Classifications

• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
  • B01D—SEPARATION
  • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
  • B01D53/34—Chemical or biological purification of waste gases
  • B01D53/46—Removing components of defined structure
  • B01D53/62—Carbon oxides
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
  • B01D—SEPARATION
  • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
  • B01D53/34—Chemical or biological purification of waste gases
  • B01D53/38—Removing components of undefined structure
  • B01D53/40—Acidic components
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
  • B01D—SEPARATION
  • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
  • B01D53/34—Chemical or biological purification of waste gases
  • B01D53/46—Removing components of defined structure
  • B01D53/48—Sulfur compounds
  • B01D53/50—Sulfur oxides
  • B01D53/501—Sulfur oxides by treating the gases with a solution or a suspension of an alkali or earth-alkali or ammonium compound
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
  • B01D—SEPARATION
  • B01D2251/00—Reactants
  • B01D2251/30—Alkali metal compounds
  • B01D2251/304—Alkali metal compounds of sodium
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
  • B01D—SEPARATION
  • B01D2251/00—Reactants
  • B01D2251/40—Alkaline earth metal or magnesium compounds
  • B01D2251/404—Alkaline earth metal or magnesium compounds of calcium
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
  • B01D—SEPARATION
  • B01D2251/00—Reactants
  • B01D2251/60—Inorganic bases or salts
  • B01D2251/604—Hydroxides
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
  • B01D—SEPARATION
  • B01D2257/00—Components to be removed
  • B01D2257/30—Sulfur compounds
  • B01D2257/302—Sulfur oxides
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
  • B01D—SEPARATION
  • B01D2257/00—Components to be removed
  • B01D2257/50—Carbon oxides
  • B01D2257/504—Carbon dioxide
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
  • B01D—SEPARATION
  • B01D2257/00—Components to be removed
  • B01D2257/60—Heavy metals or heavy metal compounds
  • B01D2257/602—Mercury or mercury compounds
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
  • B01D—SEPARATION
  • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
  • B01D53/32—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by electrical effects other than those provided for in group B01D61/00
  • B01D53/323—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by electrical effects other than those provided for in group B01D61/00 by electrostatic effects or by high-voltage electric fields
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
  • B01D—SEPARATION
  • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
  • B01D53/34—Chemical or biological purification of waste gases
  • B01D53/46—Removing components of defined structure
  • B01D53/48—Sulfur compounds
  • B01D53/50—Sulfur oxides
  • B01D53/501—Sulfur oxides by treating the gases with a solution or a suspension of an alkali or earth-alkali or ammonium compound
  • B01D53/505—Sulfur oxides by treating the gases with a solution or a suspension of an alkali or earth-alkali or ammonium compound in a spray drying process
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
  • B01D—SEPARATION
  • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
  • B01D53/34—Chemical or biological purification of waste gases
  • B01D53/74—General processes for purification of waste gases; Apparatus or devices specially adapted therefor
  • B01D53/77—Liquid phase processes
• • Y—GENERAL 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
  • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
  • Y02A—TECHNOLOGIES FOR ADAPTATION TO CLIMATE CHANGE
  • Y02A50/00—TECHNOLOGIES FOR ADAPTATION TO CLIMATE CHANGE in human health protection, e.g. against extreme weather
  • Y02A50/20—Air quality improvement or preservation, e.g. vehicle emission control or emission reduction by using catalytic converters
• • Y—GENERAL 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
  • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
  • Y02C—CAPTURE, STORAGE, SEQUESTRATION OR DISPOSAL OF GREENHOUSE GASES [GHG]
  • Y02C20/00—Capture or disposal of greenhouse gases
  • Y02C20/40—Capture or disposal of greenhouse gases of CO2

Definitions

• the invention relates generally to methods and apparatuses for removing carbon dioxide from a gas stream.
• the invention relates to methods and apparatuses for absorbing carbon dioxide from a coal-fired boiler flue gas stream using an absorbing solution and for regeneration of an alkaline component used in the absorbing solution.
• Certain gaseous or vapor phase pollutants are routinely removed from gas streams emitted by various sources, such as power, chemical, and manufacturing plants, before such gas streams are released into the atmosphere.
• sulfur dioxide is routinely removed from flue gas generated by coal-fired power plants.
• concerns have recently arisen about the release of carbon dioxide into the atmosphere from various sources such as coal-fired power plants.
• carbon dioxide has been identified as a greenhouse gas and as a contributor to global warming. Accordingly, it is desirable to reduce carbon dioxide emissions, for example, by removing it from gas streams emitted by these various sources, such as coal-fired power plants. While there are various technologies available for removing carbon dioxide from a gas stream, improvements in removal efficiency and cost can still be achieved, and new technologies still need to be developed.
• the invention provides methods and apparatuses for removing carbon dioxide from a gas stream.
• the invention provides methods and apparatuses for absorbing carbon dioxide from a coal-fired boiler flue gas stream using an absorbing solution and for regeneration of an alkaline component used in the absorbing solution.
• the invention provides a method for removing carbon dioxide from a gas stream, comprising contacting a gas stream containing carbon dioxide with an alkaline liquid stream; absorbing at least a portion of the carbon dioxide into the alkaline liquid stream to produce absorbed carbon dioxide; and catalyzing a reaction of the absorbed carbon dioxide to a form of carbonate.
• a wet electrostatic precipitator is used to remove the carbon dioxide from the gas stream.
• various modifications to the operation of the wet electrostatic precipitator are used to oxidize and remove elemental mercury from the gas stream.
• the invention provides a method for removing carbon dioxide from a gas stream and producing a carbon dioxide rich gas stream that can be used for other commercial purposes. The invention also provides various apparatuses for use in performing the various methods of the invention.
• Figure 1 illustrates a coal-fired boiler and flue gas treatment process incorporating an embodiment of the present invention
• Figure 2 illustrates a process comprising a carbon dioxide absorber and related process equipment for implementing an embodiment of the present invention
• Figure 2 A illustrates a process comprising a wet electrostatic precipitator as a carbon dioxide absorber and related process equipment for implementing another embodiment of the present invention
• Figure 3 illustrates a series of carbon dioxide absorbers and related process equipment for implementing another embodiment of the present invention
• Figure 4 illustrates a carbon dioxide absorber having a vertical stage and a horizontal stage for implementing another embodiment of the present invention
• Figure 5 illustrates a carbon dioxide absorber with two stages for implementing another embodiment of the present invention
• Figure 5A illustrates another carbon dioxide absorber with two stages for implementing another embodiment of the present invention
• Figure 5B illustrates another carbon dioxide absorber with two stages for implementing another embodiment of the present invention
• Figure 5 C illustrates another carbon dioxide absorber with multiple stages for implementing another embodiment of the present invention
• Figure 6 illustrates a process for the removal of sulfur dioxide and carbon dioxide according to one embodiment of the present invention
• Figure 6 A illustrates another process for the removal of sulfur dioxide and carbon dioxide according to another embodiment of the present invention
• Figure 7 illustrates a process for regenerating reagent for use in an embodiment of the present invention
• Figure 8 illustrates a process for producing gaseous carbon dioxide according to one embodiment of the present invention.
