SYSTEM AND METHOD FOR CONTROLLING WASTE HEAT FOR CO2 CAPTURE

Abstract

The present invention relates to systems and methods for controlling the flow of steam provided to a gas recovery unit 130 based on changes to steam flow to and/or power generated by a power generation unit 119. The gas recovery unit 130 may be part of a thermal power generation unit and may be an amine based CO2 recovery unit including two or more regenerator columns 153.

Description

The present application claims the benefit under 35 U.S.C. §119(e) of Provisional Patent Application Ser. No. 61/469,915 entitled A SYSTEM AND METHOD FOR CONTROLLING WASTE HEAT FOR CO₂ CAPTURE filed Mar. 31, 2011, the disclosure of which is incorporated herein by reference in its entirety.

CROSS-REFERENCE TO RELATED APPLICATIONS

This Application is related to U.S. Patent Application No. 61/469,919, Attorney Docket No. WO9/056-0(27849-0014), filed contemporaneously with this Application on Mar. 31, 2011, entitled “A SYSTEM AND METHOD FOR CONTROLLING WASTE HEAT FOR CO₂ CAPTURE” assigned to the assignee of the present invention and which is incorporated herein by reference in its entirety.

FIELD OF THE INVENTION

The present invention generally relates to a thermal power plant. The present invention more particularly relates to methods and systems to integrate process control schemes for the capture of carbon dioxide with power plant steam to minimize waste heat.

BACKGROUND

Fossil fuel and natural gas power stations conventially use steam turbines and other machines to convert heat into electricity. The combustion of these fuels produce a flue gas stream that includes acid gases including carbon dioxide CO₂, nitrogen oxides NO_x and sulfur oxides SO_x. Efforts have been made to reduce the emission of acid gases from these power stations, and in particular, to reduce the emission of greenhouse gases including CO₂. As such, CO₂ capture systems have been integrated into these power stations. Numerous advances have been made in this respect, leading to the CO₂ generated during the combustion of fossil fuels being partly to completely separated from the combustion gases. Recently, there has been interest in aqueous absorption and stripping processes using 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. Gas/liquid contact can be counter-current or co-current, with counter-current contact being most commonly practiced. Stripping is essentially the inverse of absorption, as it involves the transfer of volatile components from a liquid mixture to a gas. In a typical carbon dioxide removal process, absorption is used to remove carbon dioxide from a combustion gas, and stripping is subsequently used to regenerate the solvent and capture the carbon dioxide contained in the solvent. Once carbon dioxide is removed from combustion gases and other gases, it can be captured and compressed for use in a number of applications, including sequestration, production of methanol, and tertiary oil recovery.

To effect the regeneration of the absorbent solution, the rich solvent drawn off from the bottom of the absorption column is introduced into the upper half of a stripping column, and the rich solvent is maintained at an elevated temperature at or near its boiling point under pressure. The heat necessary for maintaining the elevated temperature is furnished by reboiling the absorbent solution contained in the stripping column, which requires energy and thus increases overall operational costs.

Hence, there exists a need to provide a cost effective and operationally efficient energy source to the reboilers to regenerate the loaded aqueous amine stream.

SUMMARY OF THE INVENTION

An objective 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 objective of the present invention is to optimize overall power generation plant performance by the use of special arrangements of steam tappings (extraction points) from different turbine stages and water and/or steam cycle locations to provide energy for acid gas capture systems.

Another objective of the present invention is to provide special arrangements of steam tappings (extraction points) from different turbine stages and water and/or steam cycle locations to provide energy for acid gas capture systems that can be designed into new or retrofitted into existing power generation system designs.

Another objective of the present disclosure is to provide process control schemes to integrate steam power generation load and energy production for acid gas capture.

Accordingly, and depending on the operational and design parameters of a known technology for capture of acidic gases, an objective of the present invention may reside in the reduction of energy usage.

Furthermore, an objective of the present invention may reside in the environmental, health and/or economical improvements of reduced emission of chemicals used in such a technology for acid gas absorption.

