TW201307669A - System and method for controlling waste heat for CO2 capture - Google Patents

Abstract

The present invention relates to systems and methods for providing steam 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 part of a thermal power generation unit 100 and may be an amine based CO2 recovery unit including two or more regenerator columns 153.

Description

System and method for controlling waste heat for carbon dioxide extraction

The present invention generally relates to a thermal power plant. More specifically, the present invention relates to a method and system for integrating a program control scheme for extracting carbon dioxide from a power plant steam to minimize waste heat.

This application is based on 35 USC § 119(e) and claims "A SYSTEM AND METHOD FOR CONTROLLING WASTE HEAT FOR CO ₂ CAPTURE", which was filed on March 31, 2011. The disclosure of the Provisional Patent Application No. 61/469,919, the disclosure of which is incorporated herein in its entirety by reference.

[Reciprocal Reference of Related Applications]

This application relates to a US patent entitled "A SYSTEM AND METHOD FOR CONTROLLING WASTE HEAT FOR CO ₂ CAPTURE", which was filed at the same time as this application on March 31, 2011. The application is hereby incorporated by reference in its entirety in its entirety by reference in its entirety in its entirety in the the the the the the the the the the the

Fossil fuel and natural gas power plants conventionally use steam turbines and other machines to convert heat into electricity. These include combusting fuel to produce exhaust gas stream of acid gas, the acid gas including carbon dioxide CO _2, sulfur oxides and nitrogen oxides NO _x SO _x. Efforts have been made to reduce the acid gas emissions from such power stations, and detail, including to reduce emissions of CO ₂ greenhouse gases. Thus, the CO ₂ extraction system has been integrated into such power plants. Progress has been made in this regard numerous, resulting in CO ₂ with the combustion gas during the combustion of fossil fuels to generate completely separated from the separation portion. Recently, attention has been paid to water absorption and stripping procedures for the removal of sour gas contaminants from aqueous combustion streams using aqueous amines.

Gas absorption is the process of dissolving the soluble components of the gas mixture in a liquid. The gas/liquid contact can be a countercurrent or cocurrent flow, with countercurrent contact being most often practiced. Stripping is essentially a reverse process of absorption because it involves the transfer of volatile components from the liquid mixture to the gas. In a typical carbon dioxide removal procedure, carbon dioxide is removed from the combustion gases using a sorbent, and then the solvent is regenerated using stripping and the carbon dioxide contained in the solvent is extracted. Once carbon dioxide has been removed from combustion gases and other gases, carbon dioxide can be extracted and compressed for use in several applications including storage, methanol generation, and tertiary petroleum recovery.

To effect regeneration of the absorbent solution, a rich solvent depleted from the bottom of the absorption column is introduced into the upper portion of the stripper and the rich solvent is maintained at a high temperature near its boiling or boiling point under pressure. This requires energy and thus increases overall operating costs by reboiling the absorbent solution contained in the stripper to provide the heat necessary to maintain high temperatures.

Therefore, there is a need to provide cost effective and operationally efficient energy sources to the reboiler to regenerate the loaded aqueous amine stream.

It is an object of the present invention 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 object of the invention is to use water from different turbine stages and/or The special configuration of the steam tap (snap point) at the steam cycle location provides energy for the sour gas extraction system to optimize overall plant performance.

Another object of the present invention is to provide a special configuration of steam taps (suck points) from different turbine stages and water and/or steam cycle locations to provide energy for the sour gas extraction system, such acid gas capture The system can be redesigned or trimmed into the design of existing power generation systems.

Another object of the present invention is to provide a program control scheme to integrate steam generation loads with energy production for sour gas extraction.

Thus, and depending on the operation and design parameters of known techniques for extracting sour gas, the object of the invention may be to reduce energy.

Furthermore, the object of the present invention may be to reduce the environmental, health and/or economical improvement of emissions of chemicals used in this technique for acid gas absorption.

In one aspect, a power plant is disclosed, the power plant comprising: a boiler unit that generates steam; a power generation unit that includes at least one power generating turbine that receives the steam from the boiler unit; and a gas recovery unit that includes two or More than two regeneration columns; and a secondary steam source that provides steam to each of the two or more regeneration columns at different rates.