• the invention comprises various methods and apparatuses for removing carbon dioxide from a gas stream using an absorbing solution and for regeneration of an alkaline component used in the absorbing solution.
• the various embodiments are described below in conjunction with the Figures; however, this description should not be viewed as limiting the scope of the present invention. Rather, it should be considered exemplary of various embodiments that fall within the scope of the present invention as defined by the claims.
• the various embodiments of the invention are described below in the context of the removal of carbon dioxide from a flue gas stream generated by a coal-fired boiler.
• the various methods and apparatuses for removing carbon dioxide can be applied to any gas stream generated by any means or from any source.
• FIG. 1 illustrates a coal-fired boiler and flue gas treatment process incorporating an embodiment of the present invention.
• the coal-fired boiler and flue gas treatment process 100 comprises a coal-fired boiler 102 that combusts coal to produce steam for use in generating electricity.
• the combustion process produces a flue gas comprising certain components that need to be removed, at least partially, from the flue gas before it is released into the atmosphere. Some of these components include fly ash or particulate matter, sulfur dioxide, and carbon dioxide, as well as other trace contaminants such as mercury.
• the flue gas exits the boiler 102 through a boiler outlet gas duct 104 that carries the flue gas to a particulate collection device 106.
• the particulate collection device 106 removes at least a portion of the fly ash or particulate matter from the flue gas.
• the particulate collection device 106 may be any device capable of removing the fly ash or particulate matter, such as a wet electrostatic precipitator, a dry electrostatic precipitator, or a baghouse fabric filter. It should be appreciated that the amount of fly ash or particulate matter removal may vary.
• the concentration of the fly ash or particulate matter in the flue gas and the type and operating conditions of the particulate collection device 106, as well as other operating parameters and conditions, may each affect the amount of fly ash or particulate matter removed from the flue gas.
• the flue gas exits the particulate collection device 106 through a particulate collection device outlet gas duct 108 that carries the flue gas to a sulfur dioxide absorber 110.
• the sulfur dioxide absorber 110 removes at least a portion of the sulfur dioxide from the flue gas.
• the sulfur dioxide absorber 110 may be any gas/liquid contactor capable of removing sulfur dioxide from the flue gas, such as a spray tower, tray tower, or a packed bed tower.
• the sulfur dioxide absorber 110 may also be a spray dryer; however, in this case a particulate collection device would be positioned downstream of the spray dryer rather than upstream as shown in Figure 1.
• Various reagents may be used in each of these contactors, including lime and limestone, as well as other additives used in conjunction with these reagents, such as oxidation and pH control additives. It should be appreciated that the amount of removal of sulfur dioxide may vary.
• the concentration of sulfur dioxide in the flue gas and the type and operating conditions of the sulfur dioxide absorber 110, as well as other operating parameters and conditions, may each affect the amount of sulfur dioxide removed.
• the flue gas exits the sulfur dioxide absorber 110 through a sulfur dioxide absorber outlet gas duct 112 that carries the flue gas to a carbon dioxide absorber 114.
• the carbon dioxide absorber 114 removes at least a portion of the carbon dioxide from the flue gas using an alkaline liquid stream or slurry, generally referred to below as an absorbing solution. In some embodiments, 90% or more, 95% or more, or 99% or more of the carbon dioxide is removed.
• the carbon dioxide absorber 114 may be any gas/liquid contactor capable of removing carbon dioxide from the flue gas, such as a spray tower, tray tower, packed bed tower, or a spray dryer, and such gas/liquid contactor may be designed for vertical or horizontal gas flow and for either countercurrent, co-current, or cross-current gas flow relative to the flow of the absorbing solution.
• a wet electrostatic precipitator may also be used as the carbon dioxide absorber, in which case the concurrent removal of both carbon dioxide and sulfur trioxide may be achieved.
• Various embodiments and aspects of the carbon dioxide absorber 114, including its configuration and operation are described further below in connection with Figures 2-6.
• the flue gas exits the carbon dioxide absorber 114 through a carbon dioxide absorber outlet duct 116 that carries the flue gas to a stack 118.
• the flue gas 120 exits the stack 118 where it is discharged to the atmosphere.
• FIG. 2 illustrates a process comprising a carbon dioxide absorber and related process equipment for implementing an embodiment of the present invention.
• the process 200 comprises a carbon dioxide absorber 202, illustrated as a packed bed absorber, that contacts the flue gas with an alkaline liquid stream or slurry, generally referred to as an absorbing solution, to absorb carbon dioxide from the flue gas.
• the packed bed absorber 202 is one example of the carbon dioxide absorber 114 illustrated in Figure 1; however, other absorber designs, such as a spray tower, tray tower, packed bed tower, a spray dryer, or a wet electrostatic precipitator may be used.
• the packed bed absorber 202 comprises a flue gas inlet duct 204, a packed bed 206, a bank of nozzles 208, a mist eliminator 210 positioned above the packed bed 206 and the nozzles 208, and a flue gas outlet duct 212.
• the packed bed absorber 202 or any other absorber design, including a wet electrostatic precipitator may be used to remove carbon dioxide from other types of gas streams and is not limited to use with flue gas streams from coal- fired boilers.
• the packed bed 206 may be any packed bed known in the art, including any packing material known in the art, that provides sufficient gas/liquid contact between the flue gas and the absorbing solution. In some embodiments, high efficiency packing with low pressure drop across the packing may be used to minimize the size and operating costs of the packed bed.
• the nozzles 208 may also be any type of nozzle or any other equipment capable of distributing an absorbing solution over the packed bed 204.
• a gas 209 from a gas source 211 optionally may be injected through a gas manifold 213 into the bottom of the packed bed 206 to provide agitation to the gas and liquid in the packed bed 206, thereby increasing the amount of contact between the gas and the liquid.
• This gas 209 may be a compressed gas, such as compressed ambient air, or any other gas provided such gas does not deleteriously affect the operation of the packed bed 206 or the carbon dioxide absorber 202.
• the mist eliminator 210 may also be any mist eliminator design known in the art, including a wet electrostatic precipitator.
• the bottom of the packed bed absorber 202 serves as a reaction tank 216 that collects the absorbing solution 218.
• An absorbing solution recirculation pump 220 is used to recirculate the absorbing solution 218 through a recirculation line 222 that extends from the reaction tank 216 to the nozzles 208.
• a blow-down pump 224 is used to discharge a portion of the absorbing solution 218 from the reaction tank 216 through a discharge or blowdown line 226.
• the reaction tank 216 may or may not be integral to the packed bed absorber.
• the size of the reaction tank 216 can be designed to provide the desired residence time for the absorbing solution.
• the reaction tank may be designed to provide a residence time of approximately 3 to approximately 15 minutes.
• the residence time is approximately 10 to approximately 15 minutes.
• the residence time is approximately 10 minutes.
• a reagent feed tank 228 is used to hold an alkaline reagent 230 that is added to the absorbing solution.
• a reagent feed pump 232 is used to feed the reagent 230 to the reaction tank 216 through a reagent feed line 234.