In one aspect, a plant is disclosed that includes a boiler unit that produces steam, a power generation unit including at least one power generation turbine that receives the steam from the boiler unit, a gas recovery unit comprising two or more regenerator columns, a secondary source of steam to the two or more regenerator columns, and a controller configured to regulate the flow rate of steam to two or more regenerator columns. The controller includes a control strategy that determines the flow rate of steam from the source of steam to each regenerator of the two or more regenerator columns based on a plant load parameter.

In another aspect, a method for providing steam to a gas recovery unit is disclosed that includes controlling the flow of steam to two or more regenerator columns of the gas recovery unit based on a load parameter for a power generation unit.

BRIEF DESCRIPTION OF THE DRAWINGS

Referring now to the figures, which are exemplary embodiments, and wherein the like elements are numbered alike.

FIG. 1 illustrates a schematic, simplified process diagram of a plant according to an embodiment of the disclosure.

FIG. 2 illustrates a schematic, simplified process diagram of a steam turbine installation according to another embodiment of the disclosure.

FIG. 3 illustrates a schematic, simplified process diagram of a steam turbine installation according to another embodiment of the disclosure.

FIG. 4 illustrates a schematic, simplified process diagram of a steam turbine installation according to another embodiment of the disclosure.

FIG. 5 illustrates a schematic, simplified process diagram of a steam turbine installation according to another embodiment of the disclosure.

DETAILED DESCRIPTION

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

FIG. 1 illustrates a schematic, simplified process diagram of a plant 100 according to an 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 including a combustion facility generating a carbon dioxide containing flue gas and at least one steam unit. The steam unit may be a steam turbine power generation unit.

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

The power generation unit 119 includes a primary consumer of steam 120 and a power generation unit 125. In this exemplary embodiment, the primary consumer of steam 120 is one or more steam turbines. The one or more steam turbines 120 are coupled to the power generation unit 125 to provide mechanical energy to the power generator 125 to generate electricity 125A. The electricity may be provided to an electrical power grid (not shown). In this exemplary embodiment, the one or more steam turbines 120 includes 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 a combination of any number of turbines of similar or varying operation pressure(s).

As can be further seen in FIG. 1, the power generation unit 119 further includes a secondary consumer of steam 124. In this exemplary embodiment, the secondary consumer of steam 124 is an auxiliary steam turbine. The auxiliary steam turbine 124 may be a back pressure turbine. The auxiliary steam turbine 124 is coupled to an auxiliary generator 152. The auxiliary generator 152 generates electricity 152A that may be provided to an electrical power grid, a plant electrical power grid, or other local energy supply (not shown). The amount of energy provided to the electrical grid may be increased or decreased depending on the electrical grid load requirement. The electrical grid load requirement may provide a setpoint to a speed control (not shown) of the auxiliary steam turbine 124. In one embodiment, the setpoint may have an override based on the pressure of the exhaust steam of the auxiliary turbine 124. In another embodiment, the pressure of the exhaust of the auxiliary turbine 124 is provided to maintain and/or bias one or more of controllers of the power generation unit 119 and an gas recovery unit 130. The controllers may use proportional integral differential (PID) control and/or model predictive control or other control method and/or steam flow devices to maintain the quality of steam going to the acid gas recovery unit 130 via the auxiliary steam line 124a.

The gas recovery unit 130 may be an acid gas capture and recovery unit. The gas recovery unit 130 includes a CO₂ absorption unit 130a and a CO₂ 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 an advanced amine process for CO₂ capture. In one embodiment, the advanced amine process may be a double matrix scheme including a matrix stripping configuration.

The CO₂ absorption unit 130a includes a CO₂ absorber (absorber) 231 The CO₂ regeneration unit 130b includes two or more regenerator columns 153. Each regenerator column of the two or more regenerator columns 153 includes at least one reboiler 140. In one embodiment, one or more of the regenerator columns may have two or more reboilers. The arrangement of two or more regenerator columns 153 may be referred to as a matrix stripping configuration. In this exemplary embodiment, the two or more regenerator columns 153 includes a high pressure (HP) regenerator column 154 and associated first reboiler 141 and a low pressure (LP) regenerator column 155 and associated second reboiler 142.