In another aspect, a method for providing steam to a gas recovery unit is disclosed, the method comprising: providing steam from a boiler unit or a power generation unit to a secondary steam source; and discharging steam from the secondary steam source; The steam discharged from the secondary steam source is supplied to the two or more regeneration columns of the gas recovery unit at different rates.

Reference is now made to the drawings of the exemplary embodiments, and wherein similar elements are similar Land number.

Specific embodiments of systems and procedures for providing energy to an acid gas recovery unit utilizing power generation steam in accordance with the present invention are described below with reference to the drawings.

FIG. 1 illustrates a schematic simplified schematic diagram of a power plant 100 in accordance with an embodiment of the present invention. In one embodiment, the thermal system 100 can be a thermal power plant. In another embodiment, power plant 100 can be a power plant or facility that includes a combustion facility that produces carbon dioxide-containing exhaust gases and at least one steam unit. The steam unit can be a steam turbine power generating unit.

As can be seen in FIG. 1, the power 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 a fossil fuel. The fuel may be coal, peat, biomass fuel, synthetic gas/fuel, natural gas, or other carbon fuel source that produces exhaust gas containing gaseous pollutants such as sour gas when burned.

The power generation unit 119 includes a main steam consuming device 120 and a power generation unit 125. In this exemplary embodiment, primary steam consuming device 120 is one or more steam turbines. One or more steam turbines 120 are coupled to the power generation unit 125 to provide mechanical energy to the generator 125 to produce electricity 125A. Electricity can be supplied to the power grid (not shown). In this exemplary embodiment, one or more steam turbines 120 include a high pressure (HP) turbine 121, a medium pressure (IP) turbine 122, and a low pressure (LP) turbine 123. In another embodiment, one or more steam turbines 120 may include any combination of turbines having similar or varying operating pressures.

As can be further seen in Figure 1, power generation unit 119 further includes secondary Steam consuming device 124. In this exemplary embodiment, the secondary steam consuming device 124 is an auxiliary steam turbine. The auxiliary steam turbine 124 can be a back pressure turbine. The auxiliary steam turbine 124 is coupled to the auxiliary generator 152. Auxiliary generator 152 produces electricity 152A that can be provided to a power grid, a power plant local power grid, or other local energy source (not shown). The amount of energy provided to the power grid can be increased or decreased depending on the power grid load requirements. The power grid load demand can provide a set point for the speed control of the auxiliary steam turbine 124 (not shown). In one embodiment, the set point may be changed based on the pressure of the waste steam of the auxiliary turbine 124.

The gas recovery unit 130 can be an acid gas extraction 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 can be an amine based wash unit. In one embodiment, the gas recovery unit 130 can be used for CO ₂ capture process of higher amines. In one embodiment, the higher amine process can be a dual matrix solution that includes a matrix stripping configuration.

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

A gas stream containing CO ₂ is supplied from the steam boiler unit 110 to the absorber 231 via a feed line 231a. The gas stream can be an exhaust stream. In one embodiment, the exhaust gases may be treated by an exhaust gas desulfurization unit (not shown) and/or a cooling unit (not shown) prior to being provided to the absorber 231. In the absorber 231, the exhaust gas is brought into contact with the solvent solution to remove CO ₂ from the exhaust gas by absorption. The solvent solution can be an amine based solvent solution. The CO ₂ removed exhaust stream is discharged from the absorber 231 via a discharge line 231b. The absorber 231 can further include a fluid flush cycle 232 to eliminate any solvent retentate, which can include a fluid flush pump 233 and a fluid flush cooler 234.

