WO2012135574A2 - System and method for controlling waste heat for co2 capture - Google Patents

System and method for controlling waste heat for co2 capture Download PDF

Info

Publication number
WO2012135574A2
WO2012135574A2 PCT/US2012/031365 US2012031365W WO2012135574A2 WO 2012135574 A2 WO2012135574 A2 WO 2012135574A2 US 2012031365 W US2012031365 W US 2012031365W WO 2012135574 A2 WO2012135574 A2 WO 2012135574A2
Authority
WO
WIPO (PCT)
Prior art keywords
steam
turbine
plant
auxiliary
secondary source
Prior art date
Application number
PCT/US2012/031365
Other languages
French (fr)
Other versions
WO2012135574A3 (en
Inventor
Nareshkumar B. Handagama
Rasesh R. Kotdawala
Staffan Jonsson
Allen M. Pfeffer
Olivier Drenik
Jacques Marchand
Craig Norman Schubert
Original Assignee
Alstom Technology Ltd
Dow Global Technologies Llc
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Priority claimed from US13/432,350 external-priority patent/US20120247104A1/en
Application filed by Alstom Technology Ltd, Dow Global Technologies Llc filed Critical Alstom Technology Ltd
Priority to CA2831818A priority Critical patent/CA2831818A1/en
Priority to EP12714463.2A priority patent/EP2691611A2/en
Priority to JP2014502822A priority patent/JP2014515074A/en
Priority to CN201280015834.9A priority patent/CN103534444A/en
Priority to AU2012236370A priority patent/AU2012236370A1/en
Publication of WO2012135574A2 publication Critical patent/WO2012135574A2/en
Publication of WO2012135574A3 publication Critical patent/WO2012135574A3/en

Links

Classifications

    • FMECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F22STEAM GENERATION
    • F22BMETHODS OF STEAM GENERATION; STEAM BOILERS
    • F22B37/00Component parts or details of steam boilers
    • F22B37/008Adaptations for flue gas purification in steam generators
    • FMECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F01MACHINES OR ENGINES IN GENERAL; ENGINE PLANTS IN GENERAL; STEAM ENGINES
    • F01KSTEAM ENGINE PLANTS; STEAM ACCUMULATORS; ENGINE PLANTS NOT OTHERWISE PROVIDED FOR; ENGINES USING SPECIAL WORKING FLUIDS OR CYCLES
    • F01K17/00Using steam or condensate extracted or exhausted from steam engine plant
    • F01K17/04Using steam or condensate extracted or exhausted from steam engine plant for specific purposes other than heating
    • FMECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F23COMBUSTION APPARATUS; COMBUSTION PROCESSES
    • F23JREMOVAL OR TREATMENT OF COMBUSTION PRODUCTS OR COMBUSTION RESIDUES; FLUES 
    • F23J15/00Arrangements of devices for treating smoke or fumes
    • F23J15/006Layout of treatment plant
    • FMECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F23COMBUSTION APPARATUS; COMBUSTION PROCESSES
    • F23JREMOVAL OR TREATMENT OF COMBUSTION PRODUCTS OR COMBUSTION RESIDUES; FLUES 
    • F23J15/00Arrangements of devices for treating smoke or fumes
    • F23J15/02Arrangements of devices for treating smoke or fumes of purifiers, e.g. for removing noxious material
    • FMECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F23COMBUSTION APPARATUS; COMBUSTION PROCESSES
    • F23JREMOVAL OR TREATMENT OF COMBUSTION PRODUCTS OR COMBUSTION RESIDUES; FLUES 
    • F23J2215/00Preventing emissions
    • F23J2215/50Carbon dioxide
    • FMECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F23COMBUSTION APPARATUS; COMBUSTION PROCESSES
    • F23JREMOVAL OR TREATMENT OF COMBUSTION PRODUCTS OR COMBUSTION RESIDUES; FLUES 
    • F23J2219/00Treatment devices
    • F23J2219/40Sorption with wet devices, e.g. scrubbers
    • YGENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02CCAPTURE, STORAGE, SEQUESTRATION OR DISPOSAL OF GREENHOUSE GASES [GHG]
    • Y02C20/00Capture or disposal of greenhouse gases
    • Y02C20/40Capture or disposal of greenhouse gases of CO2
    • YGENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02EREDUCTION OF GREENHOUSE GAS [GHG] EMISSIONS, RELATED TO ENERGY GENERATION, TRANSMISSION OR DISTRIBUTION
    • Y02E20/00Combustion technologies with mitigation potential
    • Y02E20/32Direct CO2 mitigation

