Abstract:
The method deacidifies a gas including H 2 S and CO 2 . The gas is subjected to an absorption to collect the CO 2  and the H 2 S in an absorber, then to conversion through hydrolysis of the COS to H 2 S and CO 2  in a reactor, and to a second absorption to collect the H 2 S and the CO 2  formed in the reactor. The absorbent solution is regenerated in regenerator. The regenerated absorbent solution is separated into two which are:
       a main stream supplying the absorber, and   a remaining stream supplying the second absorption

Description:
BACKGROUND OF THE INVENTION 
       [0001]    1. Field of the Invention 
         [0002]    The present invention relates to deacidification methods of using an absorbent solution. 
         [0003]    Absorption methods using an aqueous amine solution are commonly used to remove carbon dioxide (CO 2 ) and hydrogen sulfide (H 2 S) from a gas. The gas is purified by contact with the absorbent solution and then the absorbent solution is thermally regenerated. 
         [0004]    Carbonyl sulfide (COS) can be present in a natural gas, as well as in a synthesis gas. Conventional chemical solvents do not allow the COS to be efficiently removed. In any case, conventional chemical solvents do not allow the H 2 S and the COS to be selectively removed in relation to CO 2 . 
         [0005]    In the case of natural gas treatment, a significant presence of COS in the feed gas is often problematic and a stringent total sulfur specification in the treated gas is constrained by the COS content in the feed gas. 
         [0006]    In the case of a synthesis gas, and according to the downstream applications of the gas, COS is often considered to be a pollutant and the treated gas must have very low COS contents, down to less than 1 ppm. 
         [0007]    2. Description of the Prior Art 
         [0008]    WO-96/19,281 describes treatment of an acidic natural gas by carrying out catalytic hydrolysis of COS between two absorption stages. The catalytic hydrolysis reactor is arranged outside the absorption column. The gas phase hydrolysis reaction is as follows: 
         [0000]      COS+H 2 O         H 2 S+CO 2    
         [0009]    The reaction is thus promoted for low H 2 S and CO 2  partial pressures. WO-96/19,281 thus describes reduction of the H 2 S partial pressure before COS hydrolysis by carrying out an absorption stage in the lower section of the absorption column. Then the acid gases are removed at the hydrolysis reactor outlet through absorption in the upper section of the absorption column. 
       SUMMARY OF THE INVENTION 
       [0010]    The present invention improves the method described in WO-96/19,281 by optimizing the distribution of the absorbent solution streams in the absorption section. 
         [0011]    In general terms, the present invention provides a method of deacidifying a gas comprising H 2 S and COS, by the following stages: 
         [0012]    (a) contacting the gas with a first absorbent solution stream in a first absorption section to obtain an H 2 S-depleted gaseous effluent and an H 2 S-laden absorbent solution; 
         [0013]    (b) feeding the H 2 S-depleted gaseous effluent into a reactor that performs a reaction of hydrolysis of the COS into H 2 S and CO 2  to obtain a COS-depleted gaseous effluent; 
         [0014]    (c) contacting the COS-depleted gaseous effluent with a second absorbent solution stream in a second absorption section to obtain a treated gas and an absorbent solution partly laden with H 2 S; and 
         [0015]    (d) regenerating the H 2 S-laden absorbent solution to obtain a regenerated absorbent solution stream. 
         [0016]    According to the invention, in stage (a), the first absorbent solution stream comprises a first portion of the regenerated absorbent solution obtained in stage (d), as well as the absorbent solution partly laden with H 2 S, and in stage (c) the second absorbent solution stream comprises a second portion of the regenerated absorbent solution stream obtained in stage (d). 
         [0017]    According to the invention, the first portion can comprise at least 70 vol. % of the regenerated absorbent solution stream obtained in stage (d) and the second portion can comprise less than 30 vol. % of the regenerated absorbent solution stream obtained in stage (d). 
         [0018]    The pressure in the first absorption section can be at least 2 bars above the pressure in the second absorption section and, in this case, the pressure can be raised by pumping the absorbent solution partly laden with H 2 S prior to feeding it into the first absorption section. 
         [0019]    The reactor can, for example, comprise a COS hydrolysis reaction catalyst, a titanium oxide or an alumina oxide. 
         [0020]    The regenerated absorbent solution stream can comprise at least one amine in aqueous phase. 
         [0021]    In stage (d), the H 2 S-laden absorbent solution can be subjected to at least one distillation. In stage (d), the H 2 S-laden absorbent solution can also be subjected to expansion. 
         [0022]    The gas can be selected from among a natural gas, and a synthesis gas, a combustion fume. 
         [0023]    Applying a limited absorbent solution flow rate in stage (c) allows significant reduction of the diameter of the second absorption section while keeping the COS specifications. This involves a significant decrease in the cost of the absorber and a decrease in the operating cost of the method. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWING 
         [0024]    Other features and advantages of the invention will be clear from reading the description hereafter, with reference to  FIG. 1  that diagrammatically shows an embodiment example of the method according to the invention. 
       