In order to achieve regeneration of the solvent solution, the CO ₂ -rich solvent solution taken out from the bottom of the absorber 231 is introduced into the upper half of each of the two or more regeneration columns 153, and in each column The rich solvent is maintained at a temperature at which the CO _{2 is} boiling under pressure. The heat necessary to maintain the boiling point is provided by one or more reboilers associated with each regeneration column. The reboiling procedure is accomplished by indirect heat exchange between the portion of the solution to be regenerated and the hot fluid at the appropriate temperature. During the regeneration process, the vapor contained in the rich solvent to be regenerated, which is maintained at the boiling point, is released by the vapor of the absorbent solution and stripped. The vapor containing stripped CO ₂ is present at the top of the regeneration column and passes through a condenser system that returns the liquid phase resulting from the condensation of the vapor of the absorbent solution (with gaseous CO ₂ ) from the regeneration column To the regeneration tower. At the bottom of the regeneration column, a thermally regenerated absorbent solution (also known as a lean solvent solution) is pumped and recycled.

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

The CO ₂ from the rich (or in other words, the CO ₂ rich solvent) of the CO ₂ absorber is discharged solvent solution (such as amine) from the CO ₂ absorber 231 is supplied to the regeneration column 154 HP and LP regeneration tower 155 Where the CO ₂ is stripped from the solution. The CO _{2 is} discharged from the HP regeneration column 154 and the LP regeneration column 155 via the discharge lines 244 and 245, respectively, and the discharge lines 244 and 245 are combined to form a discharge line 246. Discharge line 246 feeding coolant CO _2, CO ₂ stream which is removed from the residual moisture. From the exhaust gas recovery unit 248 via line 130 product CO ₂ is discharged liquid CO ₂ product stream.

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

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

The reduced pressure supplied to the gas recovery unit 130 is supplied to the first reboiler 141 and the second reboiler 142 via the first auxiliary steam line 124a ₂ and the second auxiliary steam line 124a ₁ , respectively. Simultaneously and at different rates, the reduced pressure steam is provided to each of the two or more regeneration columns 153. Providing steam at different rates can include providing steam at different pressures, temperatures, and/or flow volumes. Providing steam at different rates to each of the two or more regeneration columns 153 can be used to provide different amounts of energy to each of the two or more regeneration columns 153 to improve each regeneration tower Controllability. Steam is supplied to two or more regeneration towers 153 at different rates by controlling the quality of the steam using one or more steam control devices such as, but not limited to, valves, expansion devices, throttling devices, and any combination thereof. . The regenerator 153 synchronization function, however, CO ₂ stripping column at different rates and pressure to the gas capture and recovery system 130 on CO ₂ capture and energy optimization. The first auxiliary steam line 124a ₂ and the second auxiliary steam line 124a ₁ will provide different amounts of energy to the first reboiler 141 and the second reboiler 142 to improve the controllability of each reboiler at different rates. The steam is supplied to the first reboiler 141 and the second reboiler 142, which subsequently improve the controllability of the HP regeneration column 154 and the LP regeneration column 155, respectively. The control of the HP regeneration column 154 and the LP regeneration column 155 is improved by controlling the rates of steam to the first reboiler 141 and the second reboiler 142, respectively, to minimize power generation by the power generation unit 119, or in other words, Incurring the minimum loss of electricity generated by the power plant 100. Therefore, heat load transfer is provided independently and flexibly to maintain system optimality. In another embodiment, the reduced pressure steam is provided to two or more reboilers 140 via 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 power plant 100. In other words, more power generated by the power plant 100 results in more steam being available to the auxiliary turbine 124 and more steam may be used by the acid gas recovery unit 130. This provides a rough expected control action when the power plant load changes.

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

The steam flow from the auxiliary turbine 124 to the two or more reboilers 140 can be used to control the regeneration of CO ₂ in the HP regeneration column 154 and the LP regeneration column 155, since the self-assisting turbine 124 to the first reboiler The flow of steam from 141 and second reboiler 142 can be used to control the temperature of HP regeneration column 154 and LP regeneration column 155.

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

Figure 2 illustrates a schematic representation of a power plant 200 in accordance with another embodiment of the present invention. Simplify the program diagram. The major components of power plant 200 are the same as those shown and described above with reference to power plant 100 of FIG. However, in this embodiment, steam from/to auxiliary turbine 124 is tapped from IP steam line 210 between HP turbine 121 and IP turbine 122 and provided to 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 temperature in the IP steam line is about 500 °C.