Definitions

  • 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.
  • 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 C0 2 , 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 C0 2 .
  • C0 2 capture systems have been integrated into these power stations. Numerous advances have been made in this respect, leading to the C0 2 generated during the combustion of fossil fuels being partly to completely separated from the combustion gases.
  • 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
  • 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.
  • 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.
  • an objective of the present invention may reside in the reduction of energy.
  • 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.
  • a plant in one aspect, 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 including two or more regenerator columns, and a secondary source of steam providing steam to each of the two or more regenerators columns at different rates.
  • a method for providing steam to a gas recovery unit includes providing steam to a secondary source of steam from either a boiler unit or a power generation unit, and discharging steam from the secondary source of steam, providing steam discharged from the secondary source of steam to two or regenerator columns of a gas recovery unit at different rates.
  • 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 plant according to another embodiment of the disclosure.
  • FIG. 3 illustrates a schematic, simplified process diagram of a plant according to another embodiment of the disclosure.
  • FIG. 4 illustrates a schematic, simplified process diagram of a plant according to another embodiment of the disclosure.
  • Fig. 5 illustrates a schematic, simplified process diagram of a plant according to another embodiment of the disclosure.
  • Fig. 6 illustrates a schematic, simplified process diagram of a plant according to another embodiment of the disclosure.
  • Fig. 7 illustrates a schematic, simplified process diagram of a plant according to another embodiment of the disclosure.
  • Fig. 8 illustrates a schematic, simplified process diagram of a plant according to another embodiment of the disclosure.
  • Fig. 9 illustrates a schematic, simplified process diagram of a plant according to another embodiment of the disclosure.
  • Fig. 1 illustrates a schematic, simplified process diagram of a plant 100 according to an embodiment of the disclosure.
  • the thermal system 100 may be a thermal power plant.
  • 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.
  • the plant 100 includes a primary source of steam 1 10, a power generation unit 1 19 and a gas recovery unit 130.
  • the primary source of steam 1 10 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.
  • 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).
  • 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.
  • the one or more steam turbines 120 may include a combination of any number of turbines of similar or varying operation pressure(s).
  • the power generation unit 1 19 further includes a secondary consumer of steam 124.
  • 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 local 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.
  • the setpoint may have an override based on the pressure of the exhaust steam of the auxiliary turbine 124.
  • the gas recovery unit 130 may be an acid gas capture and recovery unit.
  • the gas recover unit 130 includes a C0 2 absorption unit 130a and a C0 2 regeneration unit 130b.
  • the gas recovery unit 130 may be an amine based scrubbing unit.
  • the gas recovery unit 130 may be an advanced amine process for C0 2 capture.
  • the advanced amine process may be a double matrix scheme including a matrix stripping configuration.
  • the C0 2 absorption unit 130a includes a C0 2 absorber (absorber) 231.
  • the C0 2 regeneration unit 130b includes two or more regenerator columns 153.
  • Each regenerator column of the two or more regenerator columns 153 includes two or more reboilers 140.
  • 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.
  • 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.
  • HP high pressure
  • LP low pressure
  • the absorber 231 is provided a gas stream containing C0 2 from the steam boiler unit 1 10 via a feed line 231 a.
  • the gas stream may be a flue gas stream.
  • 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 absorber 231.
  • flue gas is contacted with a solvent solution that removes C0 2 from the flue gas by absorption.
  • the solvent solution may be an amine-based solvent solution.
  • the flue gas stream, having C0 2 removed, is discharged from the absorber 231 via a 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 carryover.
  • the rich C0 2 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 C0 2 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.
  • the carbon dioxide contained in the rich solvent to be regenerated maintained at its boiler point is released and stripped by the vapors of the absorbent solution.
  • Vapor containing the stripped C0 2 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 C0 2 .
  • the hot regenerated absorbent solution also called the lean solvent solution, is drawn off and recycled.
  • the HP regenerator column 154 and the LP regenerator column 155 are interconnected with the C0 2 absorber 231 by a fluid interconnection system 235 that circulates solvent solution for C0 2 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 C0 2 absorber 231, which is discharged from the C0 2 absorber rich in C0 2 , or in other words, C0 2 rich solvent, is provided to the HP regenerator column 154 and the LP regenerator column 155 where C0 2 is stripped from the solvent.
  • C0 2 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 C0 2 cooler, where residual moisture is removed from the C0 2 stream.
  • a C0 2 product stream is discharged from the gas recovery unit 130 via C0 2 product discharge line 248.
  • 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.
  • HP high pressure
  • 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 first reboiler 141 and the second reboiler 142 via first and second auxiliary steam lines 124a 2 , 124ai , respectively.
  • the reduced pressure steam is provided to each of the two or more regenerator columns 153 simultaneously and 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.
  • the steam is provided to the two or more regenerator columns 153 at different rates by controlling the quality of the steam by using one or more steam control devices, such as but not limited to valves, expansion devices, throttling devices and any combination thereof.
  • the regenerators 153 function in synch, however, the C0 2 stripping rates and column pressures are different, to optimize the gas capture and recovery system 130 with respect to C0 2 capture and energy.
