BACKGROUND In recent years many oil companies have installed refinery facilities that allow them to process cheaper, heavier crude oils which contain large amounts of contaminants such as sulfur, nitrogen, and metals. Some of these contaminants are converted in the refining processes to "acidic gases" which are gases that exhibit acidic characteristics when dissolved in water, as for example, hydrogen sulfide (H2 S), carbon dioxide (CO2), and hydrogen cyanide (HCN).

At the same time that the concentration of these contaminants has been increasing in the available crude oils, there has been an increased awareness of the deleterious effects of releasing these acidic gases into the atmosphere. Acidic gases of particular concern, that will be discussed below in greater detail, are hydrogen sulfide, carbon dioxide, and the nitrogen based compounds.

The increase of sulfur emissions to the atmosphere has become a major environmental concern. For example, atmospheric sulfur dioxide and nitrous oxides are converted to acid rain which has a negative impact on the environment. The primary source of atmospheric sulfur is the combustion of sulfur-laden fuels. Recent environmental regulations will not allow the burning of sulfur-laden gas unless the concentration of sulfur in the gas has been reduced to an acceptable level. In fact, most of the world's governments have established standards limiting sulfur emissions. For example, the United States and some state environmental regulations require an extremely high percentage of H2S recovery, basically set according to the levels permitted by the Best Available Control Technology. In the United States, refineries are permitted to burn mixed fuel gas with no more than 160 ppm by volume of H2S. Natural gas must be processed to 4 ppm by volume of H2S and regulations governing waste water do not permit the discharge of water containing more than 10 ppm by weight of NH3 and 5 ppm by weight of H2S.

An oil refinery derives most of its fuel requirement from the crude oil as it is separated into the various liquid distillate components. The traditional business of an oil refiner is to sell liquid products, because liquids are more easily transported, stored and dispensed, thus the gaseous by-products are either burned by the various refining processes or sold as a petrochemical feed stock. The purity requirements for petrochemical feed stocks generally are more stringent than the environmental requirements for burning this gas.

Fuel gas production results from the initial crude oil distillation, and as a by-product of several hydrogenation steps which must be applied to make some distillates environmentally acceptable, and from hydrocarbon conversion operations like the fluid catalytic cracker (FCC), or a coke oven or a visbreaker. Gaseous by-products emanating from these refining operations must be made environmentally acceptable before they are consumed by the refinery as fuel.

Generally in the United States the admix of these fuel gases must have no more than 160 ppmv of H2S. Some specific areas, like California for instance are so environmentally constrained that the regulators find it necessary to set Total Reducible Sulfur emissions at a still lower requirement of no greater than 40 ppm by volume. The challenge for oil refiners and industries in general across the world has been to find economically viable ways of conducting a profitable business, while still meeting environmental constraints.

The most common gas by-product treatments employed are usually based upon contacting these gas by-products with an array of regenerative alkanolamines. One to as many as three parallel regenerated alkanolamines (amines) are typically supplied by dedicated central regeneration steps. The regenerated (lean) amines are brought into intimate contact with the by-product gases and become enriched when they absorb H2S and other acidic gases. The resulting amine now (rich ) in acidic gases are collected and reject the acids gases in a centralized heat regeneration step.

The performance of amines systems are hampered by trace levels of noxious constituents in the by-product gases that continually destroy the amines they contact.

Destruction of the amine by these compounds contributes significantly to a refinery's annual multi-million dollar fresh amine make-up and disposal costs.

The acidic gases produced by successful amine regeneration is typically converted to elemental sulfur, carbon dioxide and nitrogen in a Claus sulfur recovery unit. The Claus process is often followed by a treatment of exit gases to recollect the unconverted sulfur species and recycle them back to the Claus reaction. Acid gas based by-products rarely

contribute to the oil refining profit. The ultimate challenge for the oil refiner and industries with analogous gas treating needs is to have a centralized operation which is as economical as possible. Ideally such an operation would also be profitable. Therefore, less expensive waste product conversion methods and process improvements continue to be an unrealized goal.

Regenerable solvents and processes for the deacidification of gas streams that can deal with all the gas by-product constituents better than the conventionally known amine molecules are currently unavailable.

PCT application US95/09290 discloses a new pure ammonia based method and special absorber apparatus for desulfurizing low pressure gases. The solvent used in this process is based upon mixing water and pure ammonia to a 19-20% concentration. These patent applications disclose an absorption step that can improve the desulfurization of one of the most formidable gases which the current amine alternatives would otherwise have to treat. This disclosure however did not improve the knowledge for treating the resulting sour water, and did not disclose less expensive ways of preparing the ammonia based solvent, other than to purchase externally produced ammonia. Ammonia is also a well known and troublesome by-product of most of the oil refining hydrogenation steps.

Ammonia is collected in the fouled (sour) waters and gas-byproducts which the aforementioned refinery operations produce. To be an environmentally acceptable water discharge in most nations, these collective sour waters must not contain more than 10 ppm by weight ammonia and 5 ppm by weight hydrogen sulfide. This is typically achieved by thermally stripping out the weak acidic compounds and ammonia. The resulting largely hydrogen sulfide and ammonia gas stream is also fed to the Claus process for conversion of these compounds to environmentally acceptable liquid sulfur, nitrogen, water and carbon dioxide.

Each of refining gaseous by-product has its own particular characteristics and complications that must be considered in its deacification. The Fluid Catalytic Cracker (FCC) makes and contributes one of the larger flows to the fuel gas admix which an oil refinery makes, cleans and then consumes. Gas by-product treatment within the FCC also includes maximum recovery of any heavier hydrocarbons that could be sold as liquid product, and the weak acidic gases that must be dealt with present formidable processing challenges and therefore expense.

The fluid catalytic cracker (FCC) is a plant used to produce light hydrocarbons starting

from heavy gas oil. Cracked hydrocarbons from the fluid catalytic reactor are first partially cooled from the extremely high heat used to crack the hydrocarbons and then separated in a main fractionator column. The gas stream recovered off the top of the column, often referred to as "wet gas," contains the light hydrocarbons (C2-C4), hydrogen sulfide, carbon dioxide, hydrogen cyanide, and other acidic gases.

The light hydrocarbons in the "wet gas" represent a valuable resource. Thus, the industry has developed a gas treatment process that maximizes the concentration of the light hydrocarbons in gasoline and oil products and sufficiently deacidifies the remaining gas stream of light hydrocarbons to produce an acceptable fuel gas. The gas treatment process generally includes compressing the wet gas (usually in two or more stages), selectively absorbing the light hydrocarbons from the wet gas by contacting the gas with successively higher molecular weight adsorbents, and finally deacidifying the remnant light hydrocarbon gas stream. This process provides a gas stream suitable for use as fuel gas or petrochemical feed stock.

Since the inception of the FCC technology, the resulting fuel gas streams have generally been deacidified by absorption of the acidic gases using synthetic amines. These synthetic amines are well suited for the treatment of gases which contain hydrogen sulfide and carbon dioxide as the only acidic gases to be removed. However, for treating gas streams containing oxygen, hydrogen cyanide, and other impurities, the synthetic amines are of limited application because (i) the amines react to form nonregenerable compounds with certain impurities, (ii) these impurities are not readily removed from fouled amine solutions, and (iii) many of the nonregenerable amine reactants are corrosive and difficult to remove. A particular synthetic amine problem is that they are destroyed by oxygen, which is almost always present in the wet gas. As a consequence, the amines are continuously degraded, requiring replenishment and offsite treatment of fouled solutions. Amine replacement costs generally exceed a million dollars a year for a refinery and amine degradation in an FCC gas treatment plant contributes significantly to that cost.

Furthermore, only a select few of the most reactive synthetic amines can desulfurize an acidic gas stream to 4 ppm by volume of H2S without significant increase in the inlet gas pressure. The most effective amines require that the acidic gases be compressed to above 70 psig before they can be effectively deacidified, or desulfurized to low levels. This is in part why regulators continue to permit refineries to burn fuel gas with significantly higher sulfur

content than natural gas, for instance.

The refining industry is under pressure to decrease the acid gas content of fuel gas, yet the crude oils being used today actually have increased concentrations of acid forebearing compounds. There is an ongoing need in the industry to improve the efficiency of the deacidifying process, to decrease the expense of deacidifying fuel gas, and to increase the capacity of the wet gas treatment process.

BRIEF DESCRIPTION OF THE DRAWINGS For a more complete understanding of the present invention, and the advantages thereof, reference is now made to the following descriptions taken in conjunction with the accompanying drawings, in which: FIG. 1 is a schematic illustration of a conventional FCC gas treatment plant; FIG. 2 is a schematic illustration of a FCC gas treatment plant where a deacidification section has been incorporated into the FCC main fractionator; FIG. 3 is a schematic illustration of one embodiment of a FCC gas treatment plant incorporating a deacidification column; FIG. 4 is a schematic illustration of an alternative embodiment a FCC gas treatment plant incorporating a deacidification column; FIG. 5 is a schematic illustration of one embodiment of a deacidification column; FIG. 6 is a schematic illustration of an alternative embodiment of a deacidification column; FIG. 7A is a schematic illustration of an alternative embodiment of a deacidification column; FIG. 7B is a schematic illustration of another embodiment of a deacidification column; FIG. 8 shows a pan view of one embodiment of a distribution device; FIG. 9 shows a pan view of an alternative embodiment of a distribution device; FIG. 10 is a schematic illustration of a conventional sour water stripper; FIG. 11 is a schematic illustration of one embodiment of a selective stripping column and its potential relationship to a deacidification column; FIG. 12 is a schematic illustration of a selective stripping apparatus; FIG. 13 is a schematic illustration of a conventional sulphur recovery unit; and FIG. 14 is a schematic illustration of one embodiment of a sulfur recovery unit.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT With reference to the drawings, like reference characters designate like or similar parts throughout the drawings.

The conventional wet gas treatment process is schematically illustrated in FIG. 1. The vapors from an FCC reactor are fed through line 2 to a FCC main fractionator column 10. The FCC main fractionator 10 separates hydrocarbon fractions according to their boiling points.

Various boiling point hydrocarbon fractions are removed from the main fractionator column 10 through lines 3. The lighter hydrocarbons, with low boiling points, rise to the top of the main fractionator column 10.

A gaseous stream, commonly referred to as "wet gas," is obtained from an overhead receiver 20 off the main fractionator 10. The composition of the wet gas is mainly light hydrocarbons (C2-C4) and non-condensible gases such as methane (CH4), hydrogen sulfide (H2S), carbon dioxide (CO2), carbon monoxide (CO), hydrogen (H2), oxygen (02), nitrogen (N2), and small quantities of other acidic and basic gases.