FIG. 3 illustrates a schematic simplified schematic diagram of a power plant 300 in accordance with another embodiment of the present invention. The main components of power plant 300 are the same as those shown and described above with reference to power plant 100 of FIG. 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 bars and about 7 bars. In another embodiment, the steam in the LP steam line 310 is between about 4 bars and about 6 bars. In another embodiment, the steam in LP line 310 is about 5 bars. 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 temperature in the LP steam line is about 400 °C.

4 illustrates a schematic representation of a power plant 400 in accordance with another embodiment of the present invention. Simplify the program diagram. The main components of power plant 400 are the same as those shown and described above with reference to power plant 100 of FIG. However, in this embodiment, steam is supplied from the auxiliary boiler 410 to the auxiliary turbine 124. Since the auxiliary boiler 410 is provided, the exhaust gas flow is decoupled from the heat input from the steam boiler unit 110 to the acid gas recovery unit 130. In one embodiment, the load on the auxiliary boiler 410 changes as the load on the main boiler changes. The load on the auxiliary boiler 410 can be varied to maintain the ratio of steam produced 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 feed to the auxiliary boiler 410 based on the change in fuel feed to the steam boiler unit 110.

FIG. 5 illustrates a schematic simplified schematic diagram of a power plant 500 in accordance with another embodiment of the present invention. The major components of power plant 500 are the same as those shown and described above with reference to power plant 100 of FIG. In this embodiment, the secondary steam consuming device 524 is a steam mixer. Steam mixer 524 can be a steam saturator. In another embodiment, the secondary steam consuming device 524 can be a steam device that receives one or more steam feeds of the same or various steam qualities and produces the resulting steam effluent of the desired steam quality. The steam saturator 524 receives steam feeds of the same or similar steam quality and combines the various steam feeds to produce a steam effluent of the desired steam quality. In one embodiment, the vapor effluent is a saturated vapor effluent. The steam feed 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 self-generating unit 119.

Turbine unit 110 includes a primary turbine circuit 110a and a secondary turbine Loop 110b. Main turbine circuit 110a receives water via primary feed line 111a and exhausts steam via high pressure steam line 126. Secondary turbine circuit 110b receives water via secondary feed line 111b and exits steam via secondary steam line 516. In one embodiment, the steam exiting via the secondary steam line 516 is high pressure steam.

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

As can be seen in Figure 5, steam from the power generation unit 119 is further provided to the steam saturator 524, including: HP steam supplied from the HP steam line 126 via the auxiliary HP steam line 126A; from the HP turbine via the auxiliary IP steam line 210A IP steam provided by IP steam feed line 210 between IP turbine 122 and IP turbine; LP steam supplied from LP steam line 310 between IP turbine 122 and LP turbine 123 via auxiliary LP steam line 310A; and exhaust steam via auxiliary Line 520A discharges steam from a discharge steam line 520 that discharges steam from LP turbine 123.

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 516 It is between about 160 bar and about 165 bar.

Steam is provided in a manner that produces a desired vapor stream via auxiliary steam line 124a to acid gas recovery unit 130 and is combined to steam saturator 524. In one embodiment, the reduced pressure steam may be provided at a pressure between about 5 bar and about 20 bar and at a temperature less than about 300 °C. The reduced pressure steam is supplied to the first reboiler 141 and the second reboiler 142. In another embodiment, the reduced pressure steam is provided to one or more reboilers. One or more of the auxiliary steam lines and the secondary steam line 516 may be utilized or shut down depending on the demand of the power generation unit 119.

FIG. 6 illustrates a schematic simplified schematic diagram of a power plant 600 in accordance with another embodiment of the present invention. The major components of power plant 600 are the same as those shown and described above with reference to power plant 300 of FIG. However, in this embodiment, flow control device 610 replaces auxiliary turbine 124 (FIG. 3) as secondary steam source 150. Flow control device 610 is provided on auxiliary LP steam line 310A. Flow control device 610 can be a throttle valve. The flow control device 610 can be selected, controlled, and/or adjusted to adjust the amount of steam provided to the auxiliary turbine 124. In another embodiment, flow control device 610 can be substituted for auxiliary turbine 124 of FIG. 2 and provided on auxiliary IP steam line 210A. In yet another embodiment, flow control device 610 can be substituted for auxiliary turbine 124 of FIG. 1 and provided on auxiliary HP steam line 126A.