  • the first auxiliary steam line 124a 2 and a second auxiliary steam line 124ai provide steam to the first and second reboilers 141 , 142 at different rates that 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.
  • the power production of the power generation unit 1 19 is minimally reduced, or in other words, incurs the minimum penalty of the power production of the plant 100. Therefore the heat duty delivery is provided independent and flexible to maintain optimality of the system.
  • the reduced pressure steam is provided to the two or more reboilers 140 via two or more auxiliary steam lines.
  • steam flow to the auxiliary turbine 124 is 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.
  • 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. The calculated ratio 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.
  • a top stage column temperature of the low pressure (LP) regenerator column 155 may 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 may be used to control the regeneration of C0 2 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.
  • Fig. 1 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.
  • 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 21 OA.
  • the steam in the IP steam line 210 is between about 50 bar and about 60 bar.
  • the steam in the IP steam line 210 is between about 58 bar and about 60 bar.
  • the steam in the IP steam line 210 is between about 450°C and 620°C.
  • the steam in the IP steam line is between about 480°C and 520°C.
  • the temperature 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.
  • 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.
  • 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 temperature 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.
  • 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 from the steam boiler unit 110 to the acid gas recovery unit 130 are decoupled.
  • 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 changed to maintain the ratio of steam generated by the auxiliary boiler 410 and the steam boiler unit 1 10.
  • 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.
  • a secondary consumer of steam 524 is a steam mixer.
  • the steam mixer 524 may be a steam saturator.
  • 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 saturator 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.
  • 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 saturator 524 is provided with steam from the steam boiler unit 1 10 and from various steam taps in the power generation unit 1 19.
  • the boiler unit 1 10 includes a primary boiler loop 1 10a and a secondary boiler loop 1 10b.
  • the primary boiler loop 1 10a receives water via a primary feed line 11 1a and discharges steam via a high pressure steam line 126.
  • the secondary boiler loop 1 10b receives water via a secondary feed line 1 1 1 b and discharges steam via a secondary steam line 516.
  • the steam discharged via the secondary steam line 516 is high pressure steam.
  • the steam saturator 524 receives steam from the secondary steam line 516.
  • steam from the secondary steam line 516 is provided to the steam saturator 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.
  • the secondary steam line 516 provides steam to the steam saturator 524 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.
  • the steam saturator 524 is further provided with steam from the power generation unit 1 19 including: 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 31 OA; and discharge steam from a discharge steam line 520 discharging steam from the LP turbine 123 via an auxiliary discharge steam line 520A.
  • 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 is between about 160 bar and about 165 bar.
  • 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.
  • the reduced pressure steam is provided to one or more reboilers.
  • one or more of the auxiliary steam lines, as well as the secondary steam line 516 may be utilized or shut off.
  • Fig. 6 illustrates 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 shown and described above with reference to the plant 300 of Fig. 3.
  • a flow control device 610 replaces the auxiliary turbine 124 (Fig. 3) as the secondary source of steam 150.
  • the flow control device 610 is provided on the auxiliary LP steam line 31 OA.
  • the flow control device 610 may be a throttle valve.
  • the flow control device 610 may be selected, controlled and/or adjusted to regulate the amount of steam provided to the auxiliary turbine 124.
  • the flow control device 610 may replace the auxiliary turbine 124 of Fig. 2 and be provided on the auxiliary IP steam line 21 OA.
  • Fig. 7 illustrates 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 shown and described above with reference to the plant 100 of Fig. 1.
  • the steam line to the auxiliary turbine 124 is an auxiliary combined steam line 726A in place of the auxiliary HP steam line 126A (Fig. 1 ).
  • the auxiliary steam line 726A receives steam from the auxiliary HP steam line 126A, auxiliary IP steam line 21 OA and the auxiliary LP steam line 31 OA.
  • Fig. 8 illustrates 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 shown and described above with reference to the plant 200 of Fig. 2.
  • the auxiliary steam line 124a provides steam only to the LP regenerator column 155, and not to the HP regenerator column 154.
  • steam from the LP steam line 310 is provided to a second auxiliary steam turbine 824 via an auxiliary LP steam line 31 OA.
  • the second auxiliary steam turbine 824 is coupled to a second auxiliary power generator 852 to generate electricity 852A.
  • one or more second auxiliary steam turbines 824 may be used.
  • Steam is discharged from the second auxiliary steam turbine 810 via a second auxiliary steam line 824A, which provides steam to the HP regenerator column 154.
  • steam from the HP steam line 126 is provided to the auxiliary turbine 124 via an auxiliary HP steam line 126A.
  • 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 process diagram of a plant 900 according to another embodiment of the disclosure.
  • the primary components of the plant 900 are the same as shown and described above with reference to the plant 300 of Fig. 3.
  • the auxiliary steam line 124a provides steam only to the LP regenerator column 155, and not to the HP regenerator column 154. Instead, at least some steam from the auxiliary steam line 124a is bypassed via a auxiliary steam bypass line 91 OA to a second auxiliary steam turbine 924.
  • one or more second auxiliary steam turbines 924 may be used.
  • the second auxiliary steam turbine 924 is coupled to a second auxiliary power generator 952 to generate electricity 952A.
  • Steam is discharged from the second auxiliary steam turbine 910 via a second auxiliary steam line 924A, which provides steam to the HP regenerator column 154.
  • steam from one or any combination of the HP steam line 126, IP steam line 210, and LP steam line 310 may be provided to the auxiliary turbine 124.

