System for recovery of CO.sub.2 from flue gases containing SO.sub.2

FIELD OF THE INVENTION
The invention is directed to an improved system for recovering CO.sub.2 from flue gases and the like containing SO.sub.2, at low CO.sub.2 partial pressure, and includes the use of K.sub.2 CO.sub.3 as the solvent for the CO.sub.2 and SO.sub.2, regeneration of the solvent, and removal of SO.sub.2 as SO.sub.4.
BACKGROUND OF THE INVENTION
An important and increasing demand for carbon dioxide stems from its utilization for enhancing the recovery of oil. Because neither the present nor the future demand for carbon dioxide can be met from available natural deposits of CO.sub.2, alternate sources have been and are being utilized. One of the most abundant sources of alternate CO.sub.2 supply lies in flue gases from fossil fuel-fired plants. Many of these plants burn fuel which contains sulfur compounds which are emitted as SO.sub.2 in the resulting flue gases. One currently known and used CO.sub.2 recovery process includes the use of monoethanolamine or potassium carbonate as an adsorbent for the CO.sub.2. In processes using such absorbents, flue gas SO.sub.2 is also absorbed along with CO.sub.2 in an absorber. Subsequent stripping which removes CO.sub.2 does not remove the bulk of SO.sub.2, which stays within the system. For example, if K.sub.2 CO.sub.3 is used as a solution, SO.sub.2 stays as K.sub.2 SO.sub.4. The degenerates the solution, e.g., potassium carbonate, and reduces its absorption efficiency. The resulting contaminated solution must then either be regenerated, or purged from the system. Present commercial practice is to purge the contaminated solution, a procedure requiring a large amount of make-up solution and increasing operating costs. These factors discourage and even prohibit the applicability of the process, especially to coal-fired power plants which use sulfur-containing coals.
There are available, in fact, a number of processes for the removal of CO.sub.2, and such other acid gases as H.sub.2 S, SO.sub.2, and the like from gas streams, using either a solid adsorbent or a liquid absorbent. These processes can be further divided into two groups, namely those which employ chemical solvents which chemically absorb the acid gas, and those which employ physical solvents which physically absorb the acid gas. The choice of solvent is important because the amount of solvent and the solvent circulation rates normally determine the size of equipment required, and, accordingly, substantially affects the overall cost of acid-gas recovery.
Among the pertinent commercial processes available are those set forth below. They use chemical or physical solvents, as indicated.
Chemical Solvents
Amines: Monoethanolamine, Diethanolamine, Triethanolamine, Diisopropylamine, Diglycolamine
Activated hot potassium carbonate: Benfield, Vetrocoke, Catacarb,Lurgi, Vacuum Carbonate
Others: Stretford, Scott, Tripotassium. Phosphate, Ammonia, Copper Liquor, Alkazid, Ferrox, Manchester, Konox, Sulfox, Seaboard, Thylox, Sodium Phenolate
Physical Solvents: Fluor, Purisol, Rectisol, Selexol, Sulfinol (really a mixed chemical-physical solvent), Water
Solvent selection is normally based on the temperature of the feed gas, and the partial pressure of the acid gas in the feed gas stream. If CO.sub.2 partial pressures in the feed gas stream are low, then the physical solvents can be eliminated because compression of the gas for physical solvent absorption makes this particular mode of CO.sub.2 recovery too expensive. Because low purity byproduct CO.sub.2 streams, such as flue gases, have low CO.sub.2 partial pressures, which range from about 1.3 to about 4.3 psi, chemical solvents are the only practical solvents which are suitable for CO.sub.2 recovery. Two typical prior art processes utilizing monoethanolamine (MEA) and potassium carbonate are briefly described hereinafter.
THE BASIC MEA PROCESS
Use of alkanolamines for the adsorption of acid gases was described at an early date, in U.S. Pat. No. 1,783,901 issued in 1930, showing the use of triethanolamine (TEA) as an absorbent for acid gases in natural gas treating plants. The development of processes using other alkanolamines followed. Because of their reactivity and availability at low cost, monoethanolamine and diethanolamine have become especially prominent in the gas-sweetening industry.