The absorber 231 is provided a flue gas stream containing CO₂ from the steam boiler unit 110 via a feed line 231a. In one embodiment, the flue gas may be treated by a flue gas desulfurization unit (not shown) and/or a cooling unit (not shown) before being provided to the CO₂ absorber 231. In the CO₂ absorber 231, flue gas is contacted with a solvent solution that removes CO₂ from the flue gas by absorption. The solvent solution may be an amine-based solvent solution. The flue gas stream, having CO₂ removed, is discharged from the CO₂ absorber 231 via a discharge line 231b. The CO₂ 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 carryover.

To effect the regeneration of the solvent solution, the rich solvent solution drawn off from the bottom of the absorber 231 is introduced into the upper half of each of the two or more regenerator columns 153, and the rich solvent is maintained at a temperature at which CO₂ boils off under pressure in each column. The heat necessary for maintaining the boiling point is furnished by one or more reboilers associated with each regenerator column. The reboiling process is effectuated by indirect heat exchange between part of the solution to be regenerated and a hot fluid at appropriate temperature. In the course of regeneration, the carbon dioxide contained in the rich solvent to be regenerated maintained at its boiling point is released and stripped by the vapors of the absorbent solution. Vapor containing the stripped CO₂ emerges at the top of the regenerator column and is passed through a condenser system which returns to the regenerator column the liquid phase resulting from the condensation of the vapors of the absorbent solution that pass out of the regenerator column with the gaseous CO₂. At the bottom of the regenerator column, the hot regenerated absorbent solution, also called the lean solvent solution, is drawn off and recycled.

In this exemplary embodiment, the HP regenerator column 154 and the LP regenerator column 155 are interconnected with the CO₂ absorber 231 by a fluid interconnection system 235 that circulates solvent solution for CO₂ absorption/desorption. The fluid interconnection system includes a lean cooler 236, a semi-lean cooler 237, a LP rich solution pump 238, a HP rich solution pump 239, a semi-lean/rich heat exchanger 240, a semi-lean solution pump 241, a lean/rich heat exchanger 242, a lean solution pump 243 and various lines and feeds as shown.

The solvent solution, such as an amine solution, from the CO₂ absorber 231, which is discharged from the CO₂ absorber rich in CO₂, or in other words, CO₂ rich solvent, is provided to the HP regenerator column 154 and the LP regenerator column 155 where CO₂ is stripped from the solvent. CO₂ is discharged from the HP regenerator column 154 and the LP regenerator column 155 via discharge lines 244 and 245, respectively, which combine for form a discharge line 246. Discharge line 246 feeds a CO₂ cooler 247, where residual moisture is removed from the CO₂ stream. A CO₂ product stream is discharged from the gas recovery unit 130 via CO₂ product discharge line 248.

As can be further seen in FIG. 1, the steam boiler unit 110 provides high pressure steam to the high pressure turbine 121 via a high pressure steam line 126. High pressure steam may be at a pressure between about 270 bar and 300 bar and temperature between about 600° C. and 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. High pressure steam is tapped from the high pressure steam line 126 via auxiliary high pressure (HP) steam line 126A and fed to the auxiliary turbine 124, which is coupled to a auxiliary power generator 152 to produce electricity.

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

The reduced pressure steam provided to the gas recovery unit 130 is provided to the two or more regenerator columns 153. The reduced pressure steam is provided to each of the two or more regenerator columns 153 simultaneously at different rates. Providing steam at different rates may include providing steam at different pressure, temperature and/or flow volume. Providing steam to each of the two or more regenerator columns 153 at different rates may be used to provided a different amount of energy to the each of the two or more regenerator columns 153 to improve the controllability of each regenerator column.

In this exemplary embodiment, the reduced pressure steam is provided to the first reboiler 141 and the second reboiler 142, of the HP regenerator column 154 and LP regenerator column 155, respectively, via auxiliary steam line 124a. In another embodiment, the reduced pressure steam is provided to one or more reboilers. Steam is provided to the first and second reboilers 141, 142 simultaneously at different rates. Providing steam the first and second reboilers 141, 142 at different rates may be used to provided a different amount of energy to the first and second reboilers 141, 142 to improve the controllability of each reboiler, which subsequently improves the controllability of the HP regenerator column 154 and the LP regenerator column 155, respectively. By improving the control of the HP regenerator column 154 and the LP regenerator column 155 by controlling the rate of steam to the first and second reboilers 141, 142, respectively, the power production of the power generation unit 119 is minimally reduced, or in other words, incurs the minimum penalty of the power production of the plant 100.