The wet gas is further processed with a gas treatment process. In the gas treatment plant, the wet gas is fed to a wet gas compressor 30 that is typically two or more stages. The wet gas enters the first stage of the wet gas compressor 30 through line 4. The initially compressed gas stream leaves the first stage of the wet gas compressor 30 through line 5, where it is cooled by cooler 6 and passed through an interstage receiver 40. The interstage receiver 40 allows condensed liquids to separate from the first stage compressed gas stream.

The first stage compressed gas stream leaves the interstage receiver 40 through line 7 and is fed into the second stage of the wet gas compressor 30. After the gas is further compressed, it leaves the second stage of the compressor 30 through line 8 where it is cooled by cooler 9 and sent to a high pressure receiver 50 through line 28. The high pressure receiver 50 also allows the compressed gas stream to separate from condensed liquid.

The compressed gas stream is then processed through two successive hydrocarbon absorption steps designed to increase the light hydrocarbon composition of the adsorbents of the two absorption columns while limiting the acidic gas absorption into the adsorbents. The compressed gas stream leaves the high pressure receiver 50 and is fed to the primary absorber 60 through line 11. In the primary absorber 60, the compressed gas stream is washed with gasoline derived from the main fractionator column 10 that enters the absorber 60 through line 12.

After passing through the primary absorber 60, the gas stream enters a sponge absorber 70 through line 13. There the gas stream is washed with a higher molecular weight hydrocarbon fraction (lean oil fraction) entering the sponge absorber 70 through line 14 from the main fractionator column 10.

The gas stream exiting the top of the sponge absorber 70 through line 15 still contains a significant portion of the light hydrocarbons and the majority of the acidic gases present in the wet gas when it left the main fractionator column 10. Since the gas stream emanating from the sponge absorber 70 still contains most of the acidic gases that were present in the wet gas, that gas stream must be deacidified before it can be used as a fuel gas.

Although a variety of physical and chemical solvent deacidifying processes are available, the gas stream is generally deacidified using a synthetic organic amine that is selective for the absorption of hydrogen sulfide. A solution of lean regenerated amine is delivered to the top of an amine absorber 80 through line 21 where it is used to deacidify and particularly desulfurize the gas stream fed to the bottom of the amine absorber 80 through line 15. The deacidified gas stream exiting the amine absorber 80 through line 22 is generally suitable for use as a fuel gas or petrochemical production feedstock. The amine adsorbents used to absorb the acidic gases from the gas stream perform that absorption in a heat reversible manner.

Therefore, once the amine absorbent has absorbed the acidic gases from the gas stream, it is withdrawn from the bottom of the amine absorber 80 through line 17, passed through heat exchanger 95, and fed through line 18 to an amine stripper column 90. This amine stripper 90 is often a central refinery unit serving many amine absorbers 80. The amine stripper column 90 is used to strip the acidic gases from the amine absorbent by heating the amine absorbent.

Concentrated acid gases (such as hydrogen sulfide and carbon dioxide) exit the top of the stripper column 90 through exit line 24 and regenerated amine absorbent exits the stripper column 90 through line 19, passes through the heat exchanger 95, and is recycled to the top of the amine absorber 80 through line 21. The stripped acid gas, which usually contains significant quantities of H2S, leaves the top of the stripper column 90 through line 24 and is usually routed directly to a sulfur recovery unit.

As illustrated in Figure 1 and described above, conventional wet gas treatment plants deacidify the gas stream coming off of the main fractionator column 10 at the end of the gas treatment process. Thus the acidic gases are included in the gas stream as it proceeds through

the entire wet gas treatment plant. The presence of acidic gases in the gas stream creates at least two major problems: (i) almost all of the gas treatment plant equipment is subject to the corrosive nature of the acidic gases; and (ii) the capacity of the equipment used in the gas treatment process (such as compressors, cooling systems, receivers and absorbers) is based on the wet gas volume, which can often contain as much as 8 to 10% acidic gases.

To circumvent these problems, the deacidification of the wet gas stream derived from the main fractionator column 10 can be performed earlier in the gas treatment process, thereby reducing the corrosive nature of the gas stream and increasing the capacity of the system by decreasing the volume of the gas stream to be processed. For example, the capacity of wet gas compressor 30 is typically a limitation on the through-put capacity of the FCC gas treatment process. Thus when the acidic gases are removed before the compression step, the capacity of the wet gas compressor 30 occupied by the acidic gases is available for increased amounts of the deacidified gas stream. Yet, the early deacidification of the wet gas stream using the organic amines described above is infeasible because none of the H2 S-selective amines can perform adequate acidic gas removal at low pressures. Amines are also degraded by oxygen and other impurities which are present in larger quantities at the front end of the gas treatment process.

New deacidification processes had to be developed in order to efficiently move the deacidification process closer to the beginning of the FCC gas treatment process. These new deacidification processes needed to include an absorbent that is not degraded by its interaction with oxygen or other constituents of the wet gas stream and that can efficiently remove the acidic gases from a gas stream at low pressures. Ammoniacal solutions (i.e., solutions containing ammonia) meet those requirements. The present invention includes a deacidification process that utilizes varying compositions of ammoniacal solvent as the absorbent. By utilizing this new deacidification process, the deacidification of the wet gas stream can be efficiently accomplished at any site along the wet gas treatment process.

Deacidifying the wet gas stream before it undergoes compression by the wet gas compressor affords the operator of a gas treatment plant with at least two major savings: (i) a decrease in the maintenance and corrosion of plant equipment, and (ii) an increase in the capacity of the gas treatment plant due to the reduction in wet gas volume that must be

compressed by the wet gas compressor 30.

Hydrogen sulfide has been identified as the major corrodent of refinery equipment operating at temperatures above 400C F. Extensive laboratory and pilot plant data has been collected and analyzed verifying the relationship of the corrosion of different metals with the concentration of H2S. This data has provided the industry with a series of isocorrosion curves relating the corrosion of steels to the temperature, pressure and the hydrogen sulfide concentration of different diluents. As expected, the corrosion data appears to correlate with the rate of a chemical reaction. A modified Arrhenius equation was used to correlate the corrosion data to the following equation: Corrosion Rate = Ae(-B/a«)x(m%H2S)DxPE where: T= temperature, P= total pressure (psig), m% H2S= mole percent H2S in the gas treatment process stream, and A,B,D,E= parameters estimated from the data by least squares fit to accumulated reference data.

It is possible to utilize the preceding equation to calculate the relative corrosion rate consequences if the wet gas taken from line 4 is desulfurized rather than desulfurizing the fuel gas 15, simply by dividing the predicted corrosion rate after the desulfurization by the predicted corrosion rate before desulfurization. Since the process steps after the wet gas compression must continue to operate at essentially the same pressure and temperature regardless of whether the gas stream has been desulfurized, the H2S concentration change is the only variable influencing the relative corrosion rate change. For example, the predicted change in the corrosion rate for carbon steel after wet gas desulfurization will decrease as follows: Cr2= Cr1*(2m%H2S)**{0.1540.05891*log(2m%H2S)} X 100% (lm%H2S)** fO. 1540.05891 *log(lm%H2S)} Thus the corrosion rate change following a 2.2 mole% H2S reduction to 730 ppm by volume will be 77% less than the corrosion rate before H2S reduction based on the following calculations: Cr2= Crl*(0.00073?** (0.1540.05891 *log(0.00073)} x 100% = Crl 23% (.022)** 1540.05891 *log(0.022)} Similar equations exist for other metals as well. A reduction of 77% in the corrosion rate of the metals that are used in the construction of gas treatment process equipment can lead to a significant decrease in the maintenance that must be done on that equipment with concurrent

savings in down time, parts, labor and so forth.

Furthermore, the capacity of the wet gas compressor is typically a through-put limiting device on the capacity of the FCC gas treatment process. When the acidic gases are removed from the wet gas stream, there is a corresponding reduction in the required compression horsepower needed for the wet gas compressor. This reduction in horsepower can be approximated by assuming that the gases involved obey the adiabatic equation describing the relationship between the pressure of an ideal gas and its volume. The work needed to compress these gases (i.e., gas sources that have been deacidified and those that still contain acidic gases) is calculated using the following equation: w = RT/n [ (PJP1)-lj or Bhp = T/520 x 0.063M/nE x [(P2/PI)n-1] where: w = work, same units as RT R = the gas constant T = absolute temperature at suction, R pl, p2 = absolute pressures at suction, discharge n = R/Cp=gamma-1/gamma gamma = Cp/Cv Cp, Cv = specific heat at constant pressure, volume M = SCF/min E = adiabatic efficiency Utilizing the foregoing equation, the compression horsepower savings can be estimated by calculating the compression workload for compressing either the wet gas containing acidic gases or the deacidified gas stream assuming the use of a single centrifugal compressor with a discharge pressure 12 kg/cm2 g (185.34 psia) under the example conditions set forth in Table 1.

TABLE 1 Fluid Compressed Sour Gas Sweet Gas Molar Flow (lbmoles/min) 16.59 l5.60 Acid Flow (rate removed) 0.99 6.0 Molecular Weight 25.05 24.41 Weight Flow (lbs/min) 415.7 380.9 Suction Temperature (°F) 104 93.4 Suction pressure (psia) 27.745 27.455 Inlet volume (ICFM) 3597 3354 Discharge Pressure (psia) 185.34 185.34 Compression Ratio 815.34/27.745=6.68 185.34/27.455=6.75 Assumed aver. Temp (°R) 200 200 k = Cp/Cv at aver. Temp 1.188 1.190 dTid. (oR) 564x(6.680-1582-1)=1 97.7 553.4(6.750JS961)=1 97.2 Discharged temperature (oR) 564+197.7=761.7 553.4+197.2=750.6 Compress (factor, suction) 0.9943 0.9943 Compress (factor, disch.) 0.9911 0.9916 Compress (factor, average) 0.9927 0.9930 Isentropic head (ftlb/lb) (1 545x0.9927x564x0.35)/ (1 545x0.993x553 .4x0.3563)/ (25.05x9.1582) = 76398 (24.41x0.1596)=77648 Assumed Assumed isentropic eff. 0.7 0.7 Gas horsepower (415.7x76398)/ (380.9x77648)/ (0.7x33000)=1375 (0.7x33000)=l 280 Mech. Losses (approx. hp) 1375°4=18 128004=17 Brake horsepower 1375+18=1393 1280+17=1297 Horsepower saving 1375 - 1280 = 95 hp = 7 % of Sour Gas hp duty Compression horsepower saving under the foregoing conditions is calculated to be 7%.

Thus, the removal of the acidic gases from the wet gas stream before it is compressed by the wet gas compressor can theoretically increase the capacity of the FCC gas treatment process by 7% leading to substantial savings within the petroleum industry. In fact, an 8% increase

for a 37,000 barrel per day FCC net gas feed rate into the gas treatment process can save the operator of the gas treatment plant about $500,000 per month.