Landscapes

  • Engineering & Computer Science (AREA)
  • Mechanical Engineering (AREA)
  • General Engineering & Computer Science (AREA)
  • Chemical & Material Sciences (AREA)
  • Combustion & Propulsion (AREA)
  • Physics & Mathematics (AREA)
  • Thermal Sciences (AREA)
  • Gas Separation By Absorption (AREA)
  • Treating Waste Gases (AREA)

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 C02 CAPTURE
[0001] The present application claims the benefit under 35 U.S.C. §1 19(e) of Provisional Patent Application Serial No. 61/469,919 entitled A SYSTEM AND METHOD FOR CONTROLLING WASTE HEAT FOR C02 CAPTURE filed March 31 , 201 1 , the disclosure of which is incorporated herein by reference in its entirety.
CROSS-REFERENCE TO RELATED APPLICATIONS
[0002] This Application is related to United States Patent Application No. 61/469,915, Attorney Docket No. W09/078-0(27849-001 1 ), filed contemporaneously with this Application on March 31 , 201 1 , entitled "A SYSTEM AND METHOD FOR CONTROLLING WASTE HEAT FOR C02 CAPTURE" assigned to the assignee of the present invention and which is incorporated herein by reference in its entirety.
FIELD OF THE INVENTION
[0003] 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
[0004] 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 C02, nitrogen oxides NOx and sulfur oxides SOx. 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 C02. As such, C02 capture systems have been integrated into these power stations. Numerous advances have been made in this respect, leading to the C02 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. [0005] 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
sequestraton, production of methanol, and tertiary oil recovery.
[0006] 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.
[0007] 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
[0008] 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.
[0009] 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.
[0010] 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.
[0011] 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.
[0012] 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.
[0013] 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.
[0014] 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 including two or more regenerator columns, and a secondary source of steam providing steam to each of the two or more regenerators columns at different rates.
[0015] In another aspect, a method for providing steam to a gas recovery unit is disclosed that includes providing steam to a secondary source of steam from either a boiler unit or a power generation unit, and discharging steam from the secondary source of steam, providing steam discharged from the secondary source of steam to two or regenerator columns of a gas recovery unit at different rates.
BRIEF DESCRIPTION OF THE DRAWINGS
[0016] Referring now to the figures, which are exemplary embodiments, and wherein the like elements are numbered alike.
[0017] Fig. 1 illustrates a schematic, simplified process diagram of a plant according to an embodiment of the disclosure. [0018] Fig. 2 illustrates a schematic, simplified process diagram of a plant according to another embodiment of the disclosure.
[0019] Fig. 3 illustrates a schematic, simplified process diagram of a plant according to another embodiment of the disclosure.
[0020] Fig. 4 illustrates a schematic, simplified process diagram of a plant according to another embodiment of the disclosure.
[0021] Fig. 5 illustrates a schematic, simplified process diagram of a plant according to another embodiment of the disclosure.
[0022] Fig. 6 illustrates a schematic, simplified process diagram of a plant according to another embodiment of the disclosure.
[0023] Fig. 7 illustrates a schematic, simplified process diagram of a plant according to another embodiment of the disclosure.
[0024] Fig. 8 illustrates a schematic, simplified process diagram of a plant according to another embodiment of the disclosure.
[0025] Fig. 9 illustrates a schematic, simplified process diagram of a plant according to another embodiment of the disclosure.
DETAILED DESCRIPTION
[0026] 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.
[0027] 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. [0028] As can be seen in Fig. 1 , the plant 100 includes a primary source of steam 1 10, a power generation unit 1 19 and a gas recovery unit 130. In this exemplary embodiment, the primary source of steam 1 10 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.
[0029] 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).
[0030] As can be further seen in Fig. 1 , the power generation unit 1 19 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 local 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.
[0031] The gas recovery unit 130 may be an acid gas capture and recovery unit. The gas recover unit 130 includes a C02 absorption unit 130a and a C02 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 C02 capture. In one embodiment, the advanced amine process may be a double matrix scheme including a matrix stripping configuration.
[0032] The C02 absorption unit 130a includes a C02 absorber (absorber) 231. The C02 regeneration unit 130b includes two or more regenerator columns 153. Each regenerator column of the two or more regenerator columns 153 includes two or more reboilers 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.
[0033] The absorber 231 is provided a gas stream containing C02 from the steam boiler unit 1 10 via a feed line 231 a. The gas stream may be a flue gas stream. 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 absorber 231. In the absorber 231 , flue gas is contacted with a solvent solution that removes C02 from the flue gas by absorption. The solvent solution may be an amine-based solvent solution. The flue gas stream, having C02 removed, is discharged from the absorber 231 via a 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 carryover.
[0034] To effect the regeneration of the solvent solution, the rich C02 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 C02 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 boiler point is released and stripped by the vapors of the absorbent solution. Vapor containing the stripped C02 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 C02. At the bottom of the regenerator column, the hot regenerated absorbent solution, also called the lean solvent solution, is drawn off and recycled.