A first ratio calculation block 131 receives steam flow data from the high pressure steam line 126 providing steam to the high pressure turbine 121 and from the auxiliary HP steam line 126A providing steam to the auxiliary turbine 124. The first ratio calculation block 131 generates a signal from the steam flow data signals and sends the signal to a first controller 181 disposed on the auxiliary steam line 124a. The first controller 181 regulates the amount of high pressure steam provided to the secondary turbine 124 by regulating the amount of resistance to discharge steam flow from the secondary turbine, and regulates the amount of steam flow from the auxiliary turbine 124 to the gas recovery unit 130. The first controller 181 may be a proportional integral differential (PID) control valve, a model predictive control (MPC) valve, or other control or valve using another control law to regulate and/or adjust the amount of steam flowing through the auxiliary steam line 124a. The first controller 181 receives a first set point (R*) that is an operator set value to regulate the flow of steam provided to the auxiliary turbine 124 based on the amount of steam flow to the high pressure turbine 121. The first set point R* is determined by the load on steam boiler unit 110 and the gas recovery unit 130 i.e. the total amount of steam produced, the total amount CO₂ produced and the desired percent CO₂ capture. In another embodiment, one or more controllers may be disposed on the auxiliary steam line 124 and/or the auxiliary steam line 124a to control the amount of steam provided to the auxiliary steam turbine 124 and/or the gas recovery unit 130.

The first ratio calculation block 131 and the first controller 181 may control the amount of steam flow provided to the auxiliary turbine 124 proportional to the amount of high pressure steam provided to the at least one steam turbine 120. The amount of steam provided to the at least one steam turbine is proportional to the electricity 125 produced by the power generation unit 125, which is proportional to the amount of acid gas produced by the steam boiler unit 110. In other words, the first ratio calculation block 131 and first controller 181 may regulate the flow of steam to and/or from the auxiliary turbine 124 in response to changes in the power demand or plant load as measured by the flow of high pressure steam.

A second ratio calculation block 133 may further control steam flow from the auxiliary turbine 124 to the gas recovery unit 130 in response to changes in electricity 125A generated by the power generation unit 119. The second ratio calculation block 133 receives inputs from the electricity 125A generated by the power generation unit 125 and the auxiliary high pressure steam line 126A providing steam to the auxiliary steam turbine 124. In response to changes in electricity 125A generated by the power generation unit 119, the second ratio calculation block 133 provides a control signal to a second controller 134, the signal based on the ratio of the power generated by the power generation unit to the steam flow to the auxiliary turbine 124.

The second controller 134 compares this signal to a second set point R**, and adjusts or regulates the amount of steam flowing through the auxiliary steam line 124a to the gas recovery unit 130. The second controller 134 may be a PID control valve, an MPC valve, or other control or valve using another control law to regulate and/or adjust the amount of steam flowing through the auxiliary steam line 124a. The second set point R** is and operator input value determined by the load on steam boiler unit 110 and the gas recovery unit 130 i.e. the total amount of steam produced, the total amount CO₂ produced and the desired percent CO₂ capture. In this manner, the second ratio calculation block 133 and second controller provide an additional flow control to further regulate steam flow to the gas recovery unit 130. In another embodiment, one or more ratio calculation blocks and/or controllers using PID, MPC or other control laws may be used to regulate flow between the various components.

According to embodiments provided in the system and methods of the present invention, steam flow to the auxiliary turbine 124 is controlled to be proportional to the power generated by the plant 100. In other words, more power generated by the plant 100 results in more steam available to be provided to the auxiliary turbine 124, and more steam available to the acid gas recovery unit 130. This provides a coarse anticipatory control action as 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 to a fixed value using one or more controllers using various control laws such as, but not limited to PID and MPC control. In one embodiment, the controllers may be ratio PID controllers. In an embodiment, the calculated ratio of steam to the auxiliary turbine 124 and steam provided to the HP turbine 121 may provide a setpoint to the speed control of the HP turbine to minimize the pressure losses due to throttling the flow to the auxiliary turbine, as it may be important to maintain the pressure of the steam generated. There might be some loss in pressure due to throttling of the outlet valves of the turbine. In another embodiment, an exhaust pressure signal from the auxiliary steam line 124a may be used to provide a feedback signal to the first ratio calculation block 131 in order to maintain the pressure of the exhaust steam of the auxiliary turbine 124.