The savings in equipment corrosion and capacity can be realized by the early deacidification of the wet gas stream. For example, in FIG. 2, a deacidification section 51, similar to the deacidification column 100 described below, can be inserted as an add-on section contained within the main fractionator column 10. By inserting a deacidification section in the main fractionator column 10, the acidic gases would be removed before the wet gas stream left the main fractionator column 10. The wet gas will enter the bottom of the extended deacidification section 51 where the wet gas is contacted with both an ammonia containing solution 106 and a water stream 108 before leaving the main fractionator 10 as a deacidified wet gas stream. The sour water stream generated by the deacidification section 51 will leave the main fractionator 10 as sour water stream 107.

Alternatively, a deacidification column 100 described in more detail below, may be inserted in line 4 to deacidify the wet gas before it reaches the first stage of the wet gas compressor, as illustrated in FIG. 3. In FIG. 3, the wet gas enters the bottom of the deacidification column 100 through line 4A and is contacted with an ammonia containing solution 106 and a water stream 108 before leaving the column 100 as a deacidified gas stream through line 4B.

The deacidification column 100 may also be inserted in line 7 to deacidify the gas stream before it enters the second stage of the wet gas compressor 30, as shown in FIG. 4. In FIG. 4, the wet gas enters the bottom of the deacidification column 100 through line 7A and is contacted with an ammonia containing solution 106 and a water stream 108 before leaving the column 100 as a deacidified gas stream through line 7B.

The deacidification of the wet gas stream, using the deacidification columns described below, is carried out early in the gas treatment process at low gas pressures and in the presence of oxygen. Thus, a deacidified gas stream progresses through the compression and absorption stages of the gas treatment process and exits ready to be treated for heavy hydrocarbon recovery in columns 60 and 70.

One embodiment of the deacidification column 100 is shown in Figure 5 and has been described in a PCT patent application (No. PCT/U.S. 95/09290), which is incorporated herein by reference. This column includes two single-bed packed sections: a lower section 102 and an upper section 104. The two sections are vertically aligned so that liquid can flow or cascade

from the upper section 104 to the lower section 102. Each section is filled with a packing material that is designed to allow a high mass transfer between a gas and a solvent while allowing the passage of the gas at low pressures. The packing materials may be made of ceramic, plastic or metal. The preferred packing material is sold by Glitsch International, Inc.

under the trademark Cascade Mini Rings and is described in Patents GB-A-1 385 672 and GB-A-1 385 673. An alternative packing material would be a structured type of packing material sold by Glitsch International, Inc. under the trademark GEMPAKB.

The lower section 102 of the deacidification column 100 represents the first stage in deacidifying a wet gas stream 103 that enters the bottom of the deacidification column 100.

As the gas stream rises, it enters the lower section 102 and is brought into countercurrent contact with an ammonia containing solution 106 having a sufficient quantity of ammonia to react with the hydrogen sulfide, the carbon dioxide and other acidic gases present in the gas stream. In this lower stage 102, the principle deacidification of the gas stream occurs as it is brought into contact with an ammoniacal solution which is dispersed onto the lower section 102 by a distribution device 210 described below. The distribution device 210 is designed to collect and disperse the ammoniacal solution in a substantially uniform manner onto the lower section 102.

The reacted gas stream leaves the lower section 102 as an initially deacidified gas stream 115 which still contains a definable quantity of acidic constituents principally comprised of hydrogen sulfide and carbon dioxide. The gas stream 115 also has a definable amount of ammonia which is stripped from the ammoniacal solution entering the lower section 102 from above.

The gas stream 115 rises around the outside of the distribution device 210 to enter the upper section 104 of the deacidification column 100. In the upper section 104, the gas stream 115 enters into countercurrent contact with a water stream 108 that enters the deacidification column through an upper inlet 33. The water stream 108 is fed into a distribution device 200 that is similar in design to the distribution device 210.

The ammonia entering the upper section 104 as a part of the gas stream 115 reacts with the water stream 108 to form ammonium hydroxide. The amount of water fed to the upper section 104 is at least sufficient to react with substantially all of the ammonia that enters the upper section 104 as a part of gas stream 115. The ammonium hydroxide formed in the upper section 104 provides a liquid phase that reacts with the remainder of the acid gases in the gas

stream 115, such as hydrogen sulfide, in the upper section 104. Hydrogen sulfide reacts with ammonia in a similar manner as the other weak acidic gases present in the gas stream. For the purposes of brevity hydrogen sulfide or H2S is herein used to represent all weak acids. The ammoniacal liquid generated in the upper section 104 by the interaction of the water stream 108 and the gas stream 115 forms a liquid stream 113 which falls back down the deacidification column 100. The liquid stream 113 contains not only ammonium hydroxide, but also ammonium salts formed from the interaction of ammonium hydroxide and the acidic gases. The liquid stream 113 enters the distribution device 210 where it is combined with the ammonia containing solution 106 entering a lower inlet 35. The mixture of the two liquids is distributed in a substantially uniform manner onto the lower section 102 and will interact in the lower section 102 with the wet gas stream 103.

The ammoniacal liquid mixture reacts with the gas stream in the lower section 102 as described above to form a reacted liquid stream 101 which leaves the lower section 102, and interacts briefly with the wet gas stream 103 before exiting the bottom of the deacidification column 100 as a total reacted liquid stream 107. This total reacted liquid stream 107 is conveyed to a sour water stripper or to a selective stripping column described below.

The efficiency of the deacidification column is affected by the free ammonia concentration in the ammonia containing solution 106 entering the lower inlet 35. Preferably, the molar ratio of ammonia to the sum of the acidic gases present in the wet gas stream, the ammonia containing solution 106 and the water stream 108 is equal to or greater than one.

In addition, the efficiency of each section of the deacidification column 100 is dependent on the mass transfer characteristics of the section packing material, the temperature of the gas and the liquid within the column bed and the contact time between the gas and the liquid within the column bed. These conditions will, for example, dictate the hydrogen ion concentration (pH) of the liquid stream exiting each section. Sufficient contact time between the gas and the liquid determines the ability of the many reactions to reach equilibrium, while the solution pH will dictate the molar ratio of the multiple salts that each acid can form with the free ammonia. A high pH will favor the formation of the more basic ammonium salts such as (NH4)2S, while a lower pH will favor the more acidic ammonium salts such as NH4HS.

A deacidified gas stream 105 exits from the top of the deacidification column 100. The performance of the deacidification column 100 and the concentration of hydrogen sulfide and other acidic gases in the deacidified gas stream 105 is monitored and controlled to meet or

surpass the appropriate government standards set for hydrogen sulfide in fuel gas. If the deacidified gas stream 105 contains a higher concentration of hydrogen sulfide than is desirable, the amount of free ammonia available for reaction in the lower section 102 can be increased appropriately. The operation of the deacidification column 100 can be designed to produce a deacidified gas containing 50 ppm or less of hydrogen sulfide. Preferably, the column 100 is configured to produce a deacidified gas ranging from below 1 ppm to 10 ppm of hydrogen sulfide.

The deacidified gas stream 105 is not only monitored for its concentration of hydrogen sulfide, but also for its concentration of ammonia vapor. The concentration of ammonia vapor lost out of the top of the deacidification column 100 should be kept to a minimum and is determined by the equilibrium temperature, water content and pressure within the upper section 104.

The temperature of the upper section 104 is governed by the temperature of the adsorbents entering the column (i.e., the liquids entering at inlets 33 and 35) and the temperature and water content of the wet gas stream 103 entering the column.

The temperature within the column is important to the entire operation of the column.

The vapor temperature for the gas streams 115 and 105 can be controlled by placing a cooling mechanism (not shown) either within the sections 102 and 104, or by positioning cooling surfaces (such as externally cooled coils) immediately above the section beds whereby the gas stream exiting the section will contact the cooling surface as described below. Alternatively, cooling devices may be placed in the feed lines that deliver the liquids to inlets 33 and 35.

Cooling devices are most likely to be incorporated into the deacidification process when the wet gas stream 103 contains a high concentration of acidic gases, since the principle reactions taking place in the deacidification column 100 (such as forming ammonium hydroxide and ammonium salts) are all exothermic. When the heat generated by the reactions in the column are large, a recirculating liquid contact cooling bed can be installed in the feed lines that deliver the water stream 108 and the ammonia containing solution 106 through inlets 33 and 35. The recirculated liquids can be cooled by a variety of mechanisms known to those skilled in the art.

The pressure can be controlled by manipulating the pressure within the column bed and by the selection of the packing material (which governs the pressure drop of the gas stream as it passes through the packing material).

FIG. 2, FIG. 6, FIG. 7A and FIG. 7B illustrate alternative embodiments of the

deacidification column 100. These alternative embodiments operate using the same general principles as the deacidification column 100, but have been designed to facilitate the introduction of a gaseous ammonia 109 into the column, rather than an ammonia containing solution 106.

FIG. 6 illustrates a deacidification column 120. In the deacidification column 120, the gaseous ammonia stream 109 is fed into the bottom of the column 120 through a bottom inlet 123. The wet gas stream 103 also enters the bottom of the deacidification column 120. The ammonia gas stream 109 and the wet gas stream 103 rise up the deacidification column 120 and enter a lower section 122 where the ammonia reacts with water to form ammonium hydroxide. The acidic gases in the wet gas stream react with ammonium hydroxide and ammonia in the lower section 122 to form ammonium salts.

The lower section 122 is wet with a first water stream 125 that enters the column 120 through an inlet 38 above a distribution device 210. The first water stream 125 is collected and mixed in the distribution device 210 with a liquid stream 124 originating from an upper section 104, which is essentially the same as the upper section 104 in the deacidification column 100. The combined liquid is dispersed onto the lower section 122.

A gas stream 126 emanates from the lower section 122 and rises to the upper section 104 where it interacts with a second water stream 127 added to the upper section 104 through an upper inlet 39. Substantially all of the ammonia escaping the lower section 122 in the gas stream 126 will react with the second water stream 127 to form ammonium hydroxide. The quantity of ammonium hydroxide formed in the upper section 104 is at least enough to form ammonium salts with the acidic gases present in the gas stream 126.

The ammonium hydroxide, the ammonium salts of the acidic gases and any unreacted water fall back down the column as liquid stream 124 and is combined with the liquids generated in the lower section 122. The total reacted liquid stream 107 exits the column 120 and is conveyed to a sour water stripper or to a selective stripping column described below.

The deacidification column 110, shown in FIG. 7A, has three sections of packing material: a first section 116, a second section 118 and an upper section 104 which is basically equivalent to the upper section 104 described for the deacidification column 100.

The first section 116 represents the first stage in deacidifying the wet gas stream 103.

The wet gas stream 103 enters the bottom of the deacidification column 110 and enters first section 116 where it is in contact with a first liquid stream 117 originating from above the

second section 118. The first liquid stream 117 contains, among other constituents, ammonium hydroxide and ammonium salts of the acidic gases found in the wet gas stream 103.

