FOR CARBON DIOXIDE CAPTURE AND THERMAL COMPRESSION

Technical Field of the Invention

The present invention relates in general to carbon dioxide CO ₂ capture and removal, and more particularly to a process for producing CO ₂ from amine solvent regeneration at elevated pressure using renewable heat over a range of temperature rather than electricity and at elevated pressure. Background Art

Without limiting the scope of the invention, its background is described in connection with methods for carbon dioxide capture and removal from flue gas or with acid gas treatment processes, particularly removal of hydrogen sulfide and carbon dioxide from gas streams formed in refinery process units, synthesis gas production plants and oil and gas production facilities.

U. S. Patent Application Publication No. 20070284240 (Rhodes and Rhodes, 2007) discloses a system for optimized operation and troubleshooting/diagnosis of an amine regeneration system comprising a flash tank, a rich/lean heat exchanger, a still, a reflux condenser, a reflux accumulator, a pump, a reboiler, and a pump bypass line to the flash tank.

U. S. Patent No. 6,547,854 issued to Gray et al. (2003) describe a new method for making low-cost CO ₂ sorbents that can be used in large-scale gas-solid processes. The new method entails treating a solid substrate with acid or base and simultaneous or subsequent treatment with a substituted amine salt. The method of the Gray invention eliminates the need for organic solvents and polymeric materials for the preparation of C0 ₂ capture systems

Disclosure of the Invention

The present invention in various embodiments relates to amine solvent regeneration for CO ₂ removal. A process involving the use of geothermal energy to regenerate the amine solvent used for C0 ₂ capture from coal-fired power plants or other gas sources is disclosed. A multi-stage stripper process configuration for using heat over a range of temperatures to regenerate amine solvents from C0 ₂ capture is also described herein. Finally, a thermal compression method for C0 ₂ from amine solvent regeneration is also disclosed.

The present invention in one embodiment discloses a process for geothermal regeneration of a carbon dioxide (C0 ₂ ) capturing amine solvent comprising the steps of: collecting a hot water or a brine from a first location in an aquifer or a geopressured formation by use of a first water well, wherein the water well is created by digging, drilling, driving, boring, or combinations thereof, contacting the hot water with the amine solvent in one or more regenerating systems, wherein the amine solvents comprise captured C0 ₂ , and exchanging heat from the hot water or brine to the amine solvent to regenerate the amine solvent and release the captured C0 ₂ , wherein the exchange lowers a temperature of the hot water or the brine.

Another embodiment of the present invention describes a process for geothermal regeneration of a carbon dioxide (CO ₂ ) capturing amine solvent comprising the steps of: (i) collecting a hot water or brine from a first location in an aquifer or a geopressured formation by use of a first water well, wherein the water well is created by digging, drilling, driving, boring, or combinations thereof, (ii) contacting the hot water with the amine solvent in two or more regenerating systems, wherein the amine solvents comprise captured CO ₂ , wherein the regenerating systems are operated at different temperatures and pressures, and (iii) exchanging heat from the hot water or brine to the amine solvent to regenerate the amine solvent and release the C0 ₂ , wherein the exchange lowers the temperature of the hot water or brine.

The process as described hereinabove further comprises the step of injecting the hot water or brine at the lower temperature into a second location in aquifer or the geopressured formation by the use of a second well, wherein the second water well is created by digging, drilling, driving, boring, or combinations thereof. In one aspect of the process the amine solvent comprises monoethanolamine (MEA), diglycolamine (DGA), diethanolamine (DEA), diisopropanolamine (DIPA), methyldiethanolamine (MDEA), piperazine, (PZ), 2-methyl-piperazine, 1-methyl-piperazine, 2- amino-2-methyl-propanol, 2-piperidine-ethanol, 1,4-dimethylpiperazine, or combinations thereof. In another aspect the released CO ₂ is cooled and compressed. In another aspect the first location and the second locations are different. In another aspect the first water well and the second water well is different. In yet another aspect the first and the second water wells have a depth of 7000 to 15,000 Ft. In another aspect the hot water or the brine has a temperature of about 125-175C. In a related aspect the process lowers the temperature of the hot water or brine to a temperature of about 80- 120C.