FIG. 7 illustrates a schematic simplified schematic diagram of a power plant 700 in accordance with another embodiment of the present invention. The major components of power plant 700 are the same as those shown and described above with reference to power plant 100 of FIG. However, in this embodiment, the steam line to the auxiliary turbine 124 is in place of the auxiliary HP steam line 126A. (Fig. 1) an auxiliary combined steam line 726A. The auxiliary steam line 726A receives steam from the auxiliary HP steam line 126A, the auxiliary IP steam line 210A, and the auxiliary LP steam line 310A.

FIG. 8 illustrates a schematic simplified schematic diagram of a power plant 800 in accordance with another embodiment of the present invention. The major components of power plant 800 are the same as those shown and described above with reference to power plant 200 of FIG. However, in this embodiment, the auxiliary steam line 124a provides only steam to the LP regeneration column 155 without providing steam to the HP regeneration column 154. The steam from the LP steam line 310 is provided to the second auxiliary steam turbine 824 via the auxiliary LP steam line 310A. The second auxiliary steam turbine 824 is coupled to the second auxiliary generator 852 to generate electricity 852A. In another embodiment, one or more second auxiliary steam turbines 824 can be used. Steam is withdrawn from the second auxiliary steam turbine 824 via a second auxiliary steam line 824A that provides steam to the HP regeneration tower 154. In another embodiment, steam from the HP steam line 126 is provided to the auxiliary turbine 124 via the auxiliary HP steam line 126A. In yet another embodiment, steam from both the HP steam line 126 and the auxiliary LP steam line 210 is provided to the auxiliary turbine 124.

FIG. 9 illustrates a schematic simplified schematic diagram of a power plant 900 in accordance with another embodiment of the present invention. The major components of power plant 900 are the same as those shown and described above with reference to power plant 300 of FIG. However, in this embodiment, the auxiliary steam line 124a provides only steam to the LP regeneration column 155 without providing steam to the HP regeneration column 154. Instead, at least some of the steam from the auxiliary steam line 124a is bypassed to the second auxiliary steam turbine 924 via the auxiliary steam bypass line 910A. In another embodiment, one or more may be used A second auxiliary steam turbine 924. The second auxiliary steam turbine 924 is coupled to the second auxiliary generator 952 to generate electricity 952A. Steam is withdrawn from the second auxiliary steam turbine 924 via a second auxiliary steam line 924A that provides steam to the HP regeneration tower 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.

While the invention has been described with respect to the embodiments of the exemplary embodiments of the embodiments 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 scope of the invention. Therefore, the invention is not intended to be limited to the specific embodiments disclosed as the preferred embodiments of the invention.