In another embodiment, one or more additional controllers, using a control method such as, but not limited to PID and MPC control laws, may provide further control of the amount of steam provided to the gas recovery unit 130. In one embodiment, the one or more additional controllers may use temperature and/or composition measurements taken from various component process streams within the plant 100 to further control of the amount of steam provided to the gas recovery unit 130. For example, a top stage column temperature of the low pressure (LP) regenerative column 155 may be used to set the reboiler duty in the second reboiler 142. Based on the reboiler duty, another controller, such as, but not limited to a ratio PID controller, may be used to maintain the ratio of reboiler duties of the first and second reboilers 141, 142. In such a manner, the solvent is maintained at or below a critical temperature so that over-stripping and under-stripping of CO₂ from the solvent is avoided. This maintains the optimal CO₂ lean loading of the solvent that is re-circulated to the absorber 231, whereby the overall efficiency of the process is maintained.

The control of steam from the auxiliary turbine 124 to the at least one reboiler 140 may be used to control the regeneration of CO₂ in the HP and LP regenerator columns 154, 155 since the flow of steam from the auxiliary turbine 124 to first and second reboilers 141, 142 may be used to control the temperature of the HP and LP regenerator columns 154, 155.

As shown in FIG. 1, the location where steam is tapped is generally shown on a steam line. However, FIG. 1 and the later figures in this disclosure are intended to include tapping into steam at a line or component position that provides a source of steam of a desired steam quality. For example, steam may be tapped from a heat exchanger, condenser, bypass, turbine structure or other steam passing component that provides steam of the desired quality.

FIG. 2 illustrates 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 shown and described above with reference to the plant 100 of FIG. 1. However, in this embodiment, steam from to the auxiliary turbine 124 is tapped from the IP steam line 210 between the HP turbine 121 and the IP turbine 122 and provided to the auxiliary turbine 124 via auxiliary IP steam line 210A. 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 the IP steam line 210 is between about 450° C. and 620° C. In another embodiment, the steam in the IP steam line is between about 480° C. and 520° C. In yet another embodiment, the pressure in the IP steam line is about 500° C.

FIG. 3 illustrates 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 shown and described above with reference to the plant 100 of FIG. 1. However, in this embodiment, steam from to the auxiliary turbine 124 is tapped 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 between about 3 bar and about 7 bar. In another embodiment, the steam in the LP steam line 310 is between about 4 bar and about 6 bar. In another embodiment, the steam in the LP line 310 is about 5 bar. In another embodiment, the steam in the LP feed line 310 is between about 300° C. and 400° C. In another embodiment, the steam in the LP steam line is between about 340° C. and 400° C. In yet another embodiment, the pressure in the LP steam line is about 400° C.

FIG. 4 illustrates 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 shown and described above with reference to the plant 100 of FIG. 1. However, in this embodiment, the auxiliary turbine 124 is provided steam from an auxiliary boiler 410. Since an auxiliary boiler 410 is provided, the flue gas flow and the heat input 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 can be changed by a ratio PID controller that maintains 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 changed by changing the fuel feed to the auxiliary boiler 410 based on a change in the fuel feed to the steam boiler unit 110.

In this exemplary embodiment, a secondary ratio calculation block 433 calculates the ratio of the flow of fuel to the auxiliary boiler 410 via auxiliary boiler fuel feed line 450 and fuel flow to the steam boiler unit 110 via steam boiler unit fuel feed line 452. The secondary ratio calculation block 433 provides the ratio of fuel flow of the auxiliary boiler 410 and the steam boiler unit 110 to a PID controller 455, which compares the ratio to a provided fuel ratio setpoint R′ and provides flow control commands to a flow device 460 in the auxiliary boiler fuel feed line.