Yet another embodiment of the present invention describes a process for carbon dioxide (CO ₂ ) capture from a flue gas, removal of C0 ₂ and H ₂ S from a gas mixture, or both comprising the steps of: (i) providing a stripping assembly comprising two or more stages, wherein the two or more stages are at a different temperatures and pressure, (ii) providing a solvent for C0 ₂ capture, removal, or both from the flue gas or the gas mixture, wherein the solvent is an amine solvent, (iii) passing the solvent through the two or more stages of the stripping assembly, (iv) contacting the solvent with the flue gas or the mixture of gases, (v) exchanging heat from the solvent at a higher temperature comprising a higher CO ₂ concentration in a first stage with the solvent at a lower temperature comprising a lower concentration or no CO ₂ in a second stage, (vi) exchanging the hot vapor from the high temperature stage with colder solvent at the lower temperature to recover a sensible and a latent heat in the hot vapor, and (vii) releasing the C0 ₂ to be cooled and compressed or for further processing.

In one aspect at least one of the stages are heated. In another aspect the stages are heated by a hot water or a brine from an aquifer or a geopressured formation. In another aspect the amine solvent comprises monoethanolamine (MEA), diglycolamine (DGA), diethanolamine (DEA), diisopropanolamine (DIP A), methyldiethanolamine (MDEA), piperazine, (PZ), 2-methyl-piperazine, 1-methyl-piperazine, 2-amino-2-methyl-propanol, 2-piperidine-ethanol, and 1,4-dimethylpiperazine, or combinations thereof.

In one aspect the present invention discloses a stripping assembly configuration comprising: two or more stages at different temperatures and pressures, wherein a solvent for C0 ₂ capture, removal, or both is passed through the two or more stages, wherein at least one of the stages is heated. In one aspect of the configuration described herein an exchange of heat occurs from the solvent at a higher temperature comprising a higher CO ₂ concentration in a first stage with the solvent at a lower temperature comprising a lower concentration or no CO ₂ in a second stage. In another aspect the stages are heated by a hot water or a brine from an aquifer or a geopressured formation.

In one embodiment the present invention discloses a stripping assembly configuration comprising: two or more stages at different temperatures and pressures, wherein a solvent for C0 ₂ capture, removal, or both is passed through the two or more stages, wherein at least one of the stages are heated. In one aspect an exchange of heat occurs from the solvent at a higher temperature comprising a higher CO ₂ concentration in a first stage with the solvent at a lower temperature comprising a lower concentration or no CO ₂ in a second stage. In another aspect the stages are heated by a hot water or a brine from an aquifer or a geopressured formation.

In another embodiment of the present invention relates to a process for carbon dioxide (CO ₂ ) capture from a flue gas, removal of CO ₂ and ¾S from a gas mixture, or both comprising the steps of: providing an absorption/stripping assembly, wherein the assembly is capable of withstanding multiple pressure application, absorbing and stripping the C0 ₂ from the flue gas or the gas mixture using an amine solvent at pressures ranging from 1 to 10 bars, reabsorbing the CO ₂ at an ambient temperature, wherein the reabsorption is achieved by a cross-flow of a heated amine solvent comprising a very low concentration to no C0 ₂ , flashing the reabsorbed C0 ₂ at a very high pressure, and releasing the C0 ₂ to be cooled and compressed. In one aspect of the process the amine solvent comprises monoethanolamine (MEA), diglycolamine (DGA), diethanolamine (DEA), diisopropanolamine (DIP A), methyldiethanolamine (MDEA), piperazine, (PZ), 2-methyl-piperazine, 1-methyl-piperazine, 2-amino-2-methyl-propanol, 2-piperidine-ethanol, and 1,4-dimethylpiperazine, or combinations thereof.

In a related aspect the CO ₂ is reabsorbed at temperatures of about 20°C to 60°C and is flashed at pressures of about 10-50 bar. In another aspect the heated amine solvent is at about 100-150°C. In another aspect the amine solvent is heated by a hot water or a brine from an aquifer or a geopressured formation. Description of the Drawings

For a more complete understanding of the features and advantages of the present invention, reference is now made to the detailed description of the invention along with the accompanying figures and in which:

FIG. 1 is a process diagram showing a multistage, multipressure flash without geothermal heating;

FIG. 2 shows three flashes with two pressures and three temperatures show. External heat such as geothermal heat could be introduced at three temperature levels;

FIG. 3 shows a process in which a high pressure rich flash is followed by low pressure lean flash with recovery of heat from the high pressure vapor;

FIG. 4 shows a high pressure rich flash followed by low pressure lean flash with recovery of heat from the high pressure vapor by direct contact;