100‧‧‧ Thermal Power Unit / Power Plant / Thermal System

110‧‧‧Main steam source/steam boiler unit

110a‧‧‧Main turbine circuit

110b‧‧‧Secondary turbine circuit

111a‧‧‧Main feed line

111b‧‧‧Secondary feed line

119‧‧‧Power unit

120‧‧‧Main steam consuming device/steam turbine

121‧‧‧High pressure (HP) turbine

122‧‧‧Medium pressure (IP) turbine

123‧‧‧Low pressure (LP) turbine

124‧‧‧Secondary steam consuming device/auxiliary steam turbine

124a‧‧‧Auxiliary steam line

124a ₁ ‧‧‧Second auxiliary steam line

124a ₂ ‧‧‧First auxiliary steam line

125‧‧‧Generator/Power Unit

125A‧‧‧Electric

126‧‧‧High pressure (HP) steam line

126A‧‧‧Assisted high pressure (HP) steam line

130‧‧‧Gas extraction and recovery unit/acid gas recovery unit

130a‧‧‧CO ₂ absorption unit

130b‧‧‧CO ₂ regeneration unit

140‧‧‧ reboiler

141‧‧‧First reboiler

142‧‧‧Second reboiler

150‧‧‧ secondary steam source

152‧‧‧Auxiliary generator

152A‧‧‧Electricity

153‧‧‧Regeneration tower/regenerator

154‧‧‧High Pressure (HP) Regeneration Tower

155‧‧‧Low Pressure (LP) Regeneration Tower

200‧‧‧ power plant

210‧‧‧IP steam line/IP steam feed line

210A‧‧‧Auxiliary IP steam line

231‧‧‧CO ₂ absorber (absorber)

231a‧‧‧feed line

231b‧‧‧Drainage line

232‧‧‧ fluid flushing cycle

233‧‧‧ fluid flushing pump

234‧‧‧Fluid Flush Cooler

235‧‧‧Fluid interconnection system

236‧‧‧ lean cooler

237‧‧‧Semi-lean cooler

238‧‧‧LP rich solution pump

239‧‧‧HP rich solution pump

240‧‧‧semi-lean/rich heat exchanger

241‧‧‧ semi-lean solution pump

242‧‧‧Low/rich heat exchanger

243‧‧‧ lean solution pump

244‧‧‧Drainage line

245‧‧‧Drainage line

246‧‧‧Drainage line

248‧‧‧CO ₂ product discharge line

300‧‧‧Power Plant

310‧‧‧LP steam line/LP feed line

310A‧‧‧Auxiliary LP steam line

400‧‧‧ power plant

410‧‧‧Auxiliary boiler

500‧‧‧ power plant

516‧‧‧Secondary steam pipeline

520‧‧‧Exhaust steam line

520A‧‧‧Auxiliary exhaust steam line

524‧‧‧Secondary steam consumption unit/steam mixer/steam saturator

600‧‧‧ power plant

610‧‧‧Flow control device

700‧‧‧Power Plant

726A‧‧‧Auxiliary combined steam line

800‧‧‧ power plant

824‧‧‧Second auxiliary steam turbine

824A‧‧‧Second auxiliary steam line

852‧‧‧Second auxiliary generator

852A‧‧‧Electricity

900‧‧‧Power Plant

910A‧‧‧Auxiliary steam bypass line

924‧‧‧Second auxiliary steam turbine

924a‧‧‧Second auxiliary steam line

952‧‧‧Second auxiliary generator

952A‧‧‧Electric

Figure 1 illustrates a schematic simplified schematic diagram of a power plant in accordance with an embodiment of the present invention.

2 illustrates a schematic simplified schematic diagram of a power plant in accordance with another embodiment of the present invention.

Figure 3 illustrates a schematic simplified schematic diagram of a power plant in accordance with another embodiment of the present invention.

4 illustrates a schematic simplified schematic diagram of a power plant in accordance with another embodiment of the present invention.

Figure 5 illustrates a schematic representation of a power plant in accordance with another embodiment of the present invention. Program diagram.

Figure 6 illustrates a schematic simplified schematic diagram of a power plant in accordance with another embodiment of the present invention.

Figure 7 illustrates a schematic simplified schematic diagram of a power plant in accordance with another embodiment of the present invention.

Figure 8 illustrates a schematic simplified schematic diagram of a power plant in accordance with another embodiment of the present invention.

Figure 9 illustrates a schematic simplified schematic diagram of a power plant in accordance with another embodiment of the present invention.