• Chemical feed tanks 236, 238 are used to hold various chemical solutions 240, 242, respectively, that are added to the reagent 230 in the reagent feed tank 228 through chemical feed lines 244, 246, respectively.
• one of the chemical solutions 240 comprises an alkaline component that is added to the reagent feed tank 228 to provide the reagent 230 with its alkalinity.
• one component of the reagent 230 is an alkaline component. Accordingly, as the reagent 230 is fed to the reaction tank 216, the alkaline component will also be added to the absorbing solution 218.
• additional process equipment such as surge tanks, necessary to maintain an appropriate pressure head for the various pumps, may also be used.
• a flue gas 248 comprising carbon dioxide, such as a flue gas from a coal-fired boiler, enters the packed bed absorber 202 at the flue gas inlet duct 204 and travels through the packed bed 206, through the mist eliminator 210, and through the flue gas outlet duct 212.
• the absorbing solution 218 is continuously pumped from the reaction tank 216 through the recirculation line 222 using the absorbing solution recirculation pump 220 to deliver the absorbing solution to the bank of nozzles 208.
• the absorbing solution 218 As the absorbing solution 218 exits the nozzles 208, the absorbing solution 218 is distributed over the top of the packed bed 206. The absorbing solution 218 travels through the packed bed 206 and is collected in the reaction tank 216 at the bottom of the packed bed absorber 202.
• the direction of gas flow and the direction of flow of the absorbing solution are countercurrent.
• the relative direction of the gas flow and absorbing solution flow may be co-current or cross-current depending upon the absorber design.
• the gas flow may also be vertical (upward or downward) or horizontal relative to the ground depending upon the absorber design.
• the flow rate of the absorbing solution 218 through the packed bed absorber 202 can be changed depending upon the desired amount of carbon dioxide to be removed from the flue gas 248. A relatively higher removal percentage of carbon dioxide removal can be achieved by increasing the flow rate of the absorbing solution 218 through the packed bed absorber 202. Other factors that will affect the amount of carbon dioxide removal include the flow rate of the flue gas 248, the concentration of carbon dioxide in the flue gas 248, and the sufficiency of contact between the flue gas 248 and the absorbing solution 218 or the mass transfer characteristics of the packed bed absorber 202.
• the flow rate of the absorbing solution can be determined to provide a given amount of carbon dioxide removal or rate of carbon dioxide removal.
• the ratio of the flow rate of the absorbing solution 218 to the flow rate of the flue gas 248 is referred to as the "L/G" ratio.
• this ratio is expected to be within the range of approximately 3 to approximately 20 and for some other embodiments this ratio is expected to be within the range of approximately 6 to approximately 15.
• the L/G ratio may be approximately 15.
• the L/G ratio will be different for different carbon dioxide absorber designs and operating parameters.
• the L/G ratio will need to be considered in the design of the size of the reaction tank 216 since it will affect the residence time of the absorbing solution 218 in the reaction tank 216.
• the pH of the absorbing solution 218 will decrease as more and more carbon dioxide is absorbed. Therefore, it is desirable to use an absorbing solution 218 that is alkaline to increase the capacity of the absorbing solution to absorb carbon dioxide. In addition, it is desirable to maintain and control the amount of alkalinity in the absorbing solution 218 as carbon dioxide is absorbed. In one embodiment, the amount of alkalinity in the absorbing solution 218 is determined using a pH measurement, and the amount alkalinity in the absorbing solution 218 is maintained by controlling the pH of the absorbing solution 218 at a predetermined value as described below.
• the amount of alkalinity and, therefore, the pH to be maintained in the absorbing solution may vary depending upon a variety of factors, including, for example, the concentration of the carbon dioxide in the flue gas 218, the desired amount of carbon dioxide removal from the flue gas 218, and the actual amount of carbon dioxide removed.
• the pH of the absorbing solution 218 is controlled at approximately 7.0 or greater and in some embodiments between approximately 8.0 to approximately 11.0.
• the pH of the absorbing solution is controlled at approximately 8.3 or greater, approximately 8.5 or greater, or between approximately 8.3 to approximately 8.5.
• the pH of the absorbing solution 218 is controlled by the addition of the alkaline reagent 230 to the absorbing solution 218, which is done by feeding the reagent 230 to the reaction tank 216 based upon a pH feedback control loop (not shown).
• the pH of the absorbing solution 218 is measured, and, as the pH drops below a predetermined value, the reagent 230 is added to the absorbing solution 218 via the reaction tank 216.
• the pH may be measured in the reaction tank 216 or in the recirculation line 222.
• the reagent 230 may be added to the recirculation line 222.
• the alkaline reagent 230 comprises at least water and an alkaline component and, in one embodiment, may be generated by mixing water and the alkaline component in the reagent feed tank 228.
• the alkaline component may be any alkaline chemical or mixture of alkaline chemicals that will provide alkalinity to the absorbing solution 218 and thereby allow for control of the pH of the absorbing solution.
• the alkaline component is sodium hydroxide.
• the alkaline component is calcium hydroxide.
• the alkaline component may be either sodium hydroxide, calcium hydroxide, and an additional alkaline chemical or a mixture of any of the foregoing.
• the alkaline component may be magnesium hydroxide or potassium hydroxide or any combination of any of the foregoing alkaline components.
• the alkaline component may be held in one of the chemical feed tanks 236 and added to the reagent feed tank 228 when necessary. In other words, whenever reagent 230 is needed, or if the amount of reagent 230 in the reagent feed tank 228 has fallen below a predetermined level, water and the alkaline component may be added to the reagent feed tank 228 and mixed to produce the reagent 230.
• the concentration of the alkaline component in the reagent 230 may vary depending upon various factors, including the amount of carbon dioxide removal and the corresponding rate at which the reagent 230 must be added to the absorbing solution 218 to maintain a given pH, as well as the overall material balance, including the water balance, of the overall process 200 or the process in which the packed bed absorber 202 is used, such as the process shown in Figure 1.
• the concentration of sodium hydroxide in the reagent may range from approximately 0.1 Normal to approximately 4 Normal.
• the concentration of the calcium hydroxide solids in the reagent may range from approximately 10% by weight solids to approximately 12% by weight solids. [0039] Accordingly, the concentration of the alkaline component 240 in the chemical feed tank 236 can also be adjusted depending upon these same factors. In some embodiments wherein the alkaline component comprises sodium hydroxide, the concentration of the sodium hydroxide 240 in the chemical feed tank 236 may range from approximately 0.1 Normal to approximately 4 Normal sodium hydroxide or greater and in other embodiments from approximately 1 Normal to approximately 2 Normal sodium hydroxide.
• the solution in the chemical feed tank 236 will be a slurry comprising calcium hydroxide solids at a concentration that may range from approximately 10% by weight solids to approximately 12% by weight solids or greater.
• the absorbing solution will also contain solids and may be referred to as a slurry.
• the absorbed carbon dioxide gas reacts with water to form carbonic acid followed by the liquid phase reactions with the sodium hydroxide to form a mixture of both sodium bicarbonate (Eq. 2) and sodium carbonate (Eq. 3).