A simplified process flow diagram for CO.sub.2 recovery using monoethanolamine is shown in FIG. 1 of the drawings. There is very little variation in the process, regardless of the strength of the MEA solution used. In this process about 10 to 30 weight percent MEA solutions are typical; the two main pieces of equipment are the absorber column--normally either a packed bed or a plate tower, and the stripper column which is normally a plate tower.
The CO.sub.2 -bearing gas stream enters at the bottom of the absorber column and flows upwardly through the absorber in intimate counter-current contact with the aqueous amine solution. The depleted gas stream leaves the top of the absorber and is vented to the atmosphere through the stack for flue gas. This stream may be heated by mixing it with untreated flue gas for plume rise if necessary. The rich amine solution, laden with CO.sub.2 flows from the bottom of the absorber and passes through the amine-amine heat exchanger and then to the top of the stripper column. The solution is boiled at the bottom of the stripper by heating the aqueous solution in the reboiler. Steam (primarily) then rises upwardly in counter-current contact with the rich amine solution. The CO.sub.2 is stripped out of the amine solution, and the CO.sub.2 gas rises to the top of the stripper with the steam. After condensing the major part of the steam from the CO.sub.2 -steam mixture, a rich CO.sub.2 stream is produced which requires only some additional drying and compression before it is ready to use for enhanced oil recovery. At the bottom of the stripper the amine solution, which is now lean in CO.sub.2, is pumped through the amine-amine heat exchanger and then through a water or air cooled exchanger, before being introduced into the top of the absorber column.
A number of difficulties are associated with CO.sub.2 absorption systems utilizing monoethanolamine as the solvent, these being broadly categorized as corrosion, solution degradation, and foaming. Corrosion occurs because an acid gas is being treated in an aqueous environment, and it will be most severe at those places where the highest concentrations of CO.sub.2 encounter the highest temperatures. These places will include the amine-amine heat exchanger, the stripping column, and the reboiler. Stress corrosion, which is also prevalent in systems using alkanol amines, is generally associated with residual stresses resulting from localized heating during vessel construction, such as welds in absorbers, strippers, and piping.
Solution degradation can occur for a number of reasons, resulting from, e.g. the entrainment of solids, sulfur pickup, and the formation of dissolved salts. In order to recover much of the fouled solution, about 3% of the solution circulation rate is taken for most byproduct streams, as a side stream, just before the reboiler. This side stream passes to an amine reclaimer, where the water and the amine are distilled from the fouled solution and then returned to the bottom of the stripper column,
Foaming in the amine CO.sub.2 recovery process can result in a severe reduction in gas throughput, a reduction in the amount of CO.sub.2 absorbed, and in a significant increase in amine loss. The foaming problem can be caused by almost any foreign material including, for example, suspended solids and amine degredation products.
POTASSIUM CARBONATE PROCESSES OF THE PRIOR ART
The fact that potassium carbonate can be used to remove CO.sub.2 from a mixture of gases has been known for many years. Kohl and Riesenfeld cite a German patent granted in 1904 describing a process for absorbing CO.sub.2 in a hot solution of potassium carbonate followed by stripping the solution through pressure reduction without additional heating. Kohl, A. L., and F. C. Reisenfeld, Gas Purification, third edition: Gulf Publishing Company, Houston, Tex., pages 187-211 1979. A highly improved form of this process is in commercial operation for acid-gas removal from high pressure streams, e.g., CO.sub.2 removal from gas at high CO.sub.2 partial pressures, such as those in ammonia plants, natural gas processing plants, and hydrogen plants.
