary turbine (124) and a second auxiliary turbine (824).   The plant (800) of claim 10, wherein the second auxiliary turbine (824) receives steam from the exhaust steam of the auxiliary turbine (824). Providing steam from either the boiler unit (110) or the power generation unit (119) to the secondary steam source (124a);
Discharging steam from the secondary steam source (124a);
Providing the steam discharged from the secondary steam source to the two or more regenerative heat exchanger columns (153) of the gas recovery unit in various proportions, characterized in that How to provide.   The method of claim 12, wherein the steam is provided from the boiler unit (110) to a secondary steam source (124a).   The method of claim 12, wherein the steam is provided from the power generation unit (119) to a secondary steam source (124a).   The method of claim 12, wherein the secondary steam source (124a) comprises at least one auxiliary turbine (124).   The method of claim 12, wherein the secondary steam source (124a) comprises a steam saturator (524).   The method of claim 12, further comprising providing steam to the power generation unit (119) to generate electricity.   The method of claim 12, wherein the gas recovery unit (130) separates acidic gas from gas vapor. The gas recovery unit (130) is a CO ₂ recovery unit, The method of claim 12, wherein.   The method of claim 12, wherein the gas recovery unit (130) comprises two or more reboilers.   The method of claim 12, wherein the steam flow provided to the gas recovery unit (130) is varied in response to changes in power generated by the power generation unit (119).

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