[0035] In this exemplary embodiment, the HP regenerator column 154 and the LP regenerator column 155 are interconnected with the C02 absorber 231 by a fluid interconnection system 235 that circulates solvent solution for C02 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.
[0036] The solvent solution, such as an amine solution, from the C02 absorber 231, which is discharged from the C02 absorber rich in C02, or in other words, C02 rich solvent, is provided to the HP regenerator column 154 and the LP regenerator column 155 where C02 is stripped from the solvent. C02 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 C02 cooler, where residual moisture is removed from the C02 stream. A C02 product stream is discharged from the gas recovery unit 130 via C02 product discharge line 248.
[0037] 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. [0038] 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.
[0039] The reduced pressure steam provided to the gas recovery unit 130 is provided to the first reboiler 141 and the second reboiler 142 via first and second auxiliary steam lines 124a2, 124ai , respectively. The reduced pressure steam is provided to each of the two or more regenerator columns 153 simultaneously and 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. The steam is provided to the two or more regenerator columns 153 at different rates by controlling the quality of the steam by using one or more steam control devices, such as but not limited to valves, expansion devices, throttling devices and any combination thereof. The regenerators 153 function in synch, however, the C02 stripping rates and column pressures are different, to optimize the gas capture and recovery system 130 with respect to C02 capture and energy. The first auxiliary steam line 124a2 and a second auxiliary steam line 124ai provide steam to the first and second reboilers 141 , 142 at different rates that 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 1 19 is minimally reduced, or in other words, incurs the minimum penalty of the power production of the plant 100. Therefore the heat duty delivery is provided independent and flexible to maintain optimality of the system. In another embodiment, the reduced pressure steam is provided to the two or more reboilers 140 via two or more auxiliary steam lines. [0040] According to the provided system and method, steam flow to the auxiliary turbine 124 is 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.
[0041] 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. The calculated ratio 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. In another embodiment, a top stage column temperature of the low pressure (LP) regenerator column 155 may be used to set the reboiler duty in the second reboiler 142.
[0042] The steam flow from the auxiliary turbine 124 to the two or more reboilers 140 may be used to control the regeneration of C02 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.
[0043] 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.
[0044] 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 21 OA. 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.
[0045] 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.
[0046] 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 temperature in the LP steam line is about 400°C.
[0047] 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 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 changed to maintain the ratio of steam generated by the auxiliary boiler 410 and the steam boiler unit 1 10. 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. [0048] 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 saturator 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 saturator 524 is provided with steam from the steam boiler unit 1 10 and from various steam taps in the power generation unit 1 19.
[0049] The boiler unit 1 10 includes a primary boiler loop 1 10a and a secondary boiler loop 1 10b. The primary boiler loop 1 10a receives water via a primary feed line 11 1a and discharges steam via a high pressure steam line 126. The secondary boiler loop 1 10b receives water via a secondary feed line 1 1 1 b 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.
[0050] The steam saturator 524 receives steam from the secondary steam line 516. In one embodiment, steam from the secondary steam line 516 is provided to the steam saturator 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 saturator 524 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.
[0051] As can be seen in Fig. 5, the steam saturator 524 is further provided with steam from the power generation unit 1 19 including: 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 31 OA; and discharge steam from a discharge steam line 520 discharging steam from the LP turbine 123 via an auxiliary discharge steam line 520A.
[0052] 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 is between about 160 bar and about 165 bar.
[0053] Steam is provided and combined to the steam saturator 524 in a manner that produces a desired steam flow to the acid gas recovery unit 130 via auxiliary steam line 124a. 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. 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.
[0054] Fig. 6 illustrates 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 shown and described above with reference to the plant 300 of Fig. 3. However, in this embodiment, a flow control device 610 replaces the auxiliary turbine 124 (Fig. 3) as the secondary source of steam 150. The flow control device 610 is provided on the auxiliary LP steam line 31 OA. The flow control device 610 may be a throttle valve. The flow control device 610 may be selected, controlled and/or adjusted to regulate the amount of steam provided to the auxiliary turbine 124. In another embodiment, the flow control device 610 may replace the auxiliary turbine 124 of Fig. 2 and be provided on the auxiliary IP steam line 21 OA. In yet another embodiment, the flow control device 610 may replace the auxiliary turbine 124 of Fig. 1 and be provided on the auxiliary HP steam line 126A. [0055] Fig. 7 illustrates 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 shown and described above with reference to the plant 100 of Fig. 1. However, in this embodiment, the steam line to the auxiliary turbine 124 is an auxiliary combined steam line 726A in place of the auxiliary HP steam line 126A (Fig. 1 ). The auxiliary steam line 726A receives steam from the auxiliary HP steam line 126A, auxiliary IP steam line 21 OA and the auxiliary LP steam line 31 OA.