FIG. 5 shows a low pressure rich flash followed by high pressure lean flash with recovery of heat from the high pressure vapor by exchange with lower T rich solution;

FIG. 6 shows an advanced 2-Stage, 2-Pressure Flash (2T2Pflash) for amine solvent regeneration with geothermal brine heating. Conditions shown for the optimal case, designed for a 60 MWe coal-fired power plant, removing 1195 ton C0 ₂ /day;

FIG. 7 provides an example of an adiabatic flash configuration modified for geothermal heating. Conditions shown for the optimal case, designed for a 60 MWe coal-fired power plant, removing 1195 ton C0 ₂ /day;

FIG. 8 is a plot showing the lean loading optimization for 2T2Pflash with 8 m PZ applied to a 60 MW _e power plant. 0.40 rich loading, T _brine;in = 150 °C, T _brine;0ut = 100 °C, 5 °C LMTD on heat exchangers, C0 ₂ compression to 150 bar;

FIG 9 shows a reduction in total heat duty with increasing brine temperature for 2T2Pflash with 8 m PZ. 0.40 rich loading, ATbrine = 50°C, 5°C LMTD on heat exchangers, C02 compression to 150 bar. Points = simulation results, line = approximate linear representation; and

FIG. 10 shows lean loading optimization for Fluor configuration with 9 m MEA. 0.5 rich loading, Tbrine,in = 150°C, Tbrine.out = 100°C, C0 ₂ compression to 150 bar.

Description of the Invention

While the making and using of various embodiments of the present invention are discussed in detail below, it should be appreciated that the present invention provides many applicable inventive concepts that can be embodied in a wide variety of specific contexts. The specific embodiments discussed herein are merely illustrative of specific ways to make and use the invention and do not delimit the scope of the invention. To facilitate the understanding of this invention, a number of terms are defined below. Terms defined herein have meanings as commonly understood by a person of ordinary skill in the areas relevant to the present invention. Terms such as "a", "an" and "the" are not intended to refer to only a singular entity, but include the general class of which a specific example may be used for illustration. The terminology herein is used to describe specific embodiments of the invention, but their usage does not delimit the invention, except as outlined in the claims.

The term "aquifer" as used herein relates to a water-bearing bed or stratum of permeable rock, sand, or gravel capable of yielding considerable quantities of water to wells or springs. As used herein, the term "geothermal aquifer" refers to a porous zone in the earth's crust which contains water which is at least about 60° C.

The term "brine" as used herein in various embodiments is used in a broad sense to denote the entire range of concentrations of aqueous solutions of water soluble inorganic compounds, for example, natural saline water containing sodium chloride, including brackish water, sea water, and saturated or nearly saturated brines, such as the brine in the Great Salt Lake or brines obtained from wells. In addition to sodium chloride-containing solutions, other brines to which the process may be applied include aqueous solutions of dissolved mineral salts, for example, halides, carbonates and sulfates of sodium, potassium, lithium, calcium, magnesium, zinc and copper.

The term "flue gas" as used herein includes the exhaust gas from any sort of combustion process (including coal, oil, natural gas, glass raw material, etc.).

The present invention used geothermal energy to regenerate the amine solvent used for CO ₂ capture from coal-fired power plants or other gas sources. A well drilled to a depth of 7000 to 15000 ft. in a porous brine formation produces hot water at 125 to 175°C. The hot water was used to provide the heat to regenerate rich amine from a scrubbing system to remove CO ₂ . Amine scrubbing regenerators normally use steam that condenses at 110 to 160°C. The steam heat was replaced by heat from the geothermal source. More heat was recovered over a range of temperatures by using two or more parallel regeneration systems that operate at variable temperatures and pressures. Heat was exchanged from the hot brine to the reboiler of the amine stripper. Cold brine at 80 to 120°C was returned to the porous formation at 7000 to 15000 ft. in a well at some distance from the extraction well.

Unlike most geothermal wells that attempt to extract heat at 150 to 200°C, this amine regeneration system described herein is able to use heat at a lower temperature, so the geothermal well does not have to be as deep, nor does it require extraordinary geologic features.