A sufficient quantity of ammonia vapors, to react with the acidic gases present in the wet gas stream 103, is fed as a gaseous ammonia stream 109 into the deacidification column 110 at first inlet 37 between the first section 116 and the second section 118. The gaseous ammonia stream 109 will react with the acidic gases in a gas stream 111 rising off of the first section 116 and with any water in the first liquid stream 117 falling from the second section 118 to form ammonium salts and ammonium hydroxide, respectively. The vertical location of the first inlet 37 is variable and will be determined by the operation of the deacidification column 110. Since entry of the ammonia stream 109 through the first inlet 37 may cause turbulence in the downward flow of the first liquid stream 117, a distribution device 210 (similar to the distribution device used above the lower section 102 in the deacidification device 100) collects the first liquid stream 117 and distributes it to the first section 116 in a substantially uniform manner.

A gas stream 111 (which has risen from the first section 116 and interacted with the ammonia vapors) continues upward to enter the second section 118. In the second section 118, the gas stream 111 will interact with the ammonia vapors, ammonium hydroxide and a second liquid stream 113 originating from the upper section 104 and distributed onto the second section 118 by a second distribution device 210.

A gas stream 119 leaves the second section and enters the upper section 104. The ammonia entering the upper section 104 as a part of the gas stream 119 reacts with the water stream 108 entering the column 110 through an inlet 33. The water stream 108 is distributed substantially evenly onto the upper section 104 by a distribution device 200, which is similar to the distribution device mounted on top of the upper section 104 of the deacidification column 100. The ammonium hydroxide formed in the upper section 104 from the reaction of the water stream 108 with ammonia provides a liquid phase that reacts with the remainder of the acidic gases in the gas stream 119.

When gaseous ammonia is used as the ammonia source for the deacidification columns 110 and 120, the operator of the deacidification column monitors the deacidified gas stream 105 to ensure that ammonia is not lost out of the top of the deacidification column in the deacidified gas stream 105. The concentration of the ammonia vapor discharged in the deacidified gas stream 105 is determined by the equilibrium pressure, temperature and water

content within the upper section 104 of the deacidification column.

Since the reaction of ammonia and water to form ammonium hydroxide is an exothermic reaction and can generate large quantities of heat when a gaseous ammonia source is used in the deacidification process, the temperature within the deacidification column and particularly the upper section 104 of the deacidification column becomes exceedingly important in capturing substantially all of the ammonia vapors. The temperature of the upper section 104 can be governed by the temperature and flow rate of the water stream 108, the temperature and water content of the wet gas stream 103 entering the column and the installation of one or more cooling mechanism in the top portion of the deacidification column. For example, FIG.

7B depicts a deacidification column 140 which is similar to the deacidification column 110, except that it has two pumparound cooling systems. Although any number of pumparound cooling systems can be used, FIG. 7B shows a deacidification column with two such systems (one pumparound system on the top of section 104 and one pumparound system beneath this same section). The upper pumparound system withdraws a descending liquid stream 153 close to the top of the deacidification column 140, pumps the liquid stream 153 with a pump 150 through a cooler 152 and returns the cooled liquid stream 153 back to the deacidification column 140. The lower pumparound works in a similar fashion utilizing a pump 170 to direct the liquid stream 173, withdrawn from the column 140, through the cooler 172 and back into the deacidification column 140.

In addition, cooling surfaces (not shown) can be used to help control the temperature within the deacidification column 140. Cooling surfaces, such as externally cooled coils, can be placed either immediately above the section beds whereby the gas stream exiting the section will contact the cooling surface, or in the feed lines that deliver the water stream 108 or gaseous ammonia 109 to the deacidification column.

The deacidified gas stream 105 exiting from the top of the deacidification columns 100, 110, 120, and 140 can be burned as fuel because these deacidification columns can be operated under conditions that will ensure that the hydrogen sulfide content of the deacidified gas stream 105 is within the desired limits set by the operator of the columns which is generally from about 250 ppm to about 50 ppm H2S. However, the deacidification columns described above can be used to reduce the H2S content in the deacidified gas stream 105, to less than 1 ppm, simply by adding more ammonia flow.

One aspect of the distribution columns 100, 110, 120 and 140 that increases the

columns' efficiency and decreases the gas pressure necessary to pass through the columns is the design of the distribution devices that are placed above each section of the columns that evenly distribute the liquids collected from above the distribution devices to the sections below the distribution devices. The distribution devices 200 and 210 used in the deacidification column 100 are illustrated in FIG. 8 and FIG. 9 respectively and are described in PCT Application No. PCT/U.S. 95/09290 and incorporated here by reference.

The distribution device 200, placed above the upper section 104 of the deacidification column 51, 100, 110, 120, or 140 is shown in FIG. 8 as a unitized cartridge for inserting into the deacidification column 51, 100, 110, 120, or 140. The distribution device 200 includes a frame support 201, which may conveniently be formed of upper and lower crossbars 203 connected by four support rods 202. A receptacle 205 is mounted on the frame to receive the liquid stream coming from above the receptacle 205 (water in the case of the upper section 104). The collected liquid stream is then substantially uniformly distributed over the upper section 104.

The receptacle 205 is designed to enhance the even distribution of the collected liquid over the section below. A preferred embodiment of the receptacle 205 has a surrounding wall 204 and a baseplate 206 containing numerous perforations 207 to aid in the irrigation of the section below. The baseplate 206 has a diameter that is smaller than the internal diameter of the column 100, in order to provide space for the gas stream to pass up the column 100 unobstructed. The area available for the passage of the gas stream is typically about 20-25% of the available area of a cross-section of the interior of the column 100. The distribution device 200 is typically mounted on a containment grid 209 that rests on top of the packing material.

The distribution device 210 is placed above the lower section 102 of the deacidification column 100 and is shown in FIG. 9. The distribution device 210 differs from the distribution device 200 in that it has a collection ring 216 attached to the frame 201 above the receptacle 205. A preferred embodiment of the collection ring 216 has an outside diameter that is greater than the diameter of the receptacle 205 and an internal diameter that is smaller than the diameter of the receptacle 205. The internal diameter of the collection ring 116 circumscribes an area that is available for the unobstructed passage of the gas stream after it passes the receptacle 205. By providing an unobstructed passage for the gas stream to rise past the distribution devices, the pressure drop in the gas stream as it transverses the deacidification

column 100 is minimized.

In addition, the outside diameter of the ring 216 is only slightly less than the internal diameter of the column 100 to facilitate the collection of the liquid falling from above the distribution device 210 which adheres to the walls of the column 100. The ring 216 will preferentially decline towards the center of the column 100 and direct the liquid from the walls of the column 100 towards the center of the receptacle 205. At an earlier point in this discussion references to other acid gases was made common with hydrogen sulfide. From this point forward, the same compounds are discussed individually.

A preferred embodiment of the gas treatment process and its component processes is further defined by reference to the following example which is meant to be illustrative not limiting.

EXAMPLE 1 The gas treatment process with the deacidification column 100 inserted into line 4A, as illustrated in FIG. 3, provides a deacidified gas stream 105 before the capacity-limiting compression step. A wet gas stream 103 taken from the FCC main fractionator overhead receiver 20 has the following composition expressed in percent by weight (% w): Water 2.77 Methane 16.34 Hydrocarbons (C2-C5) 59.55 Hydrogen 1.08 Nitrogen 11.15 Oxygen 0.19 Carbon monoxide 1.43 Carbon dioxide 4.50 Hydrogen sulfide 2.99 This wet gas stream 103 is fed into the base of the deacidification column 100 through line 4A upstream to the wet gas compressor 30 at a pressure of 191 kPa, a temperature of 40"C and at a flow rate of 11,314 Kg/h.

An ammonia containing solution 106, derived from an ammonia stripping column, is fed into the column 100 at a flow rate of 4,762 Kg/h and a temperature of 34"C. The ammonia containing solution has the following composition expressed in percentage by weight (% w): Water 67.22 Ammonia 20.07 Hydrogen sulfide 4.32 Carbon dioxide 8.39 The ammonia containing solution 106 reacts with the acidic gases in the wet gas stream 103

to form ammonium salts. The reacted gas stream continues to rise in the column 100 and enters the upper section 104.

A stream of water 108 is introduced into the column 100 above the upper section 104 with a flow rate of 50 m3/h and at a temperature of 34"C. The ammonia from the ammonia containing solution that rises to the top section 104 reacts with the water stream 108 to form ammonium hydroxide which then reacts with the remaining hydrogen sulfide and carbon dioxide in the gas stream to form ammonium salts. The resultant liquid stream which contains water and ammonium salts of carbon dioxide, hydrogen cyanide and hydrogen sulfide falls back down the column to contribute to the reactions taking place in the lower section 102.

After the wet gas stream has passed through the lower and the upper sections of the column 100 and has been in countercurrent contact with the described ammonia containing liquids therein, it is released from the top of the column as a deacidified gas stream 105 at a flow rate of 10,367 Kg/h. at a temperature of 34.2"C, and at a pressure of 189 Kpa. The deacidified gas stream 105 contains the following quantities of acidic gases: Hydrogen sulfide 10 ppm Carbon dioxide 5 ppm Ammonia 40 ppm This deacidified gas stream passes on through the gas treatment process where it is compressed by the wet gas compressor 30 and directed through the primary absorber 60 and the sponge absorber 70 before being used as a fuel gas.

A liquid stream 107 exits from the bottom of the deacidification column 100. The total reacted liquid stream 107 leaves the column 100 at a flow rate of 55,709 Kg/h and is sent to a selective stripping column. Liquid stream 107 has a temperature of 37"C and contains 1.63% by weight of carbon dioxide, 0.98% by weight of hydrogen sulfide, and 1.71% by weight of ammonia, predominantly in the form of ammonium carbonates and ammonium sulfides. The selective stripping column separates the acidic gases and ammonia from the liquid stream 107.

The deacidification columns described herein may be used to remove acidic gases, including hydrogen sulfide, from almost any gas stream and can be used to deacidify gases generated from the processing of petroleum, natural gas, wood and coal. The removal of the acidic gases with the deacidification columns described herein result in aqueous solutions containing a variety of compounds, including ammonia and hydrogen sulfide, that cannot be disposed of in a sewage treatment plant. Such aqueous solutions are generally referred to as "sour water."

Sour water generally requires the removal of the weak acids and volatile bases before it can be discharged into the environment. For example, the removal of H2S with ammoniacal solutions produce aqueous solutions containing significant quantities of (NH4)2S, NH4HS and possibly excess NH3. The separation of these compounds from a sour water stream is usually accomplished with a "sour water stripper", which is an apparatus for heating the sour water to temperatures which will break the ammonium sulfides and carbonates into ammonia, hydrogen sulfide and carbon dioxide and vaporize these gaseous compounds so that they can be withdrawn from the sour water stripper and the water stream. The resultant water stream (i.e., a stripped water stream) can be reused as a solvent or can be discharged into the environment.