In an activated potassium carbonate process, which could be economical compared to the above-described process using MEA, especially when sulfur is present, and discussed in West Virginia University DOE Contract EF-77-C-03-1582, Final Report, June 1980, entitled "Determination of the Effects of Sulfur Dioxide on Recovery Systems for CO.sub.2 " by J. T. Sears, the process flows for the potassium carbonate would be similar to the one above-described for the MEA system. IN a hot potassium carbonate system the absorber operates at higher temperatures, thus reducing the amount of heat exchange surface area needed, and thereby reducing the number and size of heat exchangers between the absorber and the stripper. In the modification for its use for recovery of low partial pressure CO.sub.2 streams, the absorber is at a lower temperature and more heat exchange surface is required.
An alternative is to utilize a process similar to the vacuum carbonate process such as disclosed in Gas Purification, third edition, Gulf Publishing Company, Houston, Tex., by Kohl and Riesenfeld, pages 187-211 (1979). This process would eliminate the rich-lean K.sub.2 CO.sub.3 heat exchanger and would operate the stripping column at reduced pressures. This change would increase the stripper column diameter, but would decrease steam regeneration requirements. Either alternative could operate down to 0.4 psia outlet-CO.sub.2 partial pressure, according to present conventional commercial system practice.
The reactions that occur can be represented by the following:
CO.sub.2 absorption
K.sub.2 CO.sub.3 +H.sub.2 O+CO.sub.2 .revreaction.2KHCO.sub.3( 1)
This reaction proceeds in two steps:
K.sub.2 CO.sub.3 +H.sub.2 O.revreaction.KOH+KHCO.sub.3 ( 1A)
KOH+CO.sub.2 .revreaction.KHCO.sub.3 ( 1B)
The KHCO.sub.3 produced as a result of the above reactions can be regenerated to K.sub.2 CO.sub.3 in the stripper at higher temperatures. Since the above reactions are slow and limit CO.sub.2 adsorption rates at low partial pressures, activators have been incorporated in order to increase absorption rates by initial reaction with the dissolving CO.sub.2 (e.g. Benfield, Catacarb). This increase in absorption activity is important for a K.sub.2 CO.sub.3 based process. The activator--CO.sub.2 product then reacts with the alkaline potassium solution.
Similar to the MEA system above-described, and in FIG. 1, the CO.sub.2 bearing gas enters at the bottom of the absorber column and flows upward through the absorber in intimate counter-current contact with lean potassium carbonate solution entering from the top of the absorber. The depleted gas stream leaves the top of the absorber and is vented to the atmosphere after water wash to recover any entrapped potassium carbonate solution. The depleted gas may be heated if necessary. The rich potassium carbonate solution laden with CO.sub.2 flows from the bottom of the absorber, passes through the rich lean K.sub.2 CO.sub.3 heat exchanger, and then to the feedplate of the stripper column. Steam is produced at the bottom of the stripper by heating the aqueous potassium carbonate solution in the reboiler, and the steam then rises upward in counter current contact with the rich potassium carbonate solution. The CO.sub.2 is stripped from the rich potassium carbonate solution (2KHCO.sub.3 .fwdarw.K.sub.2 CO.sub.3 +H.sub.2 O+CO.sub.2), and the CO.sub.2 gas rises to the top of the stripper with the steam. After condensing the major part of the steam from the CO.sub.2 -steam mixture, it is returned to the stripper through the reflux tank via the reflux pump. The uncondensed part of the CO.sub.2 -rich gas stream requires only some further drying and compression before the CO.sub.2 is ready for use, as in enhanced oil recovery. At the bottom of the stripper, the potassium carbonate solution which is now lean in CO.sub.2 after passing through the reboiler, is pumped to the top of the absorber through the rich/lean K.sub.2 CO.sub.3 heat exchanger and the lean K.sub.2 CO.sub.3 cooler.