The present invention addresses the problem of excessive loss of power production in amine scrubbing because of the requirement for a large quantity of steam be extracted from the turbine system of the coal-fired power plant. The geothermal heat will replace steam extraction thus allowing for a more efficient use for the geothermal heat. In a separate embodiment the present invention discloses a process configuration for regenerating amine solvent used for C0 ₂ capture at multiple pressure and temperature levels. The solvent passes through two or more stages of different pressures and temperatures where CO ₂ is produced and sent to an appropriate stage of a multistage, intercooled compressor. The lean solvent from each high temperature stage is heat exchanged with the rich solvent from the next lower temperature stage. The vapor from each high temperature stage is heat exchanged with the rich solvent from the next lower temperature stage. A stage may be a simple flash of either the rich or lean solvent, or a more complex embodiment of known methods of stripping such as simple stripper with countercurrent contact of vapor and liquid in packing or trays. Heat must be added at the highest temperature stage and may also be added at any or all of the other stages.

The configuration of the present invention differs from multieffect flashing or stripping in that the majority of the solvent passes through all of the pressure stages. It differs from a simple multistage flash in that the heat exchange is applied between each stage so that there can be a larger temperature difference between stages. It differs from a simple stripper with interheating cross exchange in that the rich and lean sections are at different pressured. It will be especially attractive when used with solvents that can be regenerated at elevated temperatures, up to 160°C.

In simple stripping the vapor from the stripper contains latent heat as water vapor that is usually lost. The configuration of the present invention recovers that heat by exchanging the high pressure vapor with solvent at the lower temperature stages. Furthermore, the heat is input to simple stripping at a fixed temperature level. This innovative configuration allows for heat to be added to a number of different temperature levels. This will be especially attractive for heat recovery from sources such as hot flue gas or compressor intercoolers. It also allows for effective use of geothermal heat with a range of temperatures from 100 to 150°C. The configuration described herein provides for a reduced energy requirement compared to simple stripping.

FIG. 1 shows the most general form of a multipressure flash (100). Rich solution from the absorber is countercurrently exchanged with all available hot streams, lean solvent, high pressure vapor (HPVapor), medium pressure vapor (MPVapor) and low pressure vapor (LPVapor) in exchanger E-4, (110). It flows on to exchanger E-3, (108) and is further heated by the available hot streams; lean, HPVapor, and LPVapor. It is flashed in S-2, (114) to produce MPVapor. The remaining rich liquid is further heated in exchanger E-2, (106) by the hot lean solvent and HPVapor. The rich stream is further heated by a primary source of external heat (104) and flashed at high pressure in separator 1 (S-l), (102) to produce the HPVapor. The hot lean liquid from S-l, (102) is cooled in exchangers E- 2, (106) and E-3, (108) then flashed in S-3, (116) to produce LPVapor. The lean solvent is further cooled in E-4, (110). HPVapor is cooled and water condensed in exchangers E-2, E-3, and E-4, .i.e., (106, 108, and 110). LPVapor is cooled and water condensed in exchangers E-3 and E-4, (108 and 110). HPVapor is cooled and water condensed in exchanger E-5 (not shown). Exchangers E-2, E-3, and E-4, .i.e., (106, 108, and 110) may be multistream, countercurrent exchangers, a combination of countercurrent, or concurrent two stream exchangers intended to approximate multistream coutercurrent exchange. In an even more general configuration the combination of separators S-2 and S-3, i.e., (114 and 116) and exchangers E-3 and E-4, i.e., (108 and 110) may be repeated to create a more complicated repetitive flowsheet with flashes at multiple pressure levels.

The present invention provides multiple regeneration configurations that use wither two or three stages of flash at different temperature and pressure using external heat such as hot brine or steam. FIGS. 3-5 represent flowsheets that illustrate simple versions of regeneration processes that use two stages of flash at different temperature and pressure.

FIG. 3 is a high pressure rich flash followed by low pressure lean flash with recovery of heat from the high pressure vapor. The simple regeneration process (300) in FIG. 3 heats rich amine solution from the absorber (314) in the heat exchanger E-3 (308). The warm rich solution is split into part A and part B. Part A is heated in exchanger E-5 (306) by hot high pressure vapor from separator S-l (302). Part B is heated by low level, option external heat in exchanger E-1 (310), then further heated in exchanger E-3 (308). Parts A and B are combined and heated to the maximum T by a source of external heat such as hot brine or steam (304). The rich stream is separated into a high pressure vapor and semilean solution in separator S-l (302). The semilean solution is cooled in exchanger E-3 (308). Low pressure vapor is separated from lean solution in Separator S-2 (312). The lean solution is cooled to absorber conditions in exchanger E-3 (308). The low and high pressure vapor streams would be cooled to condense water and then fed to appropriate stages of a multistage compressor. This configuration makes good use of the heat in the high pressure vapor. It allows the efficient use of two temperature levels of heat such as geothermal brine or waste heat in exchangers E-1 (310) and E-3 (308).