A conventional sour water stripper (SWS) is illustrated in FIG. 10. A sour water stream 302 is initially heated in a heat exchanger 301 using the heat in the stripped water stream 305 coming off the bottom of the sour water stripper. This heated sour water stream 298 is directed into a SWS column 300, where it is contacted with hot vapors as it descends the SWS column 300 to further increase the temperature of the sour water stream. Heat is provided to the bottom of the SWS column 300 either directly as a steam stream 303, or indirectly via an optional reboiler 304.

As the sour water stream travels down the SWS column 300 and the steam stream 303 travels up the column, the temperature of the descending sour water stream will continually increase causing the more volatile compounds to rise up the SWS column 300. Due to the increasing temperature of the descending sour water stream and the progressively changing composition of the sour water stream, the ammonium salts derived from the interaction of ammonia and weak acids will be broken down to release their component gaseous compounds (e.g., ammonium sulfide breaks down to ammonia and hydrogen sulfide) which are withdrawn from the top of the SWS column 300 as an acidic gas stream 307. Ammonia, being much less volatile than some of the other compounds such as hydrogen sulfide, is one of the last compounds to be stripped from the descending sour water stream.

An overhead cooling process is typically employed at the top of the SWS column 300 to minimize water loss out the top of the SWS column 300. This cooling process is typically performed with a pump around system where a liquid fraction 317 is withdrawn close to the top of the SWS column 300, pumped with a pump 314 through a cooler 316 and returned to the SWS column 300. Alternatively, the acidic gas stream 307 may be cooled in a cooler 308 and separated from the resulting liquid condensate in a drum 309. The condensed liquid 312

is sent back to the SWS column 300 and the acidic gases 313 are processed further.

The acidic off-gases 307 and 313 are generally directed to a sulfur recovery unit for additional treatment. If the SWS column 300 is operated at pressures ranging from 10-20 psig and temperatures ranging from 160°-210° F the resulting acidic gas stream 307 will contain approximately 35% by volume of hydrogen sulfide, 35% by volume of ammonia, and varying amounts of carbon dioxide and water.

However, it would be advantageous to the operator of the sulfur recovery unit if the ammonia and the hydrogen sulfide removed from the sour water were recovered separately.

This is true because ammonia fed to a sulfur recovery unit can cause operating problems in the unit such as catalyst deactivation, equipment plugging, and lower sulfur recoveries. For example, a conventional sulfur recovery unit (i.e., a Claus sulfur recovery unit) must be specifically modified to oxidize the ammonia fed to the sulfur recovery unit or the unburned ammonia will bond with sulfur compounds, solidify and block the downstream condenser tubing. In addition, the cost of sulfur recovery is increased by both the wastage of the burned ammonia and by the increased load placed on the sulfur recovery unit by the inclusion of ammonia in the off-gas from which sulfur is to be recovered. Therefore, the use of the deacidification columns described above can be augmented by integrating the deacidification columns with a selective stripping column 320 or 360 and 380 as described below for separating hydrogen sulfide, ammonia and a stripped water source.

The selective stripping column 320 shown in FIG. 11 or the combination of an acid gas stripping column 360 and an ammonia stripping column 380 can provide a stripped water source 333 that can be discharged into the environment with less than 5 ppm of either ammonia or hydrogen sulfide. The stripped water source 333 can also be used as the water stream 108 in the deacidification columns 100, 110, 120 and 140 or at other steps in the gas treatment process. The recycling of water within the gas treatment process reduces the net water requirements of the gas treatment process and reduces the waste water discharge rates to waste water treatment plants.

The ammonia produced by the selective stripping process can also be recycled in its gaseous state or as an ammonia containing solution into the lower section of the deacidifying columns described above. The deacidification columns 110, 120, and 140 are specifically designed to use gaseous ammonia 109; while the deacidification column 100 is designed to utilize an ammonia containing solution 106. The reutilization of the isolated ammonia in the

deacidification of the wet gas stream in the deacidification columns saves the cost and environmental impact of having to constantly replenish the ammonia supply.

Furthermore, the acid gas produced by the selective stripping process is suitable for feeding into an unmodified sulfur recovery unit or a sulfuric acid plant. Separating the ammonia from the hydrogen sulfide not only decreases the maintenance on the sulfur recovery units, but it also increases the capacity of the sulfur recovery units.

The column 51 variant of these absorbers would utilize any one of the columns 100, 110, 120, or 140 by omitting a bottom cap 701, so that gas can enter the bottom of the column directly. The descending liquid 101 must then be collected in a well known chimney tray of conventional design and taken outside the column through a port in the vertical interior wall.

A chimney tray offers an upward passage for the gas while holding a reservoir of liquid around this passage area.

One embodiment of a selective stripping column 320 is depicted in FIG. 11. Although FIG. 11 shows how the selective stripping column 320 would be tied to the deacidification column 100, the selective stripping column 320 can be advantageously used in conjunction with deacidification columns 51, 110, 120, and 140, as well.

In FIG. 11, a wet gas stream 103, containing H2S, or other acidic gases, is fed to the bottom of the deacidification column 100. The gaseous stream 103 is brought into countercurrent contact with an ammonia containing solution 112, which may include acidic gas components such as hydrogen sulfide, in the lower section 102 of the deacidification column 100. It is important that the NH3 present in the ammonia containing solution 112 is in molar excess to the total concentration of weak acids entering the deacidification column 100.

In the upper section 104 of the deacidification column 100, an initially deacidified gas stream 115 originating from the lower section 102 is washed by an aqueous stream 333 of recycled water from the selective stripping column 320. The resulting liquid stream 113, which contains ammonium hydroxide and ammonium salts of the weak acids present in the gas stream 115, falls back into the lower section 102 of the deacidification column 100.

A deacidified gas stream 105 exits from the top of the deacidification column 100, while a total reacted liquid stream 107 leaves the bottom of the deacidification column 100.

The liquid stream 107 can be sent directly to the upper part of the selective stripping column 320 or it can be mixed with an externally supplied sour water stream 350 to form a cumulative sour water stream 302. The cumulative sour water stream 302 is conveyed to a heat exchanger

301 where it is heated before being sent to the selective stripping column 320 as a heated liquid stream 295.

As the sour water stream 295 descends the selective stripping column 320, it is heated further either by a steam stream 303 injected into the bottom of the column 320 or by heat generated by a reboiler 304. With the increasing temperature, the ammonium salts are broken down and the component gases volatized and sent out the top of the selective stripping column 320 as an acid gas stream 324 which may be sent directly to a sulfur recovery unit.

An overhead pumparound cooling process is employed at the top of the selective stripping column 320 to minimize the water loss out the top of the column. This cooling process is performed by withdrawing a liquid fraction 306 close to the top of the selective stripping column 320. pumping the liquid with a pump 314 through a cooler 316 to cool the liquid fraction 306. The cooled liquid can be split so that a first portion 317 is directed back into the selective stripping column 320 and a second portion 296 can be used to provide a part of the ammonia containing solution 112 injected between the upper and lower sections of the deacidification column 100.

Alternatively, the acid gas stream may be partially condensed by cooling the acid gas stream 324 with a cooler 308. A resulting liquid condensate 329 is separated in a drum 309 and sent back into the selective stripping column 320, while an acidic gas fraction 325 is directed to a sulfur recovery unit. This alternative cooling system is indicated by dashed lines.

The operator of the selective stripping column 320 can reduce the concentration of ammonia discharged in the acidic gas stream 324 by injecting an aqueous stream 328 into the top of the selective stripping column 320 to wash the acidic gas stream rising up through the column 320. The added aqueous stream 328 absorbs ammonia from the rising vapors which will in turn reform some ammonium-weak acid salts. These ammonium-weak salts will descend as a liquid stream down the selective stripping column 320 and the weak bonds in these compounds will be broken by the heat within the column. The more volatile acidic gases will exit the column 320 as the acidic gas stream 324.

Since ammonia is much less volatile than the acidic gases, the volume and temperature of the aqueous stream 328 can be used to control the amount of ammonia discharged in the acidic gas stream 324. The aqueous stream 328 can be provided from an external water source 318 and/or the stripped water stream 333. If the partial overhead condensing process described above is employed instead of the pumparound cooler 316, the aqueous stream 328 can be

joined with the returning liquid condensate 329.

The temperature of the aqueous stream 328 can be manipulated by varying the cooling delivered by the cooler 319 or the temperature of the external water source 3 18. In addition, the stripped water stream 333 is initially cooled when it is passed through the heat exchanger 301. Introducing a cooled aqueous stream 328 into the top of the selective stripping column 320 will decrease the temperature in the top of the selective stripping column 320, causing the less volatile ammonia vapors to condense and fall back down into the column 320. Thus, the ammonia concentration can be reduced from approximately 34% by volume of the acidic gas stream 307 withdrawn off the conventional SWS column 300 to less than 1% by volume of the acidic gas stream 324 drawn off the selective stripping column 320 by installing a cooled water wash 340 at the top of the selective stripping column 320 or by increasing the cooling service of the cooler 316. In fact, the selective stripping column 320 can be designed to yield an acidic gas stream 324 with 5 ppm or less of ammonia by controlling the flow rate and temperature of the aqueous stream 328.

When the cooled water wash 340 is not installed and wash water 328 is not used in the selective stripping column 320, the full concentration of ammonia gas released from the sour water stream in the column 320 will be discharged in the acidic gas stream 324. If fresh ammonia is constantly being added to the system from the external sour water stream 350, the selective stripping column 320 must discharge that ammonia either into the acidic gas stream 324 or into the stripped water stream 333. Thus if ammonia is not pulled off the selective stripping column 320 to be used elsewhere, the acid gas stream 324 must contain approximately an equal quantity of ammonia as was added to the system in the liquid stream 107 or 350, since typical environmental regulations forbid the release of more than 10 ppm of ammonia or hydrogen sulfide in the discharged water.

Therefore, if the ammonia concentration of the acidic gas stream 324 is to be reduced and the stripped water stream 333 is to contain less than 5 ppm ammonia, ammonia must be drawn off the selective stripping column 320 somewhere else. For example, the ammonia containing solution 112 that is used by the deacidification column 100 can be taken from the selective stripping column 320 by collecting a liquid stream from any location within the column 320, such as a stream 335 and/or obtaining a cooled fraction exiting the cooler 316 as liquid stream 296.

The ammonia containing solution 112 taken from the selective stripping column will

likely contain ammonia, some acidic gases ammonium salts of the acidic gases, and other components. However, as long as these solutions contain sufficient ammonia and are cooled below the saturated temperature for ammonia and the acidic gases by a cooler 347, these ammonia containing solutions can absorb additional ammonia and acidic gases. In practice the flow rate of the ammonia containing solution 112 and its temperature are adjusted until the total molar quantity of acid gases escaping from the lower section 102 in the gas stream 115 is less than the molar quantity of ammonia and ammonium salts in the liquid stream 113.