[0056] Fig. 8 illustrates 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 shown and described above with reference to the plant 200 of Fig. 2. However, in this embodiment, the auxiliary steam line 124a provides steam only to the LP regenerator column 155, and not to the HP regenerator column 154. Instead, steam from the LP steam line 310 is provided to a second auxiliary steam turbine 824 via an auxiliary LP steam line 31 OA. The second auxiliary steam turbine 824 is coupled to a second auxiliary power generator 852 to generate electricity 852A. In another embodiment, one or more second auxiliary steam turbines 824 may be used. Steam is discharged from the second auxiliary steam turbine 810 via a second auxiliary steam line 824A, which provides steam to the HP regenerator column 154. In another embodiment, steam from the HP steam line 126 is provided to the auxiliary turbine 124 via an 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.
[0057] Fig. 9 illustrates 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 shown and described above with reference to the plant 300 of Fig. 3. However, in this embodiment, the auxiliary steam line 124a provides steam only to the LP regenerator column 155, and not to the HP regenerator column 154. Instead, at least some steam from the auxiliary steam line 124a is bypassed via a auxiliary steam bypass line 91 OA to a second auxiliary steam turbine 924. 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 power generator 952 to generate electricity 952A. Steam is discharged from the second auxiliary steam turbine 910 via a second auxiliary steam line 924A, which provides steam to the HP regenerator column 154. In another embodiment, steam from one or any combination of the HP steam line 126, IP steam line 210, and LP steam line 310 may be provided to the auxiliary turbine 124.
[0058] 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 (100), comprising:
a boiler unit (110) that produces steam;
a power generation unit (1 19) comprising at least one power generation turbine (120) that receives the steam from the boiler unit (1 10);
a gas recovery unit (130) comprising two or more regenerator columns (153); and
a secondary source of steam (124(a)) providing steam to each of the two or more regenerators columns (153) at different rates.
2. The plant (100) of claim 1 , wherein the gas recovery unit (130) comprises an amine based scrubbing process.
3. The plant (100) of claim 1 , wherein the secondary source of steam (124(a)) comprises an auxiliary turbine (124).
4 The plant (100) of claim 1 , wherein the secondary source of steam (124(a)) comprises a flow control device (610).
5. The plant (100) of claim 1 , wherein the power generation unit (1 19) comprises a high pressure turbine (121) and high pressure steam (126(a)) is provided to the secondary source of steam from a high pressure steam feed to the high pressure turbine.
6. The plant (100) of claim 1 , wherein the power generation unit (1 19) comprises a high pressure turbine (121 ) and an intermediate pressure turbine (122), and steam is provided to the secondary source of steam (124(a)) from any one of the high pressure steam feed to the high pressure turbine (126(a)), and the intermediate pressure steam feed to the intermediate pressure turbine (122).
7. The plant (100) of claim 1 , wherein the power generation unit (1 19) comprises a high pressure turbine (121 ), an intermediate pressure turbine (122), and a low pressure turbine (123), and steam is provided to the secondary source of steam (124(a)) from any one of the high pressure steam feed to the high pressure turbine
(121) , the intermediate pressure steam feed to the intermediate pressure turbine
(122) , the low pressure steam feed to the low pressure turbine (123), and any combination thereof.
8. The plant (400) of claim 1 , wherein the secondary source of steam (124(a)) comprises an auxiliary boiler (410) and an auxiliary turbine (124).
9. The plant (500) of claim 1 , wherein the secondary source of steam (124(a)) comprises a steam saturator (524), and wherein the steam saturator (524) receives steam from any one of a high pressure feed line, an intermediate pressure feed line, a low pressure feed-line, a secondary feed line from the boiler unit (110), and any combination thereof.
10. The plant (800) of claim 1 , wherein the secondary source of steam (824) comprises an auxiliary turbine (124) and a second auxiliary turbine (824).
11. The plant (800) of claim 10, wherein the second auxiliary turbine (824) receives steam from the steam discharge of the auxiliary turbine (824).
12. A method for providing steam to a gas recovery unit, comprising:
providing steam to a secondary source of steam (124(a)) from either a boiler unit (110) or a power generation unit (119);
discharging steam from the secondary source of steam (124(a)); and providing steam discharged from the secondary source of steam to two or more regenerator columns (153) of a gas recovery unit at different rates.
13. The method of claim 12, wherein steam is provided to the secondary source of steam (124(a)) from the boiler unit (110).
14. The method of claim 12, wherein steam is provided to the secondary source of steam (124(a)) from the power generation unit (1 19).
15. The method of claim 12, wherein the secondary source of steam (124(a)) comprises at least one auxiliary turbine (124).
16. The method of claim 12, wherein the secondary source of steam (124(a)) comprises a steam saturator (524).
17. The method of claim 12, further comprising:
providing steam to a power generation unit ( 19) to generate electricity.
18. The method of claim 12, wherein the gas recovery unit (130) separates an acid gas from a gas steam.
19. The method of claim 12, wherein the gas recovery unit (130) is a C02 recovery unit.
20. The method of claim 12, wherein the gas recovery unit (130) comprises two or more reboilers.
21. The method of claim 12, wherein a flow steam provided to the gas recovery unit (130) is varied in response to changes in power generated by the power generation unit (1 19).
PCT/US2012/031365 2011-03-31 2012-03-30 System and method for controlling waste heat for co2 capture WO2012135574A2 (en)