• Eq. 2 sodium bicarbonate
• Eq. 3 sodium carbonate
• Equation (4)-(6) the absorption of carbon dioxide and its reaction with the absorbing solution 218 comprising calcium hydroxide is shown by Equations (4)-(6):
• the absorbed carbon dioxide gas reacts with water to form carbonic acid followed by the liquid phase reactions with dissolved calcium hydroxide to form a mixture of both calcium bicarbonate (Eq. 2) and calcium carbonate (Eq. 3). While these reactions are reversible, at a pH of approximately 8.2 to approximately 8.3 there is a reduced amount of carbonic acid in the absorbing solution, as Equation (2) is shifted in favor of the formation of calcium bicarbonate. Accordingly, at this pH range and higher there would be little to no off-gassing of carbon dioxide. [0042] Once the process 200 reaches steady-state operation, the absorbing solution 218 will contain certain concentrations of bicarbonate and carbonate ions and the corresponding cations depending upon the alkaline component used.
• the absorbing solution 218 will also comprise solids. Also, it should be appreciated that the absorbing solution 218 may also comprise other chemicals in significant or trace concentrations depending upon such factors as the amount of particulate matter or fly ash and other gaseous species removed by the packed bed absorber 202 from the flue gas 248 and the amount of other chemicals that enter the system with the reagent 230 or water used in the reagent 230. Therefore, the absorbing solution 218 may contain other liquid phase chemicals as well as other solids.
• alkaline liquid stream and "absorbing solution” are intended to include liquid streams, as well as liquid streams comprising solids, such as slurries.
• water is produced by the absorption of carbon dioxide, as shown in Equations 2 and 3 and Equations 4 and 5 above.
• the chemical components in the absorbing solution it may be possible to reuse this generated or excess water, depending upon the overall water balance of the process.
• a portion of the absorbing solution that is discharged from the reaction tank as blowdown may be used as make-up water.
• the absorbing solution may also be filtered and chemically treated to provide water having an acceptable chemical composition for use elsewhere.
• one of the chemical feed tanks 238 may be used to hold a catalyst 242 that is optionally added to the reagent feed tank 230 and fed to the absorbing solution 218 with the reagent 230.
• This catalyst 242 is used to catalyze the absorption of carbon dioxide.
• the carbon dioxide absorption rate is limited more by the relatively low rate of reaction of the carbon dioxide in the liquid phase after it has been absorbed than by its diffusion rate through the gas film and the gas-liquid interface. Therefore, the reaction rate within the liquid phase is increased by the use of catalyst.
• the catalyst increases the rate of reaction of the carbonic acid and the bicarbonate with the alkaline component, as shown by Equations (2) and (3) and Equations (5) and (6) above.
• the catalyst may be any catalyst that increases the rate of absorption of carbon dioxide.
• the catalyst comprises a monosaccharide, such as levulose or dextrose.
• the catalyst comprises a disaccharide, such as sucrose and lactose.
• the catalyst comprises an alcohol, such as ethylene glycol, glycerol, methyl alcohol, and ethyl alcohol.
• the catalyst comprises an aldehyde, such as formaldehyde.
• the catalyst comprises a mixture of any of a monosaccharide, a disaccharide, an alcohol, and an aldehyde.
• the catalyst comprises sucrose, dextrose, ethanol, methanol, ethylene glycol, levulose, glycerol, lactose, and any mixture or combination of any of the foregoing.
• the catalyst may comprise an enzyme that catalyses the conversation of carbon dioxide to bicarbonate or other products.
• carbonic anhydrase which is a family of metalloenzymes or enzymes containing one or more metals or other functional components at an active site, may be used.
• the metals may include cadmium, zinc, or other ions, and may include mixtures of these metals and ions as well.
• the catalyst may be added to the reagent feed tank 228 from a chemical feed tank 238.
• the catalyst may be added directly to the reaction tank 216, directly to the recirculation line 222 separately from the reagent feed line 234, or directly to the alkaline component 240 being held in one of the chemical feed tanks 236.
• the concentration of catalyst necessary in the absorbing solution 218 is any amount that improves the rate of removal of carbon dioxide removal from the flue gas 248, which can be determined simply by measuring the amount of carbon dioxide removal across the packed bed absorber 202.
• the actual concentration of the catalyst in the absorbing solution 218 may not need to be measured, as one of skill in the art will appreciate that various concentrations of the catalyst in the chemical feed tank 238 and various rates of addition of the catalyst to either the reagent feed tank 230 or to the reaction tank 216 or the recirculation line 222 may be used to determined the absolute amount and rate of catalyst that needs to be fed to the absorbing solution 218 to enhance the rate of carbon dioxide removal. In some embodiments, the concentration of the catalyst is approximately 0.01% to approximately 1.0% of the absorbing solution. [0047] As the process 200 continues to operate, the absorbing solution 218 is recirculated multiple times or makes multiple passes through the absorber 202.
• the rate at which the absorbing solution 218 is recirculated is determined by the desired L/G ratio, as described above. During each pass, an additional increment of carbon dioxide is absorbed resulting in the formation of more bicarbonate and carbonate that must be removed from the absorption solution and replaced by the addition of reagent and fresh alkaline component to maintain the a desired reactivity or alkalinity of the absorbing solution. This is accomplished by discharging a portion of the absorbing solution 218 through the blowdown line 226 at a selected rate. This rate will depend upon the removal rate of carbon dioxide and the corresponding increase in concentration of reaction products such as bicarbonates and carbonates and the overall system water balance.
• This discharge or blowdown stream ultimately may be passed to a set of hydroclones and thickeners or to a storage tank (not shown) for ultimate disposal.
• the blowdown stream will contain potassium ions, which may make the blowdown stream saleable in the fertilizer industry, for example, as a soil amendment.
• This stream may be either sold in its current form or water may be evaporated to concentrate the potassium ions and minimize transportation costs.
• the blowdown stream comprising potassium ions may by sent to an evaporation pond where the water is evaporated and the remaining solids are scraped together and sold.
• the hydroclones and thickeners are particularly useful for those embodiments in which solids are present in the absorbing solution, such as systems using calcium hydroxide as the alkaline component.
• the blowdown stream will also contain solids, including carbonate solids, that can be separated from the liquid phase to allow disposal of the solids and liquids separately.
• the resulting solids may be washed to remove residual liquid from the absorbing solution and to remove certain dissolvable chemicals from the solids. Washing of the solids may provide solids having a given chemical composition necessary for disposal or possible sale.
• the blowdown stream will comprise calcium carbonate solids, which can be used in roadbed construction and in the manufacture of cement and concrete. It should be appreciated that the concentration of the catalyst in the blowdown stream will be relatively low since the concentration in the absorbing solution 218 is also relatively low. Therefore, disposal of the blowdown stream comprising a low concentration of catalyst should not present any particular disposal issues.
• FIG. 2A illustrates a process comprising a wet electrostatic precipitator as a carbon dioxide absorber and related process equipment for implementing another embodiment of the present invention.
• This embodiment is similar to that shown in Figure 2, except that a wet electrostatic precipitator 207 is used in the absorber 202 in place of the packed bed 206.