In order to minimize the internal liquid loading within the selective stripping column 320, it is preferable, although not required, to insert the sour water liquid stream 107 into the selective stripping column 320 above the point where the ammonia containing solution is withdrawn from the column 320. For instance, when a side draw is extracted from the column below the cooled water wash 340, such as illustrated in FIG. 11 as the stream 335, the sour water liquid stream 107 would preferably be added to the column 320 as the heated liquid stream 295. Yet when the ammonia containing solution is drawn from the cooled pumparound liquid stream, shown in FIG. 11 as the stream 296, it would be preferable to insert the sour water liquid stream 107 into the column 320 mixed in with the cooled pumparound condensate 329 (not shown).

Alternatively, it is also possible to withdraw a gaseous ammonia stream 280 from the selective stripping column 320 and inject this ammonia stream 280 into the bottom of the deacidification 120 through inlet 123 or into the bottom section of the deacidification column 110 through inlet 37 and similarly by injecting the ammonia stream 280 into the deacidification column 140 through inlet 37.

When a gaseous ammonia is used as the ammonia source in the deacidification columns, an increased flow of the stripped water 333 or an increased cooling of the stripped water 333 by a cooler 345 may be required to capture the ammonia vapors to ensure that ammonia or the acid gases do not escape in the deacidified gas stream 105.

By manipulating the flow rates and temperatures of the recycled stripped water stream 133, as well as, the source and quantity of ammonia put into the deacidification column 100, the ammonia content of the deacidified gas stream 105 can be controlled to extremely low levels, generally less than 50 ppm with levels as low as 28 part per billion being achievable.

The acidic gases removed from the wet gas stream 103 by the deacidification column 100 are sent to the selective stripping column 320 in a total reacted liquid stream 107 where the acidic

gases are selectively removed in a concentrated form and directed to a downstream acidic gas disposal system (such as a sulfur recovery unit) or other acidic processes benefited by the concentration of acidic gases or the pressure at which the separation can be achieved.

The selective stripping column 320 can function well at pressures that are less than or equal to atmospheric pressure. The selective stripping column 320 can also function at elevated pressures up to the critical point pressure (88.9 atm) of hydrogen sulfide, where hydrogen sulfide will no longer vaporize. Therefore, the pressure of the selective stripping column 320 can be raised as desired to increase the pressure of the acidic gas stream 324 or an ammonia gas stream drawn off the column 320. A liquid acidic gas stream can also be produced if the column pressure is raised to a pressure sufficient to condense the gases using refrigeration or utility cooling devices.

A preferred embodiment of the acidification column 100 interfaced with the selective stripping column 320 is further defined by reference to the following example which is meant to be illustrative not limiting. Although the deacidification column 100 and the selective stripping column 320 have been described as a part of the FCC gas treatment process, these columns can also be used to deacidify sour gases from a vacuum distillation unit or any sour gases of any kind produced from other deacidification absorbers.

EXAMPLE 2 A sour gas stream produced by a vacuum distillation column overhead jet ejector system (i.e., Vacuum Non-Condensible Gas or VNCG) contains light hydrocarbons, oxygen, water and 14.3% by volume hydrogen sulfide. This VNCG is fed into the bottom of a deacidification column 100. The deacidification column 100 has an upper section 104 and a lower section 102, both of which are packed with CASCADE MINI-RINGSB or GempakB. The deacidification column 100 is 400 mm in diameter and has a lower section 102 that is 5 m in height and an upper section 104 that is 4 m in height. The lower and upper sections are separated by a distribution device 210.

The VNCG is fed into the bottom of the deacidification column 100 at a flow rate of 640 kg/h and rises to the lower section 102 where it is in contact with an ammonia containing solution 112 which enters the deacidification column 100 above the lower section 102 and is distributed onto the lower section by the distribution device 210. The ammonia containing solution 112 was taken as stream 335 from the tray below the site where the sour water is fed to the selective stripping column 320 and was cooled to 450C in the heat exchanger 347 as

depicted in FIG. 11. The cooled ammonia containing solution 112 was fed into the deacidification column 100 at a flow rate of 650 Kg/h. This ammonia containing solution 112 contains 20.96% by weight of NH3 and 0.95% by weight of H2S.

The ammonia in the ammonia containing solution 112 reacts with the hydrogen sulfide in the VNCG to form ammonium sulfide. An initially reacted VNCG gas stream 115, which contains ammonia and some residual hydrogen sulfide, continues up the deacidification column 100 to enter the upper section 104. In the upper section 104 the gas stream 115 is washed with 3,060 Kg/h of a stripped water stream 333 that is withdrawn from the bottom on the selective stripping column 320 and fed into the top of the deacidification column 100. The stripped water stream 333 contains less than 10 ppm of H2S and less than 30 ppm of NH3 and has been cooled by the cooler 345 to 450C.

From the top of the deacidification column 100, 55 Kg of a deacidified gas stream 105 is obtained which has less than 50 ppm of NH3 and less than 1 ppm of H2S. From the bottom of the deacidification column 100, a total reacted liquid stream 107 containing 130.5 Kg/h of H2S and 104.5 Kg/h of NH3 (as NH4HS and NH4)2S) is withdraw at a flow rate of 7,247 Kg/h and joined to a 62,000 Kg/h sour water liquid stream 350 from the refinery which contains 1.22% by weight of NH3 and 2.5% by weight of H2S. The cumulative sour water stream 302 is heated by the heat exchanger 301 and fed into the selective stripping column 320 as heated liquid stream 295. The heated liquid stream 295 is stripped of acidic gases by vapors generated by the bottom reboiler 304.

From the tray below the feed tray, an ammonia containing solution 335 is withdrawn, cooled, and fed into the deacidification column 100 as the ammonia containing solution 112 described above. Furthermore, part of the overhead vapors of the column 320 are cooled by an overhead condenser where some vapors are condensed by cooling the vapors with the cooler 308 and returning the liquid to the top of the selective stripping column 320.

The deacidified gas stream 324 or 325 is discharged from the top of the selective stripping column 320 at a flow rate of 3,000 Kg/h. Since the cooled water wash 340 was not used in this example of the selective stripping column 320, the deacidified gas stream 324 contains 25.2% by volume of NH3 and 54% by volume of H2S (corresponding to most of the NH3 and H2S in the cumulative water stream 295 fed into the selective stripping column 320).

The stripped water stream 333 that is withdrawn from the bottom of the selective stripping column 320 at a flow rate of 62.147 Kg/h contains less than 10 ppm of H2S and less

than 30 ppm of NH3. The stripped water stream 333 is utilized as the water source fed into the upper section 104 of the deacidification column 100 and as the aqueous stream 328 fed into the top of the selective stripping column 320. The remainder of the stripped water stream is suitable to be discharged into the environment.

FIG. 12 depicts a two column stripping unit that will separate and recover ammonia and any acidic gas stream (containing hydrogen sulfide, carbon dioxide, and other acidic gases), while producing a stripped water stream suitable to be recycled into the upper section of the deacidification columns described above, the top section of the different stripping columns described below, or discharged into the environment. A preferred embodiment of the two column stripping unit is shown in FIG. 12 which has both an acid gas stripping column 360 and an ammonia stripping column 380. This embodiment of a multi-column stripping unit represents a sour water extractive distillation process whereby high purity acid gas or gases is produced by the acid gas stripper column 360 and low pressure and high purity ammonia is produced by the ammonia stripping column 380.

If it is desirable to separate and purify two or more acidic gases, either more or less volatile than hydrogen sulfide, then additional stripper columns configured identically to the acid gas stripping column 360 will be required. One additional stripper column should be added for each additional acidic gas product desired and these additional stripper columns should be assembled in the descending order of the gas product's volatility. If additional stripper columns are required, then the bottom stream resulting from the first column would become the feed gas for the second column and so forth. The last column is such a series will always be used to separate ammonia from water. For simplicity, FIG. 12 depicts only one acid gas stripping column.

A preferred embodiment of the sour water stripping system depicted in FIG. 12 can be used to remove acidic gases and ammonia from sour water. Sour water from various sources (e.g., an external source 350, the ammonia stripping column 380 or from the deacidification columns described above) can be mixed to form a cumulative sour water stream before entering the acid gas stripping column 360.

The cumulative sour water stream may be split into two streams, 310 and 311, where the stream 310 enters the acid gas stripping column 360 directly and the stream 311 is pre-heated by the heat exchanger 301 before entering the column 360.

In the acid gas stripping column 360 the hydrogen sulfide is driven off the top of the

column in a hydrogen sulfide stream 364 by applying heat to the bottom of the acid gas stripping column 360 in a similar manner as previously described for the selective stripping column 320 illustrated in FIG. 11. Heat can be generated with the injection of a steam stream 363 or by heat added by a reboiler 367. As vapors created by this heat rise up the acid gas stripping column 360, the heat causes the ammonium sulfide salts to disassociate releasing hydrogen sulfide and ammonia. The hydrogen sulfide will leave the top of the acid gas stripping column 360 as the hydrogen sulfide stream 364.

In order to prevent the ammonia from leaving the acid gas stripping column 360 with the hydrogen sulfide stream 364, an aqueous solution 366 is added to a top wash section 418 in the upper portion of the acid gas stripping column 360. The discharge of ammonia in the hydrogen sulfide stream 364 can be controlled by the flow rate, composition, and temperature of the aqueous solution 366.

Although the temperature of the aqueous solution 366 is a major consideration in reducing the amount of ammonia released in the hydrogen sulfide stream 364, a substantially pure H25 stream 364 (containing from about 1 to about 250 ppm of ammonia) can be achieved without refrigerating the aqueous solution 366, with the proper pressure at the top of the column. Typically, utility cooling water or air fin cooled water having a temperature ranging from about 105° to about llO"F is all that is required. If a high concentration of hydrogen sulfide in the cumulative sour water stream requires more energy input than the utility cooling can offset, then a liquid stream 373 can be removed from the column 360, pumped by a pump 369 through a cooler 371 and returned to the column 360. The cooled liquid stream 373 is returned to the gas stripping column 360 at a zone below the water wash section 418, but above the uppermost sour water feed location. By regulating the flow rate and fluid temperature of the liquid stream 373, the column overhead temperature and therefore the ammonia and water content of the hydrogen sulfide stream 364 can be carefully controlled.