The process 400 in FIG. 4 replaces exchanger E-5 (306 in FIG. 3) with direct contact of cold rich solution (Part A) with the hot high pressure vapor in a section of packing, trays, or other gas/liquid contacting device (414) in the top of the high pressure separator (S-l) (402). The warm rich solution from the absorber (412) is split into part A and part B. Part A is heated with the hot high pressure vapor in a section of packing, trays, or other gas/liquid contacting device (414) in the top of the high pressure separator (S-l) (402). Part B is heated by low level, option external heat in exchanger E-1 (408), then further heated in exchanger E-3 (406). Parts B is heated to the maximum T by a source of external heat such as hot brine or steam (404). The rich stream is separated into a high pressure vapor and semilean solution in separator S-l (402). The semilean solution is cooled in exchanger E-3 (406). Low pressure vapor is separated from lean solution in Separator S-2 (410). The lean solution is cooled to absorber conditions in exchanger E-3 (406).

In the process 500 depicted in FIG. 5 rich solution is flashed at low pressure and the high pressure flash produces lean solution. Rich amine solution from the absorber is heated in the heat exchanger E-5 (516), E-1 (514), and E-2 (512), then separated in the low pressure separator (S-l) (510) to semirich solution and low pressure vapor. The semirich solution (circulated using a pump 508) is heated in exchanger E-3 (506) and E-4 (504) and separated into lean solution and high pressure vapor in separator S-2 (502). The lean solution is cooled to absorber conditions in exchangers E-3 (506) and E-5 (516). Heat is recovered from the high pressure vapor in exchanger E-l (514). The external heat applied to E-2 (512) is optional and could include geothermal brine, recovered heat from compressor intercooling, and other sources of lower T recovered heat. The single stage flash regeneration system consisting of E-4 (504) and S-2 (502) could be replaced by more complicated solvent regeneration systems including a two-stage isothermal flash, a simple stripper, or an interheated stripper.

FIG. 2 shows the multipressure flash 200 with external heat such geothermal heat introduced at three temperature levels (high, medium, and low) at (204), (224), and (220) respectively. FIG. 2 also illustrates direct contact of Medium T vapor with the Low T flash at the same pressure. Rich solution from the bottom of the absorber is fed to exchanger E-6 (210) where it is heated by exchange with High Pressure Vapor (HPVapor), Low Pressure Vapor (LPVapor), and lean solution. The warm rich solution is further heated in exchanger E-5 (220) by a source of Low T Heat such as the low temperature end or portion of geothermal brine. The rich solution is then flashed in separator S-2 (218) and contacted in packing or trays with LP Vapor from the flash S-3 (214) to produce LPVapor which is exhausted through exchanger E-6 (210). The rich solution continues through a pump (216) into exchanger E-4 (208) where it is further heated by exchange with lean solution from S-3 (214) and HPVapor. The rich solution continues through exchanger E-2 (206) where it is heated by lean solution from S-l (202) and HPVapor from S-l (202). Final heating of the rich solution to its maximum temperature is achieved by High T Heat such as the high temperature end or portion of geothermal brine in exchanger E-l (204). The hot rich solution is flashed in separator S-l (202) to produce HPVapor and lean solution. The lean solution passes back through E-2 (206) and is flashed across a valve (222) and heated with medium T Heat such as the medium temperature portion of geothermal brine in exchanger E-3 (224). The lean solution is flashed in S-3 (214) to produce LPVapor. The lean solution is further cooled through exchanger E-4 (208) and E-6 (210) and is returned to the absorber to pick up more CO ₂ . The LPVapor and HPVapor are then sent to appropriate stages of a multistage, intercooled compressor and compressed to the required pressure for further C0 ₂ processing.

Though the process configurations described hereinabove can use geothermal heat or steam as the external heat source, it will be understood by the skilled artisan that usage of geothermal heat would be much different than using steam because the heat would be supplied from the brine at variable temperature. Steam supplies heat at a single temperature where it condenses. A typical steam reboiler would not make efficient use of geothermal brine because there would be a large approach temperature on the hot side of the exchanger where the brine is supplied, and there would be a pinch on the cold side. From an energy standpoint, the high imbalance of temperature driving forces yields inefficiencies. From the viewpoint of the process itself, a large hot side driving force indicates that the heat source is not being utilized to its maximum capacity; the heat could be used at a higher temperature. Alternatively, using a cross exchanger with the hot brine and cool rich solvent could more effectively take advantage of the high temperature brine by balancing the temperature approach throughout the exchanger. Using a cross exchanger in place of a reboiler is not a matter of simply replacing the processing unit, but the flowsheet must be redesigned to use heat in such a manner.