SO.sub.2 CONTAINING FLUE GASES
As stated previously, flue gases will contain SO.sub.2 when sulfur-containing fuel is burned, a situation typified in the operation of many coal-fired power and cement plants. In the presence of oxygen, SO.sub.2 reacts with K.sub.2 CO.sub.3 as follows:
K.sub.2 CO.sub.3 +SO.sub.2 +1/2O.sub.2 +H.sub.2 O.fwdarw.K.sub.2 SO.sub.4 +H.sub.2 O+CO.sub.2 ( 2)
This reaction proceeds in the following steps:
SO.sub.2 +H.sub.2 O.revreaction.H.sub.2 SO.sub.3 ( 2A)
H.sub.2 SO.sub.3 +1/2O.sub.2 .revreaction.H.sub.2 SO.sub.4 ( 2B)
H.sub.2 SO.sub.4 +K.sub.2 CO.sub.3 .fwdarw.K.sub.2 SO.sub.4 +H.sub.2 O+CO.sub.2 ( 2C)
The K.sub.2 SO.sub.4 produced by the above reactions can not be regenerated in the stripper and will reduce the capacity for SO.sub.2 and CO.sub.2 adsorption unless K.sub.2 SO.sub.4 is separated from the K.sub.2 CO.sub.3 solution. The corrosion rate of the solution, and the steam requirements for desorption of CO.sub.2 also increase with increase in SO.sub.2 contamination of the K.sub.2 CO.sub.3 solution.
This problem can be solved by purging the contaminated solution before it is recirculated to the absorber, the amount of purging and the composition of the K.sub.2 CO.sub.3 solution required depend on the amount of SO.sub.2 in the CO.sub.2 -containing stream of the flue gas being treated, and on the size of the CO.sub.2 recovery system. When the SO.sub.2 impurity is above a certain level, typically about 50 to 60 ppm, the purging of contaminated solution is no longer ecconomically feasible. Thus, such a system can not be economically used for CO.sub.2 recovery from many potential CO.sub.2 supply sources such as coal-fired power and cement plants.
At the present time use of the K.sub.2 CO.sub.3 system for CO.sub.2 recovery from flue gases is not commercially attractive because the monoethanolamine (MEA) process is cheaper in those cases where the flue gases contain little or no sulfur and the solution can be purged without significant impact on the overall cost.
SUMMARY OF THE INVENTION
The present invention is directed to providing process alternatives for CO.sub.2 recovery systems using K.sub.2 CO.sub.3 so that the SO.sub.2 contaminated absorption medium (solution) can be regenerated instead of purged. The system of the invention is generally similar to the process of absorption and desorption of CO.sub.2 as discussed above, except for the addition of an SO.sub.2 removal procedure, which involves converting K.sub.2 SO.sub.4 to CaSO.sub.4 using procedures as described hereinafter.

The invention will be better understood when considered in light of the following detailed description together with the drawings in which:
FIG. 1 is a simplified flow diagram illustrating conventional processes for CO.sub.2 removal from gases utilizing K.sub.2 CO.sub.3 or MEA as the absorbent.
FIG. 2 is also a simplified flow diagram, but illustrating the improved process of the invention.

In the practice of our invention, the SO.sub.2 - and CO.sub.2 -containing gas stream enters the bottom of the absorber column and flows upwardly through the absorber in intimate counter-current contact with 20-30% lean potassium carbonate solution entering from the top of the absorber. The CO.sub.2 and SO.sub.2 are absorbed in the solution as shown by the following overall reactions:
K.sub.2 CO.sub.3 +H.sub.2 O+CO.sub.2 .revreaction.2KHCO.sub.3(1)
K.sub.2 CO.sub.3 +1/2O.sub.2 +SO.sub.2 +H.sub.2 O.fwdarw.K.sub.2 SO.sub.4 +CO.sub.2 +H.sub.2 O (2)
The depleted gas stream leaves the top of the absorber and is vented to the atmosphere after an optional water wash (not shown) to recover any trapped potassium carbonate solution. The rich potassium carbonate solution containing K.sub.2 SO.sub.4 leaves the bottom of the absorber and proceeds to the stripper for regeneration. If K.sub.2 SO.sub.4 is not removed, it accumulates in the system, thereby reducing the absorption efficiency of the system and increasing the steam requirements.
In this novel system, a portion of the rich K.sub.2 CO.sub.3 solution containing KHCO.sub.3, K.sub.2 CO.sub.3, and K.sub.2 SO.sub.4 is sent to the SO.sub.2 removal system.