Priority Applications (5)

Application Number Priority Date Filing Date Title
CA2831818A CA2831818A1 (en) 2011-03-31 2012-03-30 System and method for controlling waste heat for co2 capture
EP12714463.2A EP2691611A2 (en) 2011-03-31 2012-03-30 System and method for controlling waste heat for co2 capture
JP2014502822A JP2014515074A (en) 2011-03-31 2012-03-30 System and method for controlling waste heat for CO2 capture
CN201280015834.9A CN103534444A (en) 2011-03-31 2012-03-30 System and method for controlling waste heat for CO2 capture
AU2012236370A AU2012236370A1 (en) 2011-03-31 2012-03-30 System and method for controlling waste heat for CO2 capture

Applications Claiming Priority (4)

Application Number Priority Date Filing Date Title
US201161469919P 2011-03-31 2011-03-31
US61/469,919 2011-03-31
US13/432,350 2012-03-28
US13/432,350 US20120247104A1 (en) 2011-03-31 2012-03-28 System and method for controlling waste heat for co2 capture

Publications (2)

Publication Number Publication Date
WO2012135574A2 true WO2012135574A2 (en) 2012-10-04
WO2012135574A3 WO2012135574A3 (en) 2013-08-15

Family

ID=46932351

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/US2012/031365 WO2012135574A2 (en) 2011-03-31 2012-03-30 System and method for controlling waste heat for co2 capture

Country Status (7)

Country Link
EP (1) EP2691611A2 (en)
JP (1) JP2014515074A (en)
CN (1) CN103534444A (en)
AU (1) AU2012236370A1 (en)
CA (1) CA2831818A1 (en)
TW (1) TW201307669A (en)
WO (1) WO2012135574A2 (en)

Cited By (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN105582794A (en) * 2016-01-19 2016-05-18 河北工程大学 Solar energy and geothermal energy assisted CO2 Rankine cycle assisted decarbonization and denitrification system for coal-fired unit