The present invention describes a form of a multi-stage flash configuration that incorporates cross exchangers to contact hot brine with cool rich solvent to heat the solvent with brine, and the solvent is flashed at two different pressures.

The brine is assumed to be available at 150 °C, so PZ was selected as the solvent to avoid thermal degradation. A rigorous thermodynamic model for PZ in AspenPlus was used in the simulations presented herein. 8 m PZ was simulated in an advanced 2-stage, 2-pressure flash (2T2PFlash) (FIG. 6). The configuration utilized an arrangement of five heat exchangers (602, 604, 606, 608, and 610) to remove heat from brine and the returning lean solvent more reversibly than with single exchangers for each of solvent and brine cross exchanging. The heating in this configuration is different from previous flowsheets in that the rich solvent is fully heated before entering the two adiabatic flash vessels (612 and 614) in series. The first flash had the highest temperature and pressure, and the second flash dropped in both temperature and pressure. The drop in temperature between the high and low pressure flashes was lower than what would be observed in a typical 2-stage flash because heat exchanger 4 was implemented.

All unit operations were modeled with chemical equilibrium within and between the gas and liquid phases. Several conditions were specified to be constant while others were optimized. A constant rich loading of 0.4 mol C0 ₂ /mol alkalinity was specified, which represented a C0 ₂ partial pressure of 5 kPa at 40 °C. The input temperature of the rich solvent coming from the absorber was specified to be constant at 50 °C. The LMTD was 5 °C for all exchangers, and a minimum approach of 1 °C was specified for either side. The temperature difference between flash vessels (612 and 614) was varied to ensure that equal moles of vapor were generated in each flash. This specification was made to maximize the reversibility of the process. The multi-stage compressor work was calculated. The split of solvent between exchangers 2 and 3 was set to 80% toward exchanger 3 (606).

The heat capacity flows of the streams in heat exchanger 1 (602) were mostly balanced, so the hot and cold side temperature approaches were both always approximately the same. Therefore, the outlet temperature of the brine in exchanger 3 (606) was closely connected to the equilibrium temperature in the low-pressure flash. The low-pressure flash temperature was 5 °C higher than the rich outlet in exchanger 1 (602), and this temperature was approximately 5 °C cooler than the cold brine temperature. The geothermal well models required a constant drop in brine temperature of 50 °C between extraction to re-injection, and this stripper design allowed the low-pressure flash temperature to be the manipulated variable to achieve the desired drop in brine temperature. The brine was simulated as pure water, but the final value of importance was the total heat rate of the brine. Simulating the flow of brine ensured that the split of heat rate in exchangers 3 (606) and 5 (610) represented accurate performance with the predicted temperatures. The lean loading was manipulated by varying the brine flow rate. The overall work requirement including the pumps, multi-stage compressor, and heat duty was calculated using equivalent work. For the purpose of the present invention with variable temperature heating, a method was developed to intergrate the work value of the heat between the inlet and outlet temperatures to account for the changing value of heat at different temperatures, which assumed that each unit of heat flow resulted in the same change in temperature along the entire temperature range. The inlet and outlet temperatures in each heater i were T _ij0 and T _ijf , respectively. This integration gave for the heat work:

A comparative configuration 700 was analyzed that used 9 m MEA with a simple stripper (702) and an adiabatic flash (708) on the lean solvent (FIG. 7). MEA represented a rigorous thermodynamic model in AspenPlus. The flowsheet is used in a planned demonstration that is designed for MEA, so the same solvent was selected for this modeling with geothermal heating. The brine heated a reboiler (706) and a rich feed preheater that was added to extract additional heat from the brine. The reboiler (706) had a large hot side approach temperature since the solvent temperature was constant, but this case represented a reconfiguration that could adapt the configuration to use brine if it was already constructed to use steam from the power plant. The only additional process unit would be the cross exchanger (712 and 714) to preheat the rich feed. The same constants were specified as for the 2- stage flash. The rich loading was specified to be 0.5 mol CCVmol alkalinity, representing a CO ₂ partial pressure of 5 kPa at 40°C.