FIG. 5 illustrates 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 shown and described above with reference to the plant 100 of FIG. 1. In this embodiment, a secondary consumer of steam 524 is a steam mixer. The steam mixer 524 may be a steam saturator. In another embodiment, the secondary consumer of steam 524 may be a steam device that receives one or more steam feeds of the same or various steam quality and produces a resultant steam discharge of a desired steam quality. The steam mixer 524 receives steam feeds of the same or similar steam quality and combines the various steam feeds to generate a steam discharge of a desired steam quality. In one embodiment, the steam discharge is a saturated steam discharge. The steam feeds may be any combination of steam, saturated or supersaturated steam, and water. The steam mixer 524 is provided with steam from the steam boiler unit 110 and from various steam taps in the power generation unit 119.

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

The steam mixer 524 receives steam from the secondary steam line 516. In one embodiment, steam from the secondary steam line 516 is provided to the steam mixer 524 at a pressure of between about 250 bar to about 320 bar and at a temperature of between about 580° C. and about 700° C. In another embodiment, the secondary steam line 516 provides steam to the steam mixer 510 at a pressure of between about 280 bar to about 300 bar and at a temperature of between about 600° C. and about 670° C.

As can be seen in FIG. 5, the steam mixer 524 is further provided with steam from the power generation unit 119 including one or more of the following sources: HP steam from the HP steam line 126 via an auxiliary HP steam line 126A; IP steam from the IP steam feed line 210 between the HP turbine 121 and the IP turbine 122 via an auxiliary IP steam line 210A; LP steam from the LP steam line 310 between the IP turbine 122 and the LP turbine 123 via an auxiliary LP steam line 310a; and discharge steam form a discharge steam line 520 discharging steam from the LP turbine 123 via an auxiliary discharge steam line 520A.

In one embodiment, the steam from the secondary steam line 516 is between about 500° C. and about 600° C. In another embodiment, the steam from the secondary steam line 516 is between about 510° C. and about 565° C. In another embodiment, the steam from the secondary steam line 516 is between about 150 bar and about 175 bar. In another embodiment, the steam from the secondary steam line is between about 160 bar and about 165 bar. In one embodiment, the steam from the auxiliary discharge steam line is between about 0.1 bar and about 0.2 bar.

The plant 500 further includes a ratio calculation block 530 that receives flow data from the secondary steam discharge line 516 and HP steam line 126. The ratio calculation block 530 provides a control signal to a controller 581 in response to the load on the power generation unit 119. The controller 581 compares this to a provided setpoint R″ and sends a control signal to a control unit 540. The controller 581 may be a proportional integral differential (PID) control valve, a model predictive control (MPC) valve, or other control or valve using another control law to regulate and/or adjust the amount of steam flowing through the secondary steam discharge line 516. The set point R* is determined by the load on steam boiler unit 110 and the gas recovery unit 130 i.e. the total amount of steam produced, the total amount CO₂ produced and the desired percent CO₂ capture.

The control unit 540 may be a calculator box. The control unit 540 provides control signals to one or more flow control devices 555 on the steam lines providing steam to the steam mixer 524 to regulate and combine the steam flows in a manner that produces a desired steam flow to the acid gas recovery unit 130 via auxiliary steam line 524a. In one embodiment, the reduced pressure steam may be provided at a pressure of between about 5 bar and about 20 bar and at a temperature of less than about 300° C. The reduced pressure steam is provided to first reboiler 141 and second reboiler 142. In another embodiment, the reduced pressure steam is provided to one or more reboilers. The controller 530 may control the various steam flows by combining one or more of the auxiliary steam lines to the steam saturator 524. In other words, depending on the power generation unit 119 demands, one or more of the auxiliary steam lines, as well as the secondary steam line 516 may be utilized or shut off.

While the invention has been described with reference to various exemplary embodiments, it will be understood by those skilled in the art that various changes may be made and equivalents may be substituted for elements thereof without departing from the scope of the invention. In addition, many modifications may be made to adapt a particular situation or material to the teachings of the invention without departing from the essential scope thereof. Therefore, it is intended that the invention not be limited to the particular embodiment disclosed as the best mode contemplated for carrying out this invention, but that the invention will include all embodiments falling within the scope of the appended claims.