Families Citing this family (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
MD4322C1 (en) * 2011-05-17 2015-07-31 Иван ГОНЧАРЮК Device and process for converting steam energy into electrical energy
PL2942494T3 (en) * 2014-05-08 2020-03-31 General Electric Technology Gmbh Coal fired oxy plant with heat integration
US10690010B2 (en) * 2018-03-16 2020-06-23 Uop Llc Steam reboiler with turbine
CN112452109B (en) * 2020-12-31 2021-08-27 双盾环境科技有限公司 Desorption SO for improving desulfurization absorbent2Efficient process

Family Cites Families (11)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US2600328A (en) * 1948-06-07 1952-06-10 Fluor Corp Separation of acidic constituents from gases
NO321817B1 (en) * 2003-11-06 2006-07-10 Sargas As Wastewater treatment plants
US20100005966A1 (en) * 2006-07-17 2010-01-14 Commonwealth Scientific And Industrial Research Organsation Co2 capture using solar thermal energy
ATE553832T1 (en) * 2007-01-25 2012-05-15 Shell Int Research METHOD FOR REDUCING CARBON DIOXIDE EMISSIONS IN A POWER PLANT
JP2008307520A (en) * 2007-06-18 2008-12-25 Mitsubishi Heavy Ind Ltd Co2 or h2s removal system, co2 or h2s removal method
US20090151318A1 (en) * 2007-12-13 2009-06-18 Alstom Technology Ltd System and method for regenerating an absorbent solution
EP2105190A1 (en) * 2008-03-27 2009-09-30 Siemens Aktiengesellschaft Method and device for separating carbon dioxide from an exhaust gas of a fossil fuel-powered power plant
JP5558036B2 (en) * 2008-09-04 2014-07-23 株式会社東芝 Carbon dioxide recovery steam power generation system
DE102009032537A1 (en) * 2009-07-10 2011-01-13 Hitachi Power Europe Gmbh Coal-fired power station with associated CO2 scrubbing and heat recovery
JP5484811B2 (en) * 2009-07-17 2014-05-07 三菱重工業株式会社 Carbon dioxide recovery system and method
JP2011047364A (en) * 2009-08-28 2011-03-10 Toshiba Corp Steam turbine power generation facility and operation method for the same

Non-Patent Citations (1)

* Cited by examiner, † Cited by third party
Title
None

Cited By (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN105582794A (en) * 2016-01-19 2016-05-18 河北工程大学 Solar energy and geothermal energy assisted CO2 Rankine cycle assisted decarbonization and denitrification system for coal-fired unit

Also Published As

Publication number Publication date
JP2014515074A (en) 2014-06-26
CA2831818A1 (en) 2012-10-04
TW201307669A (en) 2013-02-16
WO2012135574A3 (en) 2013-08-15
AU2012236370A1 (en) 2013-10-10
CN103534444A (en) 2014-01-22
EP2691611A2 (en) 2014-02-05

Similar Documents

Publication Publication Date Title
US20120247104A1 (en) System and method for controlling waste heat for co2 capture
US8806870B2 (en) Carbon-dioxide-recovery-type thermal power generation system and method of operating the same
CA2491163C (en) Improved split flow process and apparatus
US8887505B2 (en) Carbon dioxide recovery system and method
RU2508158C2 (en) Method and device for separation of carbon dioxide from offgas at electric power station running at fossil fuel
JP5875245B2 (en) CO2 recovery system and CO2 gas-containing moisture recovery method
KR20110110244A (en) Method and device for separating carbon dioxide from an exhaust gas of a fossil fired power plant
EP2691611A2 (en) System and method for controlling waste heat for co2 capture
WO2014013939A1 (en) Co2 recovery system
US20140150699A1 (en) Method and fossil-fuel-fired power plant for recovering a condensate
WO2014129391A1 (en) Co2 recovery system and co2 recovery method
JP5584040B2 (en) CO2 recovery steam turbine system and operation method thereof
KR101749287B1 (en) Feedwater storage and recirculation system and method
US20140366720A1 (en) Method and system for removing carbon dioxide from flue gases
WO2012154313A1 (en) System and method for controlling waste heat for co2 capture
CN117797605A (en) Flue gas carbon dioxide trapping system
WO2018200526A1 (en) Process for carbon dioxide recapture with improved energy recapture

Legal Events

Date Code Title Description
121 Ep: the epo has been informed by wipo that ep was designated in this application

Ref document number: 12714463

Country of ref document: EP

Kind code of ref document: A2

ENP Entry into the national phase

Ref document number: 2831818

Country of ref document: CA

ENP Entry into the national phase

Ref document number: 2014502822

Country of ref document: JP

Kind code of ref document: A

ENP Entry into the national phase

Ref document number: 2012236370

Country of ref document: AU

Date of ref document: 20120330

Kind code of ref document: A

WWE Wipo information: entry into national phase

Ref document number: 2012714463

Country of ref document: EP