• a wet electrostatic precipitator 207 is used in the absorber 202 in place of the packed bed 206.
• One advantage of using a wet electrostatic precipitator for the removal of carbon dioxide is that sulfur trioxides may also be removed. It is well known in the industry that sulfur trioxides are not removed in the particulate collection device 106 or the sulfur dioxide absorber 110, and as a result are exhausted through the stack 118.
• a wet electrostatic precipitator uses a high voltage, direct current field of between 45,000 volts to 60,000 volts applied to discharge electrodes to ionize the flue gas, producing a corona around these electrodes. Each discharge electrode is enclosed within a tubular collection electrode that is connected to ground.
• pollutants including sulfur trioxides, imparting a charge to these and causing them to migrate to the collecting electrodes.
• pollutants including sulfur trioxides, imparting a charge to these and causing them to migrate to the collecting electrodes.
• pollutants are flushed from the electrodes by a film of water, effectively removing them from the flue gas.
• a wet electrostatic precipitator may be used to oxidize and absorb vaporous mercury in the flue gas.
• the corona if created by oscillating the power supply to the electrodes between an alternating current and a direct current
• the use of a wet electrostatic precipitator may provide the advantage of removing carbon dioxide, sulfur trioxides, and mercury from a flue gas stream.
• the absorber 202 and all of the related equipment is the same as that shown in Figure 2, except, as noted, that the absorber 202 comprises a wet electrostatic precipitator 207 instead of a packed bed 206.
• the absorbing solution 218 is distributed over the top of the wet electrostatic precipitator 207, and carbon dioxide is absorbed as the absorbing solution 218 travels through the wet electrostatic precipitator 207.
• FIG. 3 illustrates a series of carbon dioxide absorbers and related process equipment for implementing another embodiment of the present invention.
• two carbon dioxide absorbers 302, 304 shown as packed bed absorbers, are used in series to remove carbon dioxide in two stages from a gas stream 306.
• the gas stream 306 comprising carbon dioxide enters the first packed bed absorber 302, where a portion of the carbon dioxide is removed from the gas stream 306.
• the gas stream 306 is passed to the second absorber 304 where an additional portion of the carbon dioxide is removed from the gas stream 306.
• Each of the packed bed absorbers 302, 304 are similar to that described in connection with Figure 2.
• gas may be injected below each of the packed beds in each of the packed bed absorbers 302, 304.
• the operation of each of the packed bed absorbers 302, 304 is similar to that described in connection with Figure 2, including the optional use of a catalyst.
• any type of gas/liquid contactor may be substituted for one or both of the packed bed absorbers 302, 304 shown in Figure 3.
• One advantage of using a series of carbon dioxide absorbers is the ability to increase the amount of carbon dioxide removal. For example, if greater than 90%, or greater than 95%, or greater than 99% carbon dioxide removal is desired, the use of two carbon dioxide absorbers in series may be used to obtain such high removal percentages.
• the reagent used in each carbon dioxide absorber can be the same or different by using the same or different alkaline component.
• the alkaline component 308 for the first packed bed absorber 302 may be calcium hydroxide
• the alkaline component 310 for the second packed bed absorber 304 may be sodium hydroxide.
• the reagents 312, 314 and the corresponding absorption solutions 316, 318 would have different compositions.
• each packed bed absorber 302, 304 may be the same (e.g., both may be sodium hydroxide or both may be calcium hydroxide), thereby giving the reagents 312, 314 and the absorption solutions 316, 318 the same composition, noting, however, that the quantity of carbon dioxide removal in each packed bed absorber 302, 304 may also affect the composition of the absorption solutions 316, 318.
• a catalyst may be used in both of the packed bed absorbers 302, 304 or in one absorber only.
• each packed bed absorber 302, 304 can be configured to add catalyst to the reagent feed tanks 320, 322 using chemical feed tanks 324, 326.
• the specific catalyst selected for use may be the same or different in each packed bed absorber 302, 304.
• different catalysts may be used with different reagents or alkaline components. For example, a given catalyst may be used with calcium hydroxide as the alkaline component in the first packed bed absorber 302 and either that same catalyst or a different catalyst may be used with sodium hydroxide as the alkaline component in the second packed bed absorber 304.
• the same catalyst and the same alkaline component may be used in both packed bed absorber 302, 304, or all four of these components may be different.
• any combination of alkaline components and reagents may be used with any of the catalysts or combination of catalysts, and any of these combinations may be used in the first or second carbon dioxide absorber.
• a further advantage of using two carbon dioxide absorbers is that the first absorber may be used to remove any residual sulfur dioxide from a gas stream prior to removing carbon dioxide.
• a sulfur dioxide absorber may be used to remove sulfur dioxide from a flue gas stream generated by a coal-fired power plant.
• the first carbon dioxide absorber may be used to remove additional sulfur dioxide, as well as a portion of the carbon dioxide.
• the remaining carbon dioxide desired to be removed from the flue gas can be removed in the second carbon dioxide absorber.
• the alkaline component of the reagent in the first carbon dioxide absorber is used for both sulfur dioxide and carbon dioxide removal.
• FIG. 4 illustrates a carbon dioxide absorber having a vertical stage and a horizontal stage for implementing another embodiment of the present invention.
• a single carbon dioxide absorber 402 having two separate absorption sections 404, 406 is used to provide two stages for carbon dioxide removal.
• a gas stream 408 comprising carbon dioxide enters the carbon dioxide absorber 402 and passes through the first or upstream absorption section 404 where a portion of the carbon dioxide is removed. The gas stream 408 then passes through the second or downstream absorption section 406 where an additional portion of the carbon dioxide is removed.
• the first or upstream absorption section 404 comprises a packed bed and the second or downstream absorption section 406 simply comprises an area in which absorption solution is sprayed into the gas stream through a bank of nozzles 410.
• gas may be injected below the packed bed of the first absorption section 404.
• the absorption solution in the second absorption section 406 is collected by a mist eliminator 412 and recycled to the bank of nozzles 410 through recycle line 414, from which a discharge or blowdown stream 416 may be taken. It should be appreciated, however, that any type of gas/liquid contact equipment can be used in each of these sections.
• the first absorption section 404 may be a spray tower and the second absorption section may be a packed bed. Similar to the use of two carbon dioxide absorbers described in connection with Figure 3, each absorption section may use the same or different alkaline component 418, 420 in the reagent 422, 424. Also, catalysts 426, 428 may be added separately to either of the absorption sections 404, 406 with the reagents 422, 424 or by any other means as described above in connection with Figure 2. Further, all of the various combinations of catalyst and alkaline components as described above in connection with Figure 3 may be used as well for each absorption section 404, 406.
• this process 400 also allows for the combined removal of sulfur dioxide and carbon dioxide in the first stage or first absorption section 404.
• the operation of this carbon dioxide absorber 402, including recirculation of the absorption solution and blowdown operations, is similar to those described in connection with Figure 2 and 3.
• Figure 5 illustrates a carbon dioxide absorber with two stages for implementing another embodiment of the present invention.