    
    
     DETAILED DESCRIPTION 
       [0025]    With reference to  FIG. 1 , the gas to be treated flows in through line  1  at a pressure that can range between 1 and 150 bars, and at a temperature that can range between 10° C. and 70° C. The gas can be, for example, a natural gas, a synthesis gas, a gas produced by coal gasification, or fumes from a combustion process. The gas comprises acidic compounds to be removed, which notably are H 2 S and COS, and possibly CO 2 . In the case of natural gas, the gas circulating in line  1  can be at a pressure ranging between 20 and 100 bars. 
         [0026]    The gas to be treated flowing in through line  1  is contacted in absorption section C 1   a  with an absorbent solution flowing in through line  19 . Section C 1   a  is an enclosure provided with gas-liquid contacting elements, for example trays, a random packing or a stacked packing. 
         [0027]    The composition of the absorbent solution is selected for its capacity to absorb the acidic compounds. 
         [0028]    An absorbent solution comprising a chemical solvent can be used, for example a solution comprising in general between 10 wt. % and 80 wt. %, preferably between 20 wt. % and 60 wt. % amines, preferably alkanolamines, and comprising at least 20 wt. % water, the sum of the compounds being 100%. The following amines can be used: MEA (monoethanolamine), DEA (diethanolamine), MDEA (methyldiethanolamine), DIPA (diisopropylamine), DGA (diglycolamine), diamines, piperazine, hydroxyethyl piperazine. An amine type or a mixture of several amines can be used, for example a mixture of one or more tertiary amines with one or more primary or secondary amines. 
         [0029]    Alternatively, an absorbent solution comprising a physical solvent can be used, for example methanol, N-formyl morpholine, glycol ethers, sulfolane, thiodiethanol. The physical solvent can be mixed with an aforementioned chemical solvent and/or with water. 
         [0030]    If it is desired to selectively absorb the H 2 S in relation to CO 2 , an absorbent solution comprising a solvent with thermodynamic and kinetic properties that confer a selective character on the absorbent solution can be used. It is possible to use an amine whose intrinsic characteristics are a rate of reaction with H 2 S that is at least twice, or even three times as high as its rate of reaction with CO 2 . For example, the absorbent solution comprises a tertiary amine, MDEA for example, or an amine comprising a sterically hindered amine function, DIPA for example. The selective absorbent solution can comprise between 10 wt. % and 80 wt. %, preferably between 20 wt. % and 60 wt. % amines, and at least 20 wt. % water with the sum of the compounds being 100%. It is also possible, for example, to use a selective physical solvent in aqueous solution, such as dimethyl ether polyethylene glycol or N-methylpyrrolidone. 
         [0031]    In the case of natural gas treatment, section C 1   a  can operate at a temperature ranging between 20° C. and 100° C., and at a pressure ranging between 20 bars and 100 bars. In section C 1   a , the solution flowing in through line  19  absorbs the acidic compounds contained in the gas which are notably H 2 S and CO 2 . However, considering the low affinity of amines for COS, the COS remains predominantly present in the gas. The H 2 S-depleted gas is discharged from section C 1   a  through line  9 . The gas discharged through line  9  is water-saturated because the absorbent solution contains water. The absorbent solution laden with acidic compounds is discharged in the bottom of C 1   a  through line  4  and sent to one or more regeneration stages. 
         [0032]    The gas circulating in line  9  is heated in heat exchangers E 3  and E 4 . Exchangers E 3  and E 4  allow recovery of the heat contained in the hot gas from reactor R 1  in order to thermally best optimize the method according to the invention. The heated gas coming from E 4  through line  11  can be sent, in some cases, to an additional heat exchanger E 5  allowing reaching temperature levels required for the hydrolysis stage carried out in R 1 . 
         [0033]    The hot gas leaving E 5  through line  12  is fed into catalytic reactor R 1 . For example, R 1  is a fixed bed reactor whose catalyst can be a titanium oxide, an alumina oxide or a zirconium oxide. The catalyst comes in solid form, such as, for example, extrudates. Preferably, a catalyst CRS 31  is used which is marketed by the Axens Company. Under the effect of the catalyst, the COS contained in the water-saturated gas is converted to H 2 S and CO 2  according to the hydrolysis reaction as follows: COS+H 2 O         H 2 S+CO 2 . In general, reactor R 1  can operate at a pressure ranging between 20 and 100 bars, and at a temperature at least above 100° C. 
         [0034]    The gas discharged from reactor R 1  through line  13  is significantly depleted in COS, and contains CO 2  and H 2 S produced by hydrolysis of the COS. The gas is cooled in exchangers E 4 , then E 3 , by heat exchange with the gas coming from C 1   a  through line  9 . The gas leaving E 4  through line  15  can be cooled in an additional heat exchanger E 6  so as to reach the thermal level required in the absorption section. 