As seen in the process 700 shown in FIG. 7 the rich solution from the absorber is heated in cross exchangers (712) and (714) . The hot rich solution is fed to the top of the stripper packing (702) and flows down through the packing (704) to be heated in the reboiler (706). Lean solution from the reboiler (706) passes through the adiabatic flash (708) at a reduced pressure and then is cooled in the cross-exchanger (712). Hot brine at 150°C is first used to heat the reboiler (706), then the exchanger (714), before returning to the underground formation at 100°C. Vapor from the top of the stripper (702) is fed to a multistage intercooled compressor (716) that removes water and produces C0 ₂ at 150 bar and 40°C.

Geothermal Stripping Results: The stripper was scaled to regenerate enough solvent to treat the flue gas of a 60 MW _e power plant. The flue gas rate and composition from this size power plant was estimated by scaling an industrial estimate. Approximately 1195 ton CCVday would be removed for 60. The lean loading was optimized to minimize the overall work requirement. FIG. 8 is a plot showing the behavior of both equivalent work and total heat duty as a function of lean loading in the 2T2PFlash. The optimum equivalent work was at a lean loading of approximately 0.33, but the heat duty was minimized at a slightly higher lean loading of 0.335. These results were calculated using a rich loading of 0.4, corresponding to a P*co2 of 5 kPa at 40 °C. At the lean loading of 0.33, the equivalent work was 35.1 kJ/mole C0 ₂ .

The P*co2 at 40°C for the optimal lean loading of 0.335 was approximately 0.85 kPa. Solvent concentrations representing a gas side removal of less than 90% might not provide adequate absorber performance since the acceptable loadings were calculated for 90% removal. An overstripped lean solvent would perform well in the absorber because it would have a significant driving force to achieve the desired clean gas purity. Additionally, the lower lean loading would reduce the solvent circulation rate. Conversely, an understripped lean solvent would have trouble attaining the desired purity of 1.2% without using chilled water for cooling or excessive packing. For this reason, the operation point was chosen to have a lean loading of 0.31, where the P*co2 at 40°C was 0.5 kPa. At this lower lean loading, the equivalent work was 35.5 kJ/mole C0 ₂ .

Since the temperature of the extracted brine was expected to decline over the length of the process, the sensitivity of the stripper performance with brine temperature was studied. The change in temperature of the brine across the process was held constant at 50 °C for all extraction temperatures. The base case temperature of 150 °C required 40.8 MW of heat. The expected decrease in brine temperature over a 30 year period was 2°. A reduction in brine temperature from 150 °C to 148 °C would change the heat duty to 41.2 MW, only a 2.4% increase from the design case. An extreme scenario where the brine temperature dropped to 145 °C required 42.4 MW of heat, only 3.7% greater than the design case. If a brine formation that could supply heat at 160 °C was found, the heat duty would decrease to 38.8 MW, a 4.5%o drop from the design case. FIG. 9 displays the increase in heat duty and the equivalent work with decreasing brine temperature. Each simulation converged multiple heat exchange recycle loops at once, and the tolerance set on each recycle loop resulted in a small variability of each point. However, a general negative linear trend was observed.

The adiabatic flash configuration (FIG. 7) with brine heating was also optimized for lean loading with 9 m MEA. The minimum equivalent work was 36.3 kJ/mole CO2 at a lean loading of 0.39, seen in FIG. 10. The overall heating requirement for a 60 MW _e plant was 38.6 MW, a lower heat duty than the 40.8 MW required in the PZ calculation. Previous work demonstrated a similar outcome, where a 2 -stage flash with 8 m PZ had a higher heat duty than a simple stripper with 9 m MEA. Even though the heat duty was less for MEA, the PZ solvent made up in overall performance by operating at a higher pressure, so the 2-stage flash had a significantly smaller compression work. Overall, 9 m MEA had a higher equivalent work requirement than for 8 m PZ. These calculations with MEA used a rich loading of 0.5 with a P*co2 at 40 °C of 5 kPa, and the optimal lean loading of 0.39 had a P*co2 at 40 °C of 0.13 kPa. Therefore, the optimal lean loading was an acceptable range to be coupled with an absorber and expect adequate performance. The difference in proportions of the three work contributions demonstrated that each configuration/solvent combinations could have its own application. Using the 2T2Pflash with 8 m PZ would be advantageous when aiming to minimize the overall energy usage. However, the adiabatic flash configuration with 9 m MEA would be advantageous if electricity was cheap and the goal was to minimize the heat usage as much as possible. The adiabatic flash configuration with 9 m MEA reduced the heat duty from the 2 -stage flash design case by 5.3%.