100‧‧‧ Thermal Power Unit / Power Plant / Thermal System

110‧‧‧Main steam source/steam boiler unit

119‧‧‧Power unit

120‧‧‧Main steam consuming device/steam turbine

121‧‧‧High pressure (HP) turbine

122‧‧‧Medium pressure (IP) turbine

123‧‧‧Low pressure (LP) turbine

124‧‧‧Secondary steam consuming device/auxiliary steam turbine

124a‧‧‧Auxiliary steam line

124a ₁ ‧‧‧Second auxiliary steam line

124a ₂ ‧‧‧First auxiliary steam line

125‧‧‧Generator/Power Unit

125A‧‧‧Electric

126‧‧‧High pressure (HP) steam line

126A‧‧‧Assisted high pressure (HP) steam line

130‧‧‧Gas extraction and recovery unit/acid gas recovery unit

130a‧‧‧CO ₂ absorption unit

130b‧‧‧CO ₂ regeneration unit

140‧‧‧ reboiler

141‧‧‧First reboiler

142‧‧‧Second reboiler

150‧‧‧ secondary steam source

152‧‧‧Auxiliary generator

152A‧‧‧Electricity

153‧‧‧Regeneration tower/regenerator

154‧‧‧High Pressure (HP) Regeneration Tower

155‧‧‧Low Pressure (LP) Regeneration Tower

210‧‧‧IP steam line/IP steam feed line

231‧‧‧CO ₂ absorber (absorber)

231a‧‧‧feed line

231b‧‧‧Drainage line

232‧‧‧ fluid flushing cycle

233‧‧‧ fluid flushing pump

234‧‧‧Fluid Flush Cooler

235‧‧‧Fluid interconnection system

236‧‧‧ lean cooler

237‧‧‧Semi-lean cooler

238‧‧‧LP rich solution pump

239‧‧‧HP rich solution pump

240‧‧‧semi-lean/rich heat exchanger

241‧‧‧ semi-lean solution pump

242‧‧‧Low/rich heat exchanger

243‧‧‧ lean solution pump

244‧‧‧Drainage line

245‧‧‧Drainage line

246‧‧‧Drainage line

248‧‧‧CO ₂ product discharge line

310‧‧‧LP steam line/LP feed line

520‧‧‧Exhaust steam line

Claims (15)

A power plant comprising: a boiler unit that generates steam; a power generation unit that includes at least one power generation turbine that receives the steam from the boiler unit; a gas recovery unit that includes two or more regeneration towers; A steam source is provided that provides steam to each of the two or more regeneration columns at different rates. The power plant of claim 1, wherein the gas recovery unit comprises an amine based washing unit. A power plant of claim 1 wherein the secondary steam source comprises an auxiliary turbine, a flow control device, or a combination thereof. The power plant of claim 1, wherein the power generating unit comprises a high pressure turbine, an intermediate pressure turbine, a low pressure turbine, or any combination thereof, and wherein the steam is fed from the high pressure steam to the high pressure turbine to the medium pressure turbine Any of the steam feed, low pressure steam feed to the low pressure turbine, and any combination thereof is provided to the secondary steam source. The power plant of claim 1, wherein the secondary steam source comprises a steam saturator, and wherein the steam satifier is from a high pressure feed line, a medium pressure feed line, a low pressure feed line, and a secondary feed from the boiler unit Any of the feed lines and any combination thereof receive steam. The power plant of claim 1, wherein the secondary steam source comprises an auxiliary boiler and an auxiliary turbine; or comprises an auxiliary turbine and a second auxiliary turbine. The power plant of claim 6, wherein the second auxiliary turbine is from the auxiliary The steam outlet of the turbine receives steam. A method of providing steam to a gas recovery unit, comprising: providing steam from a boiler unit or a power generation unit to a secondary steam source; discharging steam from the secondary steam source; and discharging the secondary steam source at different rates The steam is supplied to two or more regeneration towers of the gas recovery unit. The method of claim 8, wherein the steam is supplied to the secondary steam source from a boiler unit or a power generating unit. The method of claim 8, wherein the secondary steam source comprises at least one auxiliary turbine, a steam saturator, or a combination thereof. The method of claim 8, further comprising: providing steam to the power generating unit to generate electricity. The method of claim 8, wherein the gas recovery unit separates the acid gas from the gas stream. The method of claim 8, wherein the gas recovery unit is a CO ₂ recovery unit. The method of claim 8, wherein the gas recovery unit comprises two or more reboilers. The method of claim 8, wherein the steam flow rate provided to the gas recovery unit changes in response to a change in power generated by the power generation unit.