         [0035]    The cooled gas leaving E 6  through line  16  is fed into absorption section C 1   b  in order to be contacted with the absorbent solution flowing in through line  2   b . Section C 1   a  is an enclosure provided with gas-liquid contacting elements, for example trays, a random packing or a stacked packing. In section C 1   b , solution  2   b  absorbs the acidic compounds contained in the gas, notably the H 2 S and the CO 2  produced by hydrolysis of the COS in reactor R 1 . The treated gas is discharged from section C 1   b  through line  3 . The absorbent solution laden with acidic compounds is discharged in the bottom of C 1   b  through line  17  and then is fed into the top of absorption section C 1   a  via pump P 1  and lines  18  and  19 . 
         [0036]    Sections C 1   a  and C 1   b  are distinct from one another. C 1   a  and C 1   b  can be arranged in two different columns. Alternatively, sections C 1   a  and C 1   b  can be arranged in a single column C 1  as shown in  FIG. 1 . A sealed tray  10  separates section C 1   a  from section C 1   b.    
         [0037]    The absorbent solution discharged in the bottom of section C 1   a  through line  4  is subjected to one or more regeneration stages. According to  FIG. 1 , the absorbent solution is expanded and then is fed into a flash drum F 1  at a pressure ranging for example between 5 and 15 bars. The vapor fraction released through expansion is discharged at the top of drum F 1  through line  5 . The liquid discharged in the bottom of F 1  is heated in exchanger E 1  by heat exchange with the regenerated absorbent solution flowing in through line  8 . The hot absorbent solution leaving E 1  through line  7  is fed into thermal regeneration column C 2  equipped, for example, with gas-liquid separation internals, trays, random packings or stacked packings. A portion of the absorbent solution is withdrawn at the bottom of C 2 , heated by reboiler Rb 1 , for example to a temperature ranging between 80° C. and 150° C. and then is fed again into the bottom of C 2 . The acidic compounds, notably H 2 S and CO 2 , are released in gas form at the top of C 2 . The regenerated absorbent solution is discharged in the bottom of C 2  through line  8  cooled in heat exchangers E 1  and then E 2  so as to reach a temperature preferably ranging between 25° C. and 50° C. 
         [0038]    According to the invention, at the outlet of exchanger E 2 , the stream circulating in line  2  is pumped by pump P 2 , then divided into two portions which are a main portion circulating in  2   a  and the remaining portion circulating in  2   b . The main portion circulating in  2   a  comprises at least 70% and preferably at least 80% or even 90% of the volume flow rate of the stream circulating in line  2 . This main portion is mixed with the absorbent solution stream coming from the bottom of section C 1   b  through line  18 . The mixture that is obtained is injected through line  19  to the top of section C 1   a , such as, for example, at a level located in the upper half of section C 1   a . The remaining portion of regenerated absorbent solution  2  is fed to the top of section C 1   b  through line  2   b . The portion circulating in line  2   b  comprises less than 30% and preferably less than 20% or even less than 10% of the volume flow rate of the stream circulating in line  2 . 
         [0039]    The main portion of the regenerated absorbent solution  2   a  (for example, 80% to 90% of the total flow rate of solution  8 ) allows collection of a large part of the acidic compounds in C 1   a . Thus, the acidic compound partial pressure in the gas is decreased which promotes hydrolysis of the COS in R 1 . A limited stream (for example of 10% to 20% of the remaining flow rate of solution  8 ) is sent to the top of absorption section C 1   b . This limited stream is sufficient to absorb the small amount of acidic compounds formed upon COS hydrolysis in R 1 . Furthermore, sending an absorbent solution flow rate to C 1   b  that is lower than the absorbent solution flow rate sent to C 1   a , allows reduction of the dimension of section C 1   b  in relation to the dimension of section C 1   a . For example, the diameter of section C 1   b  can be reduced. The method according to the invention allows implementation of a section C 1   b  whose diameter can be at least 30%, preferably at least 50% less than the diameter of section C 1   a . Moreover, since section C 1   b  operates at a pressure slightly lower than the pressure in section C 1   a  (approximately 2 to 5 bars less), it is necessary to compress the absorbent solution  17  obtained in the bottom of section C 1   b  with P 1  to the operating pressure of section C 1   a  prior to recycling it to C 1   a . Having a limited absorbent solution flow rate circulating in C 1   a  allows reduction of the cost of the compression operation in P 1 . Moreover, a relatively low absorbent solution flow rate is sent to section C 1   b  in order to absorb a sufficient amount of H 2 S while limiting CO 2  absorption. 
         [0040]    The method operation example according to  FIG. 1 , presented hereafter, highlights the advantages of the method according to the invention. 
         [0041]    The method according to  FIG. 1  is implemented in order to remove the COS contained in a natural gas to reach a specification on the treated gas of 1 ppmv COS. The method illustrated in  FIG. 1  can reduce the total sulfur content of a gaseous feed stream  1 . Table 1 gives the compositions and the operating conditions of the incoming/outgoing streams of the COS hydrolysis reactor, obtained from a numerical modelling specific to this reactor. 
         [0000]    
       