The acid gas stripping column 360 may be constructed to produce an ammonia containing solution 112 to be used in the deacidification column 100. The ammonia containing solution 112 can be drawn from the acid gas stripping column 360 by either collecting descending liquid from within the acid gas stripping column 360 such as a liquid stream 372, or by using the partially stripped water stream 374 taken from the bottom of the acid gas stripping column 360. It is also possible to provide a gaseous ammonia source 378 to the deacidification column 110, 120 or 140 by drawing an ammonia rich gaseous stream 376 from

the side of the acid gas stripping column 360 and injecting this ammonia rich gaseous stream 376 into the deacidification column 110, 120 or 140 as the gaseous ammonia source 378.

However, the injection of a gaseous ammonia into the deacidification column may require that either the flow rate or the cooling of the water stream 362 be increased. The efficiency of the deacidification column shown in FIG. 12 in capturing hydrogen sulfide with ammonia and ammonia with the water stream 362 can be manipulated by the same factors discussed in reference to FIG. 11.

Control of the temperature and flow rate of the aqueous solution 366 and the pumparound stream 373 can prevent excessive ammonia loss from the sour water stripping system as a whole. The ammonia loss that does occur can be replenished either by adding minimal quantities of ammonia from an external supply stream 368 or by the ammonia concentration present in the cumulative sour water stream fed into the acid gas stripping column 360 from streams 107 and 350.

The partially stripped liquid stream 374 leaving the bottom of the acid gas stripping column 360 is fed to the ammonia stripping column 380 above at least one zone of liquid/vapor mass transfer as stream 406. To vaporize the ammonia and any residual hydrogen sulfide in stream 406, heat must be added to the bottom of the ammonia stripping column 380 either in the form of direct heat through steam injection as stream 375, or indirectly through the operation of the reboiler 377. Using an adequate combination of heat input and mass transfer devices, levels of ammonia and hydrogen sulfide in the stripped water stream 362 can be less than 5 ppm of free NH3 and 1 ppm of H2S or other weak acid compounds. Even ammonia captured in fixed ammonium salts can be released within either the acid gas stripping column 360 or the ammonia stripping column 380 by injecting a sufficient quantity of a base that is stronger than ammonia, such as caustic soda, to displace the fixed ammonia (not shown).

A pumparound installed in the ammonia stripping column 380 above the site where the partially stripped water stream 406 is fed into the ammonia stripping column 380 allows the operator to control the ammonia flow up the ammonia stripping column 380. The pumparound draws descending liquid from the column 380 using a pump 381 to pump fluid stream 388 through a cooler 383 and back into the ammonia stripping column 380.

A highly purified ammonia stream 395 is achieved by adding wash beds 420 above the pumparound which uses the cooler 383. The ammonia stripping column 380 depicted in FIG.

12 shows two such washing beds 420. If no special measures are taken the residual H2S, that

is more volatile than the ammonia, and similar acid gases, would leave the ammonia stripping column 380 in the ammonia stream 395. However by regulating the flow rates and temperatures of the wash solutions used in the wash beds 420 in the top of the ammonia stripping column 380, the release of hydrogen sulfide in the ammonia stream 395 can be kept at minimal levels.

Water is added above each of the two washing beds 420. The preferred source for this water is the stripped water stream 362 that has been cooled by heat exchangers 301 and 389 before entering the ammonia stripping column 380 as water streams 387 and 385.

Alternatively, an external clean water stream may be added to the ammonia stripping column 380 as water stream 390. By contacting the gases rising from the pumparound zone with water, ammonia is condensed to form ammonium hydroxide, then one or both of the salts (NH4)2 S and NH3H2S is formed.

All the water washes from the two washing beds 420 are totally withdrawn from the ammonia stripping column 380 as liquid streams 391 and 392. By a unique use of the known constant boiling phenomenon, any residual H2S fed to the ammonia stripping column 380 by the partially stripped water stream 374 can be removed from the ammonia stripping column 380 without contributing H2S to either the ammonia stream 395 or the stripped water stream 362. In fact, an ammonia stream 395 having less than 1 ppm H2S can be achieved by using this extractive distillation technique. The temperature and flow rate of the water streams 387 and 385 can be manipulated to achieve the desired level of H2S content in the ammonia stream 395.

If either liquid aqueous or liquid anhydrous ammonia is the desired product 396 or 397, an overhead partial condenser (including a cooler 308 and a drum 309) or a pumparound zone (including a pump 314 and a cooler 316) can be used above the two washing beds 420 to condense the desired liquid ammonia product. To produce aqueous ammonia, some additional water must be added to the top of the ammonia stripping column 380 as stream 393.

In addition to the other advantages of the ammonia stripping column 380, the ammonia stripping column 380 can be modified in a variety of ways to withdraw liquid streams for use elsewhere within the system shown in FIG. 12, such as the examples given below: (a) the liquid streams 392 and 391 can be combined with other sources of sour water to make up the cumulative sour water streams 310 and 311 that are fed into the acid gas stripping column 360;

(b) an ammonia containing solution (such as stream 416) can be drawn from the liquid descending the ammonia stripping column 380 and fed into the deacidification column 100 as solution 112; (c) an ammonia containing solution can be withdrawn from the top pumparound as stream 402, or from the condensate 311 resulting from the overhead partial condenser as stream 404, that can be fed into the deacidification column 100 as solution 112; (d) a gaseous ammonia vapor can be drawn as stream 386 from the ammonia stripping column 380 and fed into the lower end of a deacidification column 110, 120, and 140 as gas stream 378; (e) the ammonia stream 395 can be fed into the bottom of deacidification columns 110, 120 or 140 as an ammonia source (not shown); (f) the partially stripped water stream 374 can be fed to the deacidification column 100 as the ammonia containing solution 112; and (g) the stripped water stream 362 can be fed into the upper section of the deacidification column 100 as stream 362, into the acid gas stripping column as stream 366, and into the top of the ammonia stripping column 380 as bed washing streams 387 and 385.

The acid gas stripping column 360 and the ammonia stripping column 380 can function well at pressures that are less than or equal to atmospheric pressure. The acid gas stripping column 360 and the ammonia stripping column 380 can also function at elevated pressures until the respective critical point pressures of 88 atm for hydrogen sulfide and 113 atm for ammonia is reached, where ammonia will no longer vaporize. Thus, the pressure of the stripping columns 360 and 380 can be raised as desired to increase the pressure of either the hydrogen sulfide stream 364 or the ammonia stream 395. In fact, liquid hydrogen sulfide or liquid ammonia can be produced if the column pressure is increased sufficiently to condense the hydrogen sulfide or ammonia using refrigeration or utility cooling water.

The deacidification columns and the sour water stripping units (or selective stripping columns) can be applied to the FCC gas treatment process as described in detail above. The deacidification columns and the selective stripping columns can also be applied to the deacidification of a non-condensible gas stream coming from a vacuum distillation unit, or any other sour gas source, as described in the following example which is meant to be illustrative and not limiting.

EXAMPLE 3

A sour gas stream produced by a vacuum distillation column overhead jet ejector system (i.e., Vacuum Non-condensible Gas or VNCG) contains light hydrocarbons, oxygen, water and 22.55% by volume of hydrogen sulfide. This VNCG is fed into the bottom of a deacidification column 100. The deacidification column 100 has an upper section 104 and a lower section 102, both of which are packed with 25 mm CASCADE MINI-RINGS, and separated by a distribution device 210. The deacidification column 100 has a diameter of 350 mm, a lower section that is 4.5 m in height and an upper section that is 3.5 m in height.

The VNCG is fed into the bottom of the deacidification column 100 at a flow rate of 547 kg/h and rises to the lower section 102 where it is in contact with an ammonia containing solution 112 which contains 20.96% by weight of NH3 and 10.34% by weight of H2S and is fed into the deacidification column 100 at a flow rate of 650 Kg/h.

The ammonia in the ammonia containing solution 112 reacts with the hydrogen sulfide in the VNCG to form ammonium sulfide. An initially reacted VNCG gas stream 115, which contains ammonia and some residual hydrogen sulfide, continues up the deacidification column 100 to enter the upper section 104. In the upper section 104 the gas stream 115 is washed with 2,600 Kg/h of a water stream that contains less than 10 ppm of H2S and less than 30 ppm of NH3 and has been cooled to 350C, without refrigeration.

From the top of the deacidification column 100, a deacidified gas stream 105 is discharged at a flow rate of 407 Kg/h which has less than 50 ppm of NH3 and less than 1 ppm of H2S. From the bottom of the deacidification column 100, a total reacted liquid stream 107 containing 190.4 Kg/h of H2S and 136.3 Kg/h of NH3 (mainly as NH4HS and (NH4)2S) is withdrawn at a flow rate of 3390 Kg/h.

Although this particular example describes the deacidification column 100 and the selective stripping system including the acid gas stripping column 360 and the ammonia stripping column 380 as a standalone facility, these columns can be advantageously utilized in the deacidification of any sour gas stream or in the stripping of any sour water source.

This cumulative sour water stream 311 is fed into the acid gas stripping column 360 where substantially all of the hydrogen sulfide contained in the cumulative sour water stream is stripped out of the sour water stream by the vapors generated by the reboiler 367 at the bottom of the acid gas stripping column 360 to produce an acid gas stream 364. In order to avoid ammonia loss with the hydrogen sulfide in the acid gas stream 364, a water stream 366 is fed to the top of the acid gas stripping column 360 at a flow rate of 400 K g/h. In this way

123 Kg/h of substantially pure, water saturated H2S is discharged as a hydrogen sulfide stream 364 from the top of the acid gas stripping column 360.

A partially stripped water stream 374, containing 1.83% by weight of H2S and 3.72% by weight of NH3, is withdrawn from the bottom of the acid gas stripping column 360. This partially stripped water stream 374 is fed into an ammonia stripping column 380 where substantially all of the NH3 is separated into an ammonia gas stream 395 and any remaining hydrogen sulfide is recycled back to the acid gas stripping column 360 in liquid streams 391 and 392.

One advantage of the ammonia stripping column 380 is that an ammonia containing side stream 386 can be drawn from the side of the ammonia stripping column 380 that is suitable for use in the deacidification column 100. This ammonia containing stream 386 can be fed to the deacidification column 100 between the upper and lower sections of the deacidification column 100 as the ammonia containing solution 112. Likewise, an ammonia source can be drawn from the top of the ammonia stripping column to be utilized as the ammonia source in the deacidification column 100. For example, either an ammonia containing condensate 311 can serve as an ammonia containing solution 112 for the deacidification column 100 or the ammonia gas stream 395 can be injected into the bottom of the deacidification column 110, 120, or 140.

The stripped water stream 362 that is withdrawn from the bottom of the ammonia stripping column 380 at a flow rate of 3013 Kg/h is exceptionally clean water. A portion of the stripped water stream 362 is utilized as the water source that fed into (a) the upper section 104 of the deacidification column 100, (b) the top of the acid gas stripping column 360, and (c) the top of the ammonia stripping column 380. The remainder of the stripped water stream (approximately 13 Kg/h) may be used elsewhere within the refinery or may be discharged into the environment.