• the carbon dioxide absorber 502 and related process equipment is similar to that shown in Figure 2 with the exception that the carbon dioxide absorber 502 comprises two absorption sections 504, 506.
• both absorption sections 504, 506 are designed for operation without a change in gas flow direction between the absorption sections 504, 506.
• a gas stream 508 comprising carbon dioxide enters the carbon dioxide absorber 502 and passes through the first or upstream absorption section 504 where a portion of the carbon dioxide is removed.
• the gas stream 508 then passes through the second or downstream absorption section 506 where an additional portion of the carbon dioxide is removed.
• the first or upstream absorption section 504 is shown as a packed bed.
• gas may be injected below the packed bed of the first absorption section 504 to increase the amount of contact between the gas and the liquid in the packed bed.
• the second or downstream absorption section 506 comprises a spray area into which absorption solution is sprayed into the gas 508 from a bank of nozzles 510.
• the absorption solution in this section 506 is collected by a collection device 512 and recycled to the bank of nozzles 510 through recycle line 514, from which a discharge or blowdown stream 516 may be taken.
• a tank (not shown) may be necessary to hold the absorbing solution after it is collected and before it is recycled to the bank of nozzles 510.
• the collection device 512 may be any device capable of collecting the absorption solution or separating it from the gas stream, such as a funnel. It should be appreciated, however, that any type of gas/liquid contact equipment can be used in each of these sections and in any combination.
• the first absorption section 504 may be a spray tower or a tray tower and the second absorption section 506 may be a packed bed, or both absorption sections may utilize the same type of gas/liquid contact equipment such as spray towers or sprays of absorbing solution or packed beds.
• each absorption section may use the same or different alkaline component 518, 520 in the reagent 522, 524.
• catalysts 526, 528 may be added separately to either of the absorption sections 504, 506 with the reagents 522, 524 or by any other means as described above in connection with Figure 2. Further, all of the various combinations of catalyst and alkaline components as described above in connection with Figure 3 may be used as well for each absorption section 504, 506. However, it should be appreciated that the use of calcium hydroxide as the alkaline component may result in some scaling inside the carbon dioxide absorber 502. Therefore, if scaling is an issue during operation, it may be preferable to avoid the use of calcium hydroxide in the second absorption section 506. Also, similar to the operation of the process 300 described in Figure 3, this process 500 also allows for the combined removal of sulfur dioxide and carbon dioxide in the first stage or first absorption section 504.
• FIG. 5A illustrates another carbon dioxide absorber with two stages for implementing another embodiment of the present invention.
• the carbon dioxide absorber 502 and related process equipment are similar to that shown in Figure 2 with the exception that the carbon dioxide absorber comprises two absorption sections 530, 532.
• the carbon dioxide absorber 502 and the two absorption sections 530, 532 are designed for operation without a change in the direction of gas flow.
• a gas stream 508 comprising carbon dioxide enters the carbon dioxide absorber 502 and passes through the first or upstream absorption section 530 where a portion of the carbon dioxide is removed. The gas stream 508 then passes through the second or downstream absorption section 532 where an additional portion of the carbon dioxide is removed.
• the first or upstream absorption section 530 comprises a wet electrostatic precipitator 534
• the second or downstream absorption section 532 comprises a packed bed 536.
• gas may be injected below the packed bed 536 of the second absorption section 532 to increase the amount of contact between the gas and the liquid in the packed bed 536.
• the absorbing solution is pumped to a bank of nozzles 538 and distributed over the packed bed 536.
• the absorbing solution travels through the packed bed 536 and passes to the wet electrostatic precipitator 534.
• the absorbing solution then travels through the wet electrostatic precipitator 534.
• a portion of the carbon dioxide in the gas stream 508 is removed by the absorbing solution passing through the wet electrostatic precipitator 534 in a counter-current manner.
• the gas stream 508 passes through the packed bed 536, where an additional portion of carbon dioxide is removed from the gas stream 508.
• the absorbing solution is only introduced into the carbon dioxide absorber at one location, namely downstream of the second absorption section 532.
• any alkaline component or combination of alkaline components, with or without a catalyst or mixture of catalysts, may be used in this process 500A. Also, operation of this process 500A, including recirculation of the absorption solution and blowdown operations, is similar to that described in connection with Figure 2.
• Figure 5B illustrates another carbon dioxide absorber with two stages for implementing another embodiment of the present invention.
• This process 500B is similar to that described in Figure 5A, with the exception that the upstream absorption section 540 comprises a packed bed 542 and the downstream absorption section 544 comprises a wet electrostatic precipitator 546.
• gas may be injected below the packed bed 542 of the upstream absorption section 540 to increase the amount of contact between the gas and the liquid in the packed bed 542.
• the operation of this configuration is similar to that described in Figure 5 A, wherein the absorbing solution is introduced at a single location in the carbon dioxide absorber 502 that is downstream of the downstream absorption section 544.
• the absorbing solution is pumped to a bank of nozzles 538 and passed to, in this case, the wet electrostatic precipitator 546.
• the absorbing solution travels through the wet electrostatic precipitator 546 and passes to the upstream absorption section 540 and the packed bed 542.
• the absorbing solution then travels through the packed bed 542. Accordingly, as the gas stream 508 passes through the packed bed 542, a portion of the carbon dioxide in the gas stream 508 is removed by the absorbing solution passing through the packed bed 542. After exiting the packed bed 542, the gas stream 508 passes through wet electrostatic precipitator 546, where an additional portion of carbon dioxide is removed from the gas stream 508. It should be appreciated that using a wet electrostatic precipitator as the final downstream absorption section may reduce the need for a mist eliminator further downstream depending upon the amount of mist in the gas stream that needs to be removed before the gas exits the carbon dioxide absorber 202.
• any alkaline component or combination of alkaline components, with or without a catalyst or mixture of catalysts, may be used in this process 500B. Also, operation of this process 500B, including recirculation of the absorption solution and blowdown operations, is similar to that described in connection with Figure 2.
• FIG. 5 C illustrates another carbon dioxide absorber with multiple stages for implementing another embodiment of the present invention.
• This process 500C is similar to those described in Figures 5A and 5B, with the exception that there are essentially three absorption sections 550, 552, 554 created by the use of a packed bed 556 positioned within a wet electrostatic precipitator 558. It should be appreciated that although the packed bed 556 is disposed between the two sections of the wet electrostatic precipitator 558, both of these sections are electrically connected such that they function as a single wet electrostatic precipitator. In other words, both sections are operated as a single wet electrostatic precipitator even though they are physically separated by the packed bed 556.
• gas may be injected below the packed bed 556 to increase the amount of contact between the gas and the liquid in the packed bed 556.
• the absorbing solution is introduced at a single location in the carbon dioxide absorber 502 that is downstream of the last absorption section 554.
• the absorbing solution is pumped to a bank of nozzles 538 and passed to the downstream portion of the wet electrostatic precipitator 558.
• the absorbing solution exits the downstream portion of the wet electrostatic precipitator 558 and passes through the packed bed 556 in the middle absorption section 552.
• the absorbing solution exits the packed bed 556 and passes to and through the upstream portion of the wet electrostatic precipitator 558.