         
               
               
               
             
               
               
               
             
               
               
               
               
             
           
               
                   
                 TABLE 1 
               
             
             
               
                   
                   
               
               
                   
                 Stream number 
                   
               
               
                   
                 Description 
               
             
          
           
               
                   
                 12 
                 13 
               
               
                   
                 R1 inlet 
                 R1 outlet 
               
               
                   
                   
               
             
          
           
               
                   
                 Temp. (° C.) 
                 140 
                 140.05 
               
               
                   
                 Pressure (Bar) 
                 75.5 
                 74.0 
               
               
                   
                 Molar flow rate 
                 2717.7 
                 2717.7 
               
               
                   
                 (kmol/h) 
               
               
                   
                 Mass flow rate 
                 58783.8 
                 58783.8 
               
               
                   
                 (kg/h) 
               
               
                   
                 Comp. (% mol) 
               
               
                   
                 CO2 
                 2.027 
                 2.0353 
               
               
                   
                 H2S 
                 0.0002 
                 0.0083 
               
               
                   
                 COS 
                 0.0081 
                 0.0001 
               
               
                   
                 H2O 
                 0.1738 
                 0.1658 
               
               
                   
                 N2 
                 0.268 
                 0.268 
               
               
                   
                 C1 
                 89.188 
                 89.188 
               
               
                   
                 C2 
                 4.892 
                 4.892 
               
               
                   
                 C3+ 
                 3.443 
                 3.443 
               
               
                   
                   
               
             
          
         
       
     
         [0042]    Table 1 shows that the gas at the reactor outlet allows the COS specification to be reached while limiting the pressure drop. 
         [0043]    Table 2 gives all the stream compositions and operating conditions obtained by means of a numerical process simulation software specific to gas-liquid absorption columns. This example shows that a certain selectivity can be kept for the treated gas while removing the COS present in the natural gas. Furthermore, this example shows that a low flow rate of absorbent solution  2   b  in C 1   b  is sufficient to reach a severe sulfur content specification (i.e. less than 4 ppm sulfur), while limiting CO 2  absorption. 
         [0000]    
       
         
               
               
             
               
               
               
               
               
             
               
               
               
               
               
             
           
               
                   
                 TABLE 2 
               
             
             
               
                   
                   
               
               
                   
                 Stream number 
               
               
                   
                 Description 
               
             
          
           
               
                   
                   
                 2a 
                 2b 
                 3 
               
               
                   
                 1 
                 Amines 
                 Amines 
                 Treated 
               
               
                   
                 Raw gas 
                 to C1a 
                 to C1b 
                 gas 
               
               
                   
                   
               
             
          
           
               
                 Temp. (° C.) 
                 37.6 
                 47.6 
                 47 
                 48.3 
               
               
                 Pressure (Bar) 
                 76.2 
                 75.9 
                 73.8 
                 73.8 
               
               
                 Volume flow 
                 75 000 
                 320 
                 45 
                 63603 
               
               
                 rate (Sm3/h) 
               
               
                 Mass flow rate 
                 68896.4 
                 334566 
                 47048 
                 50295.3 
               
               
                 (kg/h) 
               
               
                 Comp. (% mol) 
               