Claims

1. A plant, comprising:

a boiler unit that produces steam;

a power generation unit comprising at least one power generation turbine that receives the steam from the boiler unit;

a gas recovery unit comprising two or more regenerator columns;

a secondary source of steam to the two or more regenerator columns; and

a controller configured to regulate the flow rate of steam to two or more regenerator columns;

wherein the controller comprises a control strategy that determines the flow rate of steam from the source of steam to each regenerator of the two or more regenerator columns based on a plant load parameter.

2. The plant of claim 1, further comprising a second controller configured to further regulate the flow of steam from the source of steam to at least one regenerator column of the two or more regenerator columns, the second controller comprising a control strategy the determines the flow rate of steam to the gas recovery unit based on total power generation of the power generation unit.

3. The plant of claim 1, wherein the secondary source of steam comprises an auxiliary turbine.

4. The plant of claim 1, wherein the power generation unit comprises a high pressure turbine, and high pressure steam is provided to the secondary source of steam from a high pressure steam feed to the high pressure turbine.

5. The plant of claim 1, wherein the power generation unit comprises a high pressure turbine and an intermediate pressure turbine, and intermediate pressure steam is provided to the secondary source of steam from an intermediate pressure steam feed from the high pressure turbine to the intermediate pressure turbine.

6. The plant of claim 1, wherein the power generation unit comprises a high pressure turbine, an intermediate pressure turbine, and a low pressure turbine, and low pressure steam is provided to the secondary source of steam from a low pressure steam feed from the intermediate pressure turbine to the low pressure turbine.

7. The plant of claim 1, wherein the gas recovery unit comprises an amine based scrubbing process.

8. The plant of claim 1, wherein the secondary source of steam comprises an auxiliary boiler and an auxiliary turbine.

9. The plant of claim 8, further comprising a second controller configured to further regulate the rate of fuel to the auxiliary boiler in response to changes in the rate of fuel supplied to the boiler unit.

10. The plant of claim 1, wherein the secondary source of steam comprises a steam saturator.

11. The plant of claim 10, wherein the boiler unit comprises a secondary boiler loop that provides a flow of steam to the steam saturator.

12. The plant of claim 10, wherein the power generation unit comprises a high pressure turbine, an intermediate pressure turbine, and a low pressure turbine, and the steam saturator receives one or more steam feeds from a steam feed group consisting of an intermediate pressure steam from an intermediate pressure steam feed from the high pressure turbine to the intermediate pressure turbine, a low pressure steam from a low pressure steam feed from the intermediate pressure turbine to the low pressure turbine, and a discharge pressure steam from a discharge steam line from the low pressure turbine.

13. The plant of claim 10, wherein the controller control strategy that determines the flow rate of steam from the steam saturator to least one reboiler of the gas recovery unit is based on a plant load parameter by controlling the flow of steam from the boiler unit and the power generation unit to the steam saturator.

14. A method for providing steam to a gas recovery unit, comprising:

controlling the flow of steam to two or more regenerator columns of the gas recovery unit based on a load parameter for a power generation unit.

15. The method of claim 14, wherein the flow of steam to the gas recovery unit is controlled by comparing the ratio of the rate of steam to the power generation unit to a rate of steam to a secondary source of steam to at least one reboiler of the gas recovery unit.

16. The method of claim 14, wherein the flow of steam to the gas recovery unit is controlled by controlling a flow of steam to an auxiliary turbine in response to changes in steam flow to the power generation unit.

17. The method of claim 14, wherein the flow of steam to the gas recovery unit is controlled by controlling a rate of fuel provided to a secondary source of steam that provides steam to the gas recovery unit based on the rate of fuel supplied to the power generation unit.

18. The method of claim 14, wherein the flow of steam to the gas recovery unit is provided by controlling a flow of steam from a boiler unit to a steam saturator and from the power generation unit to the steam saturator.

19. The method of claim 14, wherein the flow of steam to the gas recovery unit is controlled in response to changes in power generated by the power generation unit.

20. The method of claim 14, wherein the control of steam to the gas recovery unit controls the temperature of two or more regenerator columns in the gas recovery unit.