• a portion of the carbon dioxide in the gas stream 508 is removed by the absorbing solution passing through that portion of the wet electrostatic precipitator 558 in the upstream absorption section 550.
• the gas stream 508 passes through the packed bed 556, where an additional portion of carbon dioxide is removed from the gas stream 508 in the middle absorption section 552.
• the gas stream 508 passes through the downstream portion of the wet electrostatic precipitator 558, where yet an additional portion of carbon dioxide is removed from the gas stream 508 in the final absorption section 554.
• a wet electrostatic precipitator as the final downstream absorption section may reduce the need for a mist eliminator further downstream depending upon the amount of mist in the gas stream that needs to be removed before the gas exits the carbon dioxide absorber 202.
• any alkaline component or combination of alkaline components, with or without a catalyst or mixture of catalysts, may be used in this process 500C.
• a carbon dioxide absorber may have more than two absorption sections.
• the absorber may have multiple banks of spray nozzles that each deliver absorbing solution to different locations or positions within the absorber.
• three or more banks of spray nozzles positioned at different heights along the absorber may be used.
• sulfur dioxide absorber may be needed upstream of the carbon dioxide absorber.
• the sulfur dioxide absorber is being used to remove a relatively small amount of sulfur dioxide, compared to, for example, a full-scale flue gas desulfurization system, and may be referred to as a sulfur dioxide polisher.
• a generic acid gas absorber may also be used to simply remove a relatively small concentration of acid gas that may otherwise interfere with the carbon dioxide removal process.
• FIG. 6 illustrates a process for the removal of sulfur dioxide and carbon dioxide according to one embodiment of the present invention.
• a sulfur dioxide absorber 602 receives a gas stream 604 that contains both sulfur dioxide and carbon dioxide.
• this gas stream 602 may be an gas stream exiting from an upstream sulfur dioxide absorber or flue gas desulfurization system, in which case the sulfur dioxide absorber 600 shown in Figure 6 may be used to remove additional sulfur dioxide, thereby polishing the gas stream prior to removing carbon dioxide.
• the gas stream 604 may be from a process that generates a relatively low concentration of sulfur dioxide or other acid gases.
• the sulfur dioxide absorber 602 may be any type of gas/liquid contactor, such as those described above for the carbon dioxide absorbers. Further any configuration of gas flow relative to liquid flow may be used, as also described above for the carbon dioxide absorbers.
• the gas stream 604 travels through the sulfur dioxide absorber 602 where it is contacted with a sulfur dioxide absorbing solution 606 to remove sulfur dioxide from the gas stream 604.
• the gas stream then passes from the sulfur dioxide absorber 602 to the carbon dioxide absorber 608, where it is contacted with another absorbing solution 610.
• the gas stream then passes from the carbon dioxide absorber 610 through a carbon dioxide absorber outlet duct 612 for discharge.
• the absorbing solution 606 may be any alkaline solution capable of removing sulfur dioxide from the gas stream 604.
• the absorbing solution 606 is passed to the sulfur dioxide absorber 602 from a reagent tank 614 using a reagent feed pump 616.
• the sulfur dioxide absorber 602 is directed to use as a polisher, significantly high removal rates of sulfur dioxide can be achieved using a highly alkaline absorbing solution 606.
• the absorbing solution may comprise alkaline components such a sodium or calcium hydroxide.
• the concentration of the alkaline component in the absorbing solution 606 or its pH can be set depending upon the amount of sulfur dioxide removal desired. It should be appreciated that other acid gases may also be removed using this absorber 602, and other components may be added to the reagent feed tank 614 to assist in the removal of these acid gases.
• the absorbing solution 606 passes from the sulfur dioxide absorber 602 to a reaction tank 618, which in this embodiment also serves as a reagent feed tank for the carbon dioxide absorber 608, as discussed further below.
• the absorbing solution 606 only passes through the sulfur dioxide absorber one time.
• the reaction tank 618 does not have to serve as the reagent feed tank for the carbon dioxide absorber 608, since a separate reagent feed tank, as described above in connection with any of the carbon dioxide absorbers also described herein, can be used. Further, the reaction tank 618 may also be integral to the sulfur dioxide absorber.
• the carbon dioxide absorber 608 may be any of the carbon dioxide absorbers described herein and may be operated in any of the same manners described herein.
• the reaction tank 618 for the sulfur dioxide absorber acts as a reagent feed tank for the carbon dioxide absorber 608, the alkaline components for carbon dioxide absorption may be added to either the reagent feed tank 614 or the reaction tank 618 for the sulfur dioxide absorber 602.
• the alkaline component for sulfur dioxide removal may be the same as the alkaline component for carbon dioxide removal, and accordingly may be any of the alkaline components described herein for carbon dioxide removal. It should be appreciated, however, to the extent that the reaction tank 618 also serves as a reagent feed tank for the carbon dioxide absorber 608, that the absorbing solution 610 used in the carbon dioxide absorber 608 will also contain the reaction products from the absorption of sulfur dioxide.
• the alkaline component for either sulfur dioxide removal or carbon dioxide removal may be added to either the reagent feed tank 614 or the reaction tank 618 (as shown by the dashed lines) for the sulfur dioxide absorber 602 or both from chemical feed tanks 620, 622.
• a catalyst for carbon dioxide removal as described herein may also be added via one of the chemical feed tanks 620, 622 to either the reagent feed tank 614 or the reaction tank 618 for the sulfur dioxide absorber 602 or both.
• Figure 6A illustrates another process for the removal of sulfur dioxide and carbon dioxide according to another embodiment of the present invention.
• This process 600A is similar to that shown in Figure 6, however, with several exceptions.
• a single reagent feed tank 650 from which an absorbing solution 652 is fed to the sulfur dioxide absorber 602. After passing through the sulfur dioxide scrubber 602, the absorbing solution is discharged from the system through a blowdown line 654.
• the reagent feed tank 650 also serves as the reagent feed tank for the carbon dioxide absorber 608.
• this reagent feed tank 650 also serves as the reaction tank for the carbon dioxide absorber 608 because it collects the absorbing solution 652 after passing through the carbon dioxide absorber 608. Otherwise, the carbon dioxide absorber 608 may be constructed and operated in the same fashion as those carbon dioxide absorbers described previously. A blowdown stream from the carbon dioxide absorber 608 is discharged through blowdown stream line 656 and combined with the blowdown stream 654 from the sulfur dioxide absorber. As discussed in connection with Figure 6, chemical feed tanks 620, 622 may be used to feed one or more alkaline components to the reagent feed tank 650 and to add additional chemicals, such as a catalyst for carbon dioxide removal. [0085] Figure 7 illustrates a process for regenerating reagent for use in an embodiment of the present invention.
• a discharge or blowdown stream 702 comprising a portion of the absorption solution from any of the foregoing carbon dioxide absorbers or from any one of the stages from those carbon dioxide absorbers having two stages in which the alkaline component comprises at least sodium hydroxide is directed to a regeneration tank 704.
• a solution comprising calcium hydroxide is held in a feed tank 706 and is fed to the regeneration tank 704, where it is mixed and reacted with the discharge stream 702.