               
                 CO2 
                 9.6 
                 0.0128 
                 0.0128 
                 1.6 
               
               
                 H2S 
                 6.0 
                 0.01 
                 0.01 
                 0.0003 
               
               
                 COS 
                 0.0075 
                 — 
                 — 
                 0.0001 
               
               
                 H2O 
                 0.12 
                 88.7 
                 88.7 
                 0.1965 
               
               
                 MDEA 
                   
                 11.3 
                 11.3 
               
               
                 N2 
                 0.23 
                   
                   
                 0.2692 
               
               
                 C1 
                 76.83 
                   
                   
                 89.5463 
               
               
                 C2 
                 4.235 
                   
                   
                 4.9071 
               
               
                 C3+ 
                 2.977 
                   
                   
                 3.48 
               
               
                   
               
             
          
         
       
     
         [0044]    Table 3 also shows the relevance of the method according to the invention in the instance of selective absorption of H 2 S in relation to CO 2  in natural gas. 
         [0000]    
       
         
               
               
               
             
               
               
               
             
           
               
                   
                 TABLE 3 
               
               
                   
                   
               
               
                   
                 Simulated method 
                   
               
               
                   
                 according to document 
                 Method according to the 
               
               
                   
                 WO 96/19281 
                 invention 
               
               
                   
                   
               
             
             
               
                   
               
             
          
           
               
                 Stream number 
                 3 (treated gas) 
                 3 (treated gas) 
               
               
                 Comp. (%) 
               
               
                 CO 2   
                 1.2 
                 1.6 
               
               
                 H 2 S 
                 2 
                 4 
               
               
                 COS (ppm) 
                 1 
                 1 
               
               
                   
               
             
          
         
       
     
         [0045]    Whereas the method according to WO-96/19,281 contains 1.2% CO 2  in the treated gas, the method according to the invention allows keeping 1.6% CO 2 , which is close to the 2% CO 2  content sought in natural gas to be carried in a gas pipeline. 
         [0046]    The economic considerations presented hereafter in Table 4 have been determined considering the cost of the main equipments (absorption column, regeneration column, heat exchangers, pump, reactor). 
         [0047]    Table 4 gives the dimensions of the absorption column dimensioned according to the diagram of  FIG. 2  provided in WO-96/19,281 and of column C 1  according to the invention. 
         [0000]    
       
         
               
               
               
             
               
               
               
             
           
               
                 TABLE 4 
               
               
                   
               
               
                   
                 Column 24-26 
                 Column C1 
               
               
                   
                 according to FIG. 2 of 
                 according to 
               
               
                 Criteria 
                 WO 96/19281 
                 the invention 
               
               
                   
               
             
             
               
                   
               
             
          
           
               
                 Height (m) 
                 28 
                 28 
               
               
                 Diameter (m) upper section 
                 2400 
                 2350 
               
               
                 Diameter (m) lower section 
                 2400 
                 1400 
               
               
                 cost (M          ) 
                 2.47 
                 1.9 
               
               
                 gain on cost (%) 
                   
                 23 
               
               
                   
               
             
          
         
       
     
         [0048]    The method according to the invention allows reduction of the cost of column C 1  by 23%. 
         [0049]    The method according to the invention also allows reduction of the energy consumption of pump P 1  as shown in Table 5. 
         [0000]    
       
         
               
               
               
             
               
               
               
             
           
               
                 TABLE 5 
               
               
                   
               
               
                   
                 Column according to 
                 Column C1 according to 
               
               
                 Criteria 
                 document WO 96/19281 
                 the invention 
               
               
                   
               
             
             
               
                   
               
             
          
           
               
                 Cost k           
                 41 
                 11 
               
               
                 Gain (%) 
                   
                 73 
               
               
                 Consumption (kW) 
                 32 
                 4 
               
               
                 Gain (%) 
                   
                 87.5 
               
               
                   
               
             
          
         
       
     
       CONCLUSIONS 
       [0050]    The method according to the invention allows achieving stringent specifications regarding COS content of the treated gas and to reduce the dimensions of the absorption column, which is the highest investment in the case of deacidifying natural gas. The gains obtained regarding the costs are significant. The method also allows improving the H 2 S content selectivity in relation to CO 2  in the treated gas, in cases where an absorbent solution comprising a selective amine that selectively absorbs H 2 S in relation to CO 2  is used. This advantage of the method according to the invention, is that unlike the prior art conventional methods of COS removal using a non-selective chemical or physical solvent which are ineffective to achieve stringent specifications, the invention has the capacity of selectively removing H 2 S and COS in relation to CO 2 , which cannot be obtained with conventional methods allowing COS removal.