Another embodiment of the present invention is also a process configuration for regenerating amine solvent used for C0 ₂ capture so that it produces high pressure C0 ₂ without a mechanical compressor. CO ₂ is absorbed at low CO ₂ partial pressure and stripped at 1 to 10 bar by a conventional or multipressure absorption/stripping process. Then the pure CO ₂ is reversibly reabsorbed at ambient temperature (40°C) into the amine solvent at very rich loading, cross-exchanged with hot lean solution, heated to 120-150°C, and flashed to produce CO ₂ at 20 to 50 bar. In one aspect the heat is provided as geothermal heat at 80 to 150°C.

This novelty of the invention lies in the fact that the CO ₂ is reabsorbed and then restripped. The process of the present invention allows the use of heat rather than electricity and mechanical compressors to generate CO ₂ at high pressure. It is especially attractive when using geothermal heat to replace the electricity for C0 ₂ compression. The present invention also provides for a reduced energy requirement and capital cost compared to simple stripping with mechanical compression. The present invention is valuable in processes which capture C0 ₂ from flue gas and for CO ₂ or acid gas removal from other gases where energy efficiency and heat recovery are important. It facilitates the use of geothermal heat, solar heat, and other sources of waste or low temperature heat.

It is contemplated that any embodiment discussed in this specification can be implemented with respect to any method, kit, reagent, or composition of the invention, and vice versa. Furthermore, compositions of the invention can be used to achieve methods of the invention.

It will be understood that particular embodiments described herein are shown by way of illustration and not as limitations of the invention. The principal features of this invention can be employed in various embodiments without departing from the scope of the invention. Those skilled in the art will recognize, or be able to ascertain using no more than routine experimentation, numerous equivalents to the specific procedures described herein. Such equivalents are considered to be within the scope of this invention and are covered by the claims.

All publications and patent applications mentioned in the specification are indicative of the level of skill of those skilled in the art to which this invention pertains. All publications and patent applications are herein incorporated by reference to the same extent as if each individual publication or patent application was specifically and individually indicated to be incorporated by reference. The use of the word "a" or "an" when used in conjunction with the term "comprising" in the claims and/or the specification may mean "one," but it is also consistent with the meaning of "one or more," "at least one," and "one or more than one." The use of the term "or" in the claims is used to mean "and/or" unless explicitly indicated to refer to alternatives only or the alternatives are mutually exclusive, although the disclosure supports a definition that refers to only alternatives and "and/or." Throughout this application, the term "about" is used to indicate that a value includes the inherent variation of error for the device, the method being employed to determine the value, or the variation that exists among the study subjects.

As used in this specification and claim(s), the words "comprising" (and any form of comprising, such as "comprise" and "comprises"), "having" (and any form of having, such as "have" and "has"), "including" (and any form of including, such as "includes" and "include") or "containing" (and any form of containing, such as "contains" and "contain") are inclusive or open-ended and do not exclude additional, unrecited elements or method steps.

The term "or combinations thereof as used herein refers to all permutations and combinations of the listed items preceding the term. For example, "A, B, C, or combinations thereof is intended to include at least one of: A, B, C, AB, AC, BC, or ABC, and if order is important in a particular context, also BA, CA, CB, CBA, BCA, ACB, BAC, or CAB. Continuing with this example, expressly included are combinations that contain repeats of one or more item or term, such as BB, AAA, MB, BBC, AAABCCCC, CBBAAA, CABABB, and so forth. The skilled artisan will understand that typically there is no limit on the number of items or terms in any combination, unless otherwise apparent from the context.

All of the compositions and/or methods disclosed and claimed herein can be made and executed without undue experimentation in light of the present disclosure. While the compositions and methods of this invention have been described in terms of preferred embodiments, it will be apparent to those of skill in the art that variations may be applied to the compositions and/or methods and in the steps or in the sequence of steps of the method described herein without departing from the concept, spirit and scope of the invention. All such similar substitutes and modifications apparent to those skilled in the art are deemed to be within the spirit, scope and concept of the invention as defined by the appended claims.

References

U.S. Patent Application Publication No. 20070284240: System and Method for Diagnosing and Troubleshooting Amine Regeneration System.

U.S. Patent No. 6,547,854: Amine Enriched Solid Sorbents for Carbon Dioxide Capture.