• the absorption solution will contain sodium carbonate as a result of the absorption of carbon dioxide.
• This sodium carbonate is reacted with the calcium hydroxide in the regeneration tank 704 to regenerate the alkaline component sodium hydroxide and to produce calcium carbonate solids or limestone according to the following equation:
• the reaction products of sodium hydroxide and calcium carbonate solids in the regeneration tank 704 are passed to a liquid/solid separator 708, such as a hydrocyclone or other device that can reasonably separate solids and liquids.
• the liquid/solid separator 708 produces a liquid-rich stream 710 comprising sodium hydroxide and a solids-rich stream 712 comprising calcium carbonate solids.
• the liquid-rich stream 710 may be recycled back to either a chemical feed tank that holds the alkaline component or to the reagent tank of any of the foregoing carbon dioxide absorber processes.
• This process 700 is particularly useful in those situations where the discharge or blowdown stream cannot be easily disposed of, since the resulting solids-rich stream 712 comprising calcium carbonate solids can be easily disposed of.
• process economics are improved by reclaiming the sodium hydroxide.
• the calcium carbonate solids precipitated in this regeneration process which comprise basically the captured carbon dioxide in a stable solid form, have been found to be a relatively pure form of precipitated calcium carbonate with a discrete particle size distribution and crystal structure.
• the precipitated calcium carbonate would contain less impurities like feldspar, other silicaceous materials, and heavy metals and also exhibit a more uniform size.
• the precipitated calcium carbonate may have certain crystal structures and shapes, such as needles, cubes, rhombohedrons, and prisms, that have desirable physical properties, including powder density and surface area, allowing these crystals to perform better than those in ground calcium carbonate.
• Calcium carbonate solids produced by this regeneration process at the laboratory-scale were analyzed and had the following properties: Brightness (MT): Rx 96.1%, Ry 95.5%,Rz 95.1%; yellowness index: 1.1, R457 TAPPI 94.7%, Hunter L 97.7%, Hunter a 0.73%, Hunter b 0.20%; Sedigraph: 55% less than 1 micrometer, 46% less than 0.5 micrometers, and 30% less than 0.2 micrometers; surface area (BET): 16.3 square meters per gram.
• Brightness (MT) Rx 96.1%, Ry 95.5%,Rz 95.1%
• yellowness index 1.1, R457 TAPPI 94.7%, Hunter L 97.7%, Hunter a 0.73%, Hunter b 0.20%
• Sedigraph 55% less than 1 micrometer, 46% less than 0.5 micrometers, and 30% less than 0.2 micrometers
• surface area (BET): 16.3 square meters per gram In removing carbon dioxide from
• These solids may also be used in roadbed construction and in the manufacture of cement and concrete.
• the precipitated calcium carbonate may be used as a replacement for Portland cement.
• Portland cement has historically been a key ingredient, along with sand and aggregate, in the manufacture of concrete, a globally used material. Concrete is normally manufactured by mixing Portland cement, sand, and aggregate in a specific ratio of one part, two parts, and three parts, respectively, by volume. Cement has been made using calcium carbonate solids produced by the regeneration process described above at the laboratory-scale as a substitute for a portion of the Portland cement. There are several advantages of using these solids as a substitute for Portland cement. First, the amount of Portland cement required to manufacture concrete can be reduced.
• flyash if captured by the processes described above, can be additionally blended with the precipitated calcium carbonate to further reduce the amount of Portland cement required for the manufacture of concrete.
• These reductions in the amount of Portland cement will represent a potentially significant reduction of carbon dioxide emissions that are normally produced during the manufacture of Portland cement, in addition to the carbon dioxide emissions captured by the processes described above.
• the concrete produced by the use of these solids represents a potential revenue stream, partially offsetting the cost of installing and operating the carbon dioxide capture system.
• potassium hydroxide may be used instead of calcium hydroxide in the feed tank 706.
• the potassium hydroxide would react with the sodium carbonate to regenerate sodium hydroxide as follows:
• potassium hydroxide is produced by electrolysis of potassium chloride ore, there is no carbon dioxide produced or released into the atmosphere during its production. Accordingly, the use of potassium hydroxide in the present invention provides a process that, even when taking into account the reagents used, avoids carbon dioxide emissions. Further, the potassium carbonate produced by this regeneration reaction (Eq. 8) will be returned to the carbon dioxide absorbers via the liquid-rich stream 710, which is beneficial because it is believed that a solution comprising potassium hydroxide may have a greater affinity for the absorption of carbon dioxide than for sulfur dioxide. The potassium hydroxide in the absorbing solution will react with absorbed carbon dioxide as follows:
• this potassium carbonate stream may also be saleable in the fertilizer industry, for example, as a soil amendment.
• This stream may be either sold in its current form or water may be evaporated to concentrate the potassium ions and minimize transportation costs.
• this stream comprising potassium ions may by sent to an evaporation pond where the water is evaporated and the remaining solids are scraped together and sold.
• blowdown streams preferably would not be mixed so that the sodium-based stream could be used in the regeneration process to regenerate sodium hydroxide.
• both absorbers or both absorption sections utilize sodium hydroxide as the alkaline component, then the blowdown streams from each could be combined and treated together in the regeneration process.
• FIG. 8 illustrates a process for producing gaseous carbon dioxide according to one embodiment of the present invention.
• a discharge or blowdown stream 802 comprising a portion of the absorption solution from any of the foregoing carbon dioxide absorbers or from any one of the stages from those carbon dioxide absorbers having two stages in which the alkaline component comprises at least sodium hydroxide is directed to a covered tank 804.
• a feed tank 806 is configured to hold an acidic solution 808 capable of reducing the pH of the blowdown stream.
• the acid may be an inorganic acid, such as sulfur acid.
• the concentration of the acidic solution 808 may be adjusted depending upon the amount of acid need to reduce the pH of the blowdown stream 802 to the desired pH, taking into account water balances.
• the pH of the blowdown stream 802 is reduced to off-gas carbon dioxide.
• the pH is reduced to approximately 3.0 or lower, and in other embodiments, the pH is reduced to approximately 2.0 or lower.
• the resulting gaseous carbon dioxide is collected in the upper region 810 of the closed tank 804 and is passed through a gas discharge line 812 to a moisture knock-out device 814 to reduce the moisture content in the carbon dioxide gas stream.
• the moisture knock-out device 814 may be any device known in the art capable of reducing the water or moisture content of a gas stream.
• the carbon dioxide gas stream is then passed to a compressor 816 that increases the gas stream's pressure to produce a saleable carbon dioxide gas stream 818.
• the carbon dioxide gas produced may be used in enhanced oil recovery or other industrial processes.
• liquid sulfite having a cation corresponding to that of the alkaline component used in the carbon dioxide absorber.
• liquid phase sodium sulfite will be produced in the closed tank 804 upon the reduction of the pH and off-gassing of the carbon dioxide.
• potassium hydroxide is used as the alkaline component
• liquid phase potassium sulfite will be produced in the closed tank 804. This liquid sulfite is passed through a liquid discharge line 820, which may be subsequently treated to recover the sulfite or reused.

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