The process of the present invention includes two major unit operations shown in the drawing as unit operation #1 and #2. In unit operation #1, K.sub.2 SO.sub.4 is converted to CaSO.sub.4 by incorporating Ca.sup.++ ions by adding a lime (or limestone) solution to the solution of rich K.sub.2 CO.sub.3 containing K.sub.2 SO.sub.4 while bubbling CO.sub.2 through the mixture at a pressure of about 150 psi. CO.sub.2 is bubbled through the system to reduce the pH of the solution to about 6, so that more calcium ions can be added to the system without precipitation of Ca(OH).sub.2 or CaCO.sub.3, thereby enhancing the conversion of K.sub.2 SO.sub.4 to CaSO.sub.4. The exact temperature of the system, the amount and concentration of Ca(OH).sub.2 or CaCO.sub.3 to be added, and the CO.sub.2 bubbling rate and pressure, can be readily determined from solubility product data at various concentrations. The solid CaSO.sub.4 is then separated from the liquor and the separated liquor is then sent to Unit Operation #2. The principal function of this unit operation is to separate calcium ions from the liquor before it is sent back to the absorber, and is accomplished in a closed tank by adding Ca(OH).sub.2 to change the pH to a higher value. The following reactions would occur:
Ca(OH).sub.2 .revreaction.(Ca).sup.++ +2(OH.sup.--)
2KHCO.sub.3 .revreaction.2(K.sup.+)+2(HCO.sub.3)
(OH)+(HCO.sub.3).fwdarw.H.sub.2 O+(CO.sub.3)
(Ca.sup.++)+(CO.sub.3).fwdarw.CaCO.sub.3
2K.sup.+ +(CO.sub.3).fwdarw.K.sub.2 CO.sub.3
The overall reaction is:
Ca(OH).sub.2 +2KHCO.sub.3 .revreaction.CaCO.sub.3 +K.sub.2 CO.sub.3 +H.sub.2 O
The CaCO.sub.3 thus produced is precipitated out and could be sent back to the pressurized system, Unit Operation #1, for addition of calcium ions. The CO.sub.2 which is required for the Unit Operation #1 reactor, can be supplied by product coming out of the stripper. The calcium hydroxide and CO.sub.2 requirements can be readily determined by stoichiometric calculations based on the solubility product data of all reactants present, The K.sub.2 CO.sub.3 which is produced in the Unit Operation #2 reactor is recirculated back to the absorber.
Among the principal advantages of the present invention over the prior art are the following: current technology permits the recovery of CO.sub.2 from flue gases containing little or no sulfur dioxide. In accordance with current practice, the SO.sub.2 -contaminated K.sub.2 CO.sub.3 solution is purged, requiring the addition of make-up solution, which is very costly. High cost has prevented the technology from being used to recover CO.sub.2 from flue gases which are emitted by the majority of coal-fired plants. The process of the present invention would permit removal of SO.sub.2 from the contaminated solution and eliminate the need for extensive purging, thereby providing a system which is economically attractive for the recovery of CO.sub.2 from coal-fired power and cement plants and the like to supply CO.sub.2.
In accordance with prior art, if the flue gas contained more SO.sub.2 than could be effectively purged, an SO.sub.2 removal system was placed ahead of the CO.sub.2 removal system. This is likewise expensive. With the process of the present invention, SO.sub.2 removal ahead of the CO.sub.2 recovery system is not required, thus reducing the overall cost.
Having clearly and fully described our invention, it will be understood that changes may be made in the system as above set forth without departing from the spirit of the invention or exceeding the scope thereof as defined in the following claims.

Number	Name	Date
1992324	Rusberg	Feb 1935
2997366	Owens et al.	Aug 1961
3264056	Konz	Aug 1966
3944649	Field et al.	Mar 1976
4377557	Lowell	Mar 1983

System for recovery of CO.sub.2 from flue gases containing SO.sub.2

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