The improved deacidification columns described above permit the removal of acidic gases, particularly hydrogen sulfide, from any sour gas stream. The acidic gases are removed from the sour gas streams by binding them to ammonia to form weak ammonium salts that can be dissolved in an aqueous solution to form sour water. However, hydrogen sulfide and the other acidic gases are environmental pollutants that must also be removed from the sour water before it can be released into waste water plants. In order to decrease the concentration of hydrogen sulfide in the environment, it is typically transformed to elemental sulfur in a sulfur

recovery unit.

FIG. 13 depicts the conventional means that is currently used to transform gaseous hydrogen sulfide into elemental sulfur. In order to transform the hydrogen sulfide to sulfur the hydrogen sulfide must first be collected and concentrated. Today the hydrogen sulfide is collected and concentrated using an amine absorber 80 in conjunction with an amine stripper 90. For example, the use of an amine absorber 80 and an amine stripper 90 to remove hydrogen sulfide from a fuel gas and to concentrate that hydrogen sulfide in an acidic gas stream has been described above and is illustrated in FIG. 1. A complex petrochemical plant, or refinery, may have a number of amine absorbers and only a few amine strippers that will provide an acidic gas stream 602 into a modified Claus unit 650, a specific type of a sulfur recovery unit, depicted in FIG. 13. A typical acidic gas stream 602 will contain approximately 85% by volume H2S with the remainder of the gas being made up of water, carbon dioxide and hydrocarbons. To achieve a higher purity of hydrogen sulfide in the acidic gas stream separated from an amine absorbent would require that the amine stripper 90 be operated at a higher temperature and pressure which would cause the thermal degradation of the amine.

Another common source for hydrogen sulfide is an acidic gas stream separated from sour waters by a sour water stripper 300 as described above and depicted in FIG. 10. The sour water is stripped of acidic gases by the application of heat to provide an acidic gas stream 307.

The acidic gas stream 307 derived from a sour water stripper 300 will generally contain about 35-40% by volume H2S and about 35-40% by volume of NH3.

Today the acidic gas streams recovered from the amine stripper 90 and the sour water stripper 300 are fed directly into a modified Claus unit 650 as shown in FIG. 13. A conventional sulfur recover)' unit (i.e., a Claus sulfur recovery unit) must be specifically modified to fully oxidize gases containing 250 ppm by volume or more of ammonia. If the ammonia is not burned off, it will bond with sulfur compounds, solidify and block the downstream condenser tubing and impede the catalyst performance. In addition, the cost of sulfur recovery is increased by both the requirement to burn the ammonia and by the increased load placed on the sulfur recovery unit by the inclusion of the ammonia in the gas volume sent to the sulfur recovery unit.

Current environmental regulations usually require the recovery of 98.6% of the sulfur from gases having sulfur components. The conventional sulfur recovery technology is limited in its ability to recover sulfur by the ability of the modified Claus sulfur recovery unit 650 to

condense liquid sulfur from the acidic gas streams fed into the sulfur recovery unit.

A residual gas stream 665 is taken off the modified Claus sulfur recovery unit 650 after the sulfur has been condensed. This gas stream 665 contains nitrogen, water, carbon dioxide and low levels of hydrogen sulfide and sulfur dioxide. In an effort, to recover as much sulfur as possible the gas stream 665 is sent to a hydrogenerator 375 where the trace amounts of sulfur dioxide are converted to hydrogen sulfide and a gas stream 667 containing this hydrogen sulfide is sent to an amine absorber column 80 and amine stripper column 90. The hydrogen sulfide that is stripped from the amine stripper 90 is recycled back to the modified Claus sulfur recovery unit 650 as gas stream 681. The deacidified gas 671 is incinerated in an incinerator 690.

The condensed liquid sulfur is sent from the modified Claus sulfur recovery unit 650 to a storage pit 670 as stream 661. As the liquid sulfur cools and is depressurized H2S gas will evolve. This H2S gas must be captured and destroyed to avoid hazard and polluting the air.

Typically, an air stream 672 is swept across the sulfur storage pit 670 to purge the evolving H25 and carry it safely to the incinerator 690 as a purged gas stream 824 to be burned with the deacidified gas 671 from the hydrogenerator 375 using a fuel stream 392. The H2S content of stream 824 contributes significantly to the lessor sulfur recovery performance of the conventional sulfur recovery unit.

FIG. 14 illustrates how the deacidification columns and the selective stripping columns described herein can be used to increase sulfur recovery to at least 99% in a high pressure sulfur recovery unit 651.

One of the deacidification columns (columns 100, 110, 120 or 140) described above can effectively replace a vapor contacting amine absorber 80 wherever it is used within a refinery. Furthermore, there may still be a need for an amine stripper 90, and its vapor product can also be treated by a deacidification column as described above. One of the advantages of the deacidification columns is that they generate a sour water stream that can be treated along with the other sour water produced within the refinery.

The sour water can be more effectively treated using the selective stripping column 320 or the multi-column selective stripping apparatus (columns 360 and 380) than the conventional sour water stripper 300. Using the two-column selective stripping apparatus illustrated in FIG.

12, an individual acidic gas stream can be produced that is 95-99% composed of a specific acidic gas, such as hydrogen sulfide. The selective stripping columns can be operated under

high pressures, including pressures that are above the 165 to 315 psia (1,143 to 2,170 kpa) generally cited for the high pressure sulfur recovery units.

The selective stripping column 320 and the acid gas stripping column 360 have the capability to generate a high pressure, substantially pure stream of hydrogen sulfide (i.e., containing from less than 1 ppm by volume to 250 ppm by volume of contaminating ammonia) that can be fed directly to the high pressure sulfur recovery unit 651. The production of a highly purified hydrogen sulfide stream avoids the need to modify the Claus sulfur recovery unit and reduces the size and maintenance of the sulfur recovery units. In addition, the use of a high pressure, highly purified source of hydrogen sulfide in conjunction with the described deacidification columns can increase the efficiency of the high pressure sulfur recovery unit 651 to achieve 99% or more sulfur recovery while decreasing sulfur emissions into the atmosphere.

Ammonia based chemical processes will also benefit from the ability to generate a highly purified, high pressure ammonia gas stream from the ammonia stripping column 380.

The ammonia stripping column 380 can generate an ammonia gas that contains only minimal amounts of hydrogen sulfide in it (i.e., from less than 1 ppm by volume to 50 ppm by volume of hydrogen sulfide) at elevated pressures ranging from about 15 to about 300 psia (103 to 2070 kpa) without having to compress the ammonia gas. Furthermore, the ammonia stripping column allows for the condensation of highly purified ammonia liquid within the ammonia stripping column 380 using 100"F fair fin or water cooling utilities, provided that the operating pressure of the ammonia stripping column 380 is equal to or greater than 211 psia.

Crucial to the performance of the acid gas stripping column 360 and the ammonia stripping column 380 is the ability to perform the separation of the hydrogen sulfide and ammonia at fluid temperatures that exceed the thermal tolerance of the amine absorbers.

Thus, any industrial operation, such as a refinery, can benefit from using the ammoniacal deacidification columns described above to treat both high and low pressure acidic gas streams that are found within the facility. These low pressure deacidification columns are particularly beneficial in treating oxygenated gas streams such as VNCG and FCC wet gas to avoid oxygen degradation of the amines. Deacidification of a FCC wet gas stream can be done directly using the deacidification columns 51, 100, 110, 120 or 140; or indirectly by treating the hydrogen sulfide released from an amine stripper 90 to significantly reduce the ammonia contamination of the hydrogen sulfide stream before it is fed into the sulfur recovery unit. By

treating the individual gases that make up the refinery fuel gas supply to hydrogen sulfide levels of less than 1 ppm by volume to 10 ppm by volume can assure that all refinery fuels contain these low levels of hydrogen sulfide without requiring the compression of any hydrocarbon gas to greater than atmospheric pressure.

A highly purified acid gas stream can be produced by collecting all of the reacted liquid streams (or sour water) from the various deacidification columns, pumping the cumulative sour water to pressures in excess of 315 psia, and stripping the acid gas from the cumulative sour water. The acid gas stream will leave the acid gas stripping column 360 as stream 364, or the selective stripping column 320 (not shown) as either stream 324 or 325. The acid gas stream 364 will contain very little ammonia and the streams 324 or 325 will also contain very little ammonia, as long as the selective stripping process is reusing all the ammonia input.

This 95% to 99+% purity acid gas can be fed directly to a high pressure sulfur recovery unit 651. Liquid sulfur will be drawn from the high pressure sulfur recovery unit as a sulfur stream 663 and the dissolved gases such as H2S, CO2 and H2O can be recovered as a gas stream 814. This gas stream 814 can be deacidified with a deacidification column to produce a gas stream 824 containing less than 10 ppm by volume of H2S that can be incinerated in incinerator 690.

Residual sulfur dioxide in the high pressure gas stream 665, remaining after the condensation of liquid sulfur, is hydrogenated in the hydrogenerator 375 and exits as gas stream 666. The trace amount of unrecovered H2S contained in stream 666 can then be removed in the deacidification column 100. The deacidified gas 605, having from about 1 ppm by volume to 10 ppm by volume of H2S is sent to the incinerator 690. The reacted liquid stream (the sour water stream), containing essentially all of the unrecovered hydrogen sulfide, is then recycled back to the central acid gas stripping column 360. The hydrogen sulfide is stripped from the sour water stream and enters the high pressure sulfur recovery unit where it experiences a second 99+% conversion to liquid sulfur. The ability to absorb ultra-low H2S levels and recycle the reclaimed hydrogen sulfide back to the high pressure sulfur recovery unit to experience a second 99% conversion of the hydrogen sulfide which failed to convert in the first pass through the sulfur recovery unit makes it possible to achieve 99.9+% sulfur conversion overall. Similar consequences can be achieved by recycling the unreacted compounds of other weak acids.

Carbon dioxide is known to be 17-85 times less reactive with ammonia than is

hydrogen sulfide. Ammonia's selectivity for hydrogen sulfide can be used to allow the carbon dioxide contained in the original acid gases to pass out the top of the deacidification column by limiting the gas and liquid contact time to 1-5 seconds in the deacidification columns.

The application of the deacidification columns described herein that use ammoniacal solvents to remove acid gases from sour gas streams can achieve H25 levels that are better than BACT. Furthermore, when these deacidification columns are coupled with an acid gas stripping column 360 to prepare a high purity, high pressure source of hydrogen sulfide that is fed into a conventional sulfur recovery unit or a high pressure sulfur recovery unit the total sulfur recovery exceeds the current BACT. Similar benefits may be realized in any industry where acids gases need to be removed, even though there may not be high pressure conversion technologies available for every possible weak acid gas.

While preferred embodiments of the invention have been shown and described, it will be apparent to those skilled in the art that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purpose as the present invention. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims.