Abstract:
A method for mitigation of H 2 S during a steam injection hydrocarbon producing process includes the steps of injecting steam and an additive comprising soluble molasses condensate (SMC) and amines of natural origin into a steam injection well; and producing hydrocarbons from a hydrocarbon producing well in subterranean fluid communication with the steam injection well, wherein the additive reduces H 2 S content in the hydrocarbon produced from the hydrocarbon producing well.

Description:
CROSS-REFERENCE TO RELATED APPLICATION 
     This application is a continuation-in-part of co-pending U.S. patent application Ser. No. 13/269,394, filed Oct. 7, 2011, which is a divisional application of U.S. patent application Ser. No. 12/347,724 which was filed on Dec. 31, 2008, now U.S. Pat. No. 8,110,094. 
    
    
     BACKGROUND OF INVENTION 
     This disclosure relates to mitigation of hydrogen sulfide or acid gas which can frequently be formed during steam injection hydrocarbon producing processes. 
     During the production of hydrocarbons from subterranean formations, steam injection wells are frequently used in order to drive fluids toward a hydrocarbon producing well. In this way, steam injection increases production and therefore serves an important purpose. 
     However, while increasing production, the added steam combined with temperature and formation conditions leads to formation of unacceptable amounts of H 2 S. 
     Since this H 2 S is both highly toxic and corrosive to equipment, the need exists for a suitable method for removing or otherwise preventing formation of the H 2 S. 
     It is the goal of the present disclosure to provide such a method. 
     SUMMARY OF INVENTION 
     The present disclosure details a method for mitigation of hydrogen sulfide or acid gas which can typically be formed during steam injection processes. The mitigation is accomplished by including an additive during the steam injection, wherein the additive comprises amines of natural origin, and these amines provide an excellent reduction of the levels of H 2 S formed. Sources of the natural amines include waste streams from fish processing and also residue from sugar processing in the form of soluble molasses condensate (SMC). A combination of these two substances has been found to produce an excellent reduction in formation of H 2 S, and also an improvement in the API gravity of hydrocarbons produced. 
     In accordance with the invention, a method for mitigation of H 2 S during a steam injection hydrocarbon producing process is provided, comprising the steps of injecting steam and an additive comprising soluble molasses condensate (SMC) and amines of natural origin into a steam injection well; and producing hydrocarbons from a hydrocarbon producing well in subterranean fluid communication with the steam injection well, wherein the additive reduces H 2 S content in the hydrocarbons produced from the hydrocarbon producing well. 
     In accordance with a preferred embodiment of the present invention, the additive preferably comprises soluble molasses condensate and fish processing residue, and the fish processing residue preferably contains histamine and amines such as methyldiethanolamine (MDEA), monoethanolamine (MEA) and diethanolamine (DEA), and these substances mixed with soluble molasses condensate (SMC) have been found to be particularly effective at mitigating H 2 S in accordance with the invention. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       A detailed description of preferred embodiments of the present disclosure follows, with reference to the attached drawings, wherein: 
         FIG. 1  is a schematic illustration of a steam injection process; 
         FIG. 2  is a schematic illustration of a typical process from which SMC can be obtained; 
         FIG. 3  is a schematic illustration of a typical process from which fish processing residues can be obtained; 
         FIG. 4  illustrates results of a steam injection process using an additive in accordance with the present invention compared to a control or blank (CAV) with respect to generation of H 2 S; and 
         FIG. 5  illustrates results of a steam injection process using an additive in accordance with the present invention compared to a control or blank (CAV) with respect to API gravity of produced oil. 
     
    
    
     DETAILED DESCRIPTION 
     The disclosure relates to steam injection oil producing processes, and more particularly to an additive and method for mitigating formation of H 2 S during such steam injection processes. 
       FIG. 1  illustrates a typical steam injection process, and shows a producing well  10  drilled from a surface level  12  to a producing zone  14 . A pump  16  is also shown and is typically used for enhancing the volume or flow rate of fluids produced from well  10 . 
     In order to further increase production from well  10 , a steam injection well  18  is also drilled from surface  12  to a zone  20  which is in fluid communication with hydrocarbon zone  14 . Steam generator  22  is used to generate steam to be injected into well  18 , resulting in steam and condensed water in zone  20 , which migrates as hot water  24  toward zone  14  and the crude oil in that zone. The increased temperature as well as fluid dynamic pressure from steam injection well  18  serves to help produce crude oil through well  10  as desired. Fluids produced from well  10  are passed to crude storage tanks  26  and a gas treatment unit  28 , also as shown. 
     As set forth above, steam injection results in a reaction between organic sulfur compounds in the crude oil, sand present in the oil field itself, and steam at temperatures typically between 200 and 300° C. This reaction involves the breaking of chemical bonds by thermal effect of the steam and this reaction can be catalyzed by the minerals in the porous medium. The overall global mechanism is as follows: RCH 2 CH 2 SCH+2H 2 O→RCH 3 +CO 2 +H 2 +H 2 S+CH 4    
     The CO 2 , H 2  and CH 4  are all useful products, but H 2 S is highly toxic and corrosive. This undesirable byproduct of the steam injection process causes numerous issues and mitigation of this H 2 S is the goal of the present invention. 
     In accordance with the invention, it has been found that additives based on naturally occurring waste material, such as for example sugar cane and fish processing waste materials, can be added to the steam injection process and result in a reduction in H 2 S formed during the steam injection. 
     These additives, which are discussed further below, can be injected into the steam injection well  18 , preferably before the steam injection. Further, when large amounts of H 2 S are produced, it may be desirable to inject additive according to the invention into production well  10  preferably after the steam injection. 
     In accordance with the present invention, the additive can be soluble molasses condensate (SMC), fish processing residues containing amines, and preferably combinations thereof. One preferred embodiment contains both SMC and amines from fish processing residue, as this combination produces excellent results as will be demonstrated below. 
     A number of different amines have been identified as useful for removing H 2 S. These substances include monoethynolamine (MEA), diethanolamine (DEA) and methyldiethanolamine (MDEA). Boiling point and critical point of these amines are particularly well suited at removing H 2 S at well and formation conditions and forming benign products instead. 
     In accordance with the present invention, the effectiveness of amines in H 2 S mitigation is combined with finding a particularly good use for waste products from other industries as a source of the amines and other useful components to prevent the generation of hydrogen sulfide in the petroleum industry. SMC obtained from sugar refineries, and fish processing residue obtained from the fish processing industry, can act as sources of additive according to the invention, with SMC combining with amines of natural origin for use in accordance with the present invention, with surprisingly beneficial results. 
       FIG. 2  schematically illustrates a process from which SMC can be obtained. This illustration is an example only, and SMC obtained from any source or by other methods would be suitable within the broad scope of the present invention. 
     Turning to  FIG. 2 , the process typically begins with a mixture of syrups  30  sent to a fermentation step  32 , followed by separation of yeasts  34 , and distillation  36  to produce ethanol  38  and a concentration of vinasse  40  which can then be used to obtain SMC  42  for use in accordance with the present invention. 
       FIG. 3  illustrates a typical fish processing method, and shows a beginning step as selection of fish  44 , a washing step  46 , a cooking step  48 , a filling step  50  and, finally, vacuum sealing and sterilization  52  to provide the final fish product  54 . As shown, the washing step  46  and cooking step  48  generate streams of residue  56  which contain useful amines. These amines are shown below to produce excellent results in mitigation of H 2 S in steam injection processes when used in accordance with the present invention. 
     With respect to SMC, compounds found and identified in the SMC are believed to contribute to the beneficial results obtained in accordance with the present invention. These compounds include carboxylic acids, lactones, alcohols, aldehydes, phenols and the like. It should be noted that the use of SMC is also disclosed in a related application by the present applicant, namely, U.S. patent application Ser. No. 12/347,724, filed Dec. 31, 2008, and that application is incorporated herein by reference. 
     With respect to the fish processing residue, histamine is a natural amine found in the tissues of fish such as tuna and mackerel and in residue from treatment of such fish. In such fish, histamine is indicative of decomposition. Histamine structure comprises various amines, typically a primary and two additional amines from the imidazolidinyl formed from decomposition, and the histamines are typically formed from a combination of histidine and bacteria. Histamines can be found in large quantity in the residue of fish processing, for example as obtained in  FIG. 3  described above. 
     Regarding the invention, the additive can usefully be SMC, fish processing residue, and most preferably both, and can advantageously be used in a steam injection process as shown in  FIG. 1  by injecting into steam injection well  18  before steam injection, and optionally into production well  10  after steam injection. 
     The additive preferably contains amounts of SMC and FPR sufficient to provide at least about 20% vol/vol amines and at least about 5% vol/vol of SMC. Further, the additive may contain a ratio of amines to SMC, by volume, of between about 1:4 and about 10:1, and preferably has a ratio of about 9:1. 
     In accordance with the present invention, in order to simulate steam injection with mitigation of H 2 S according to the invention, steam injection was conducted on an oil well located at Anzoátegui, VE. This oilfield has properties as shown below in Table 1. 
     
       
         
               
             
               
               
               
             
               
               
               
             
           
               
                 TABLE 1 
               
             
             
               
                   
               
               
                 PROPERTIES IN THE OILFIELD 
               
             
          
           
               
                   
                 Property 
                 Value 
               
               
                   
                   
               
             
          
           
               
                   
                 Porosity, Ø, vol % 
                 27 
               
               
                   
                 Saturation of crude oil, S o  vol % 
                 73 
               
               
                   
                 Gas/oil ratio, GOR, ft 3  N gas/bbl N crude oil 
                 79 
               
               
                   
                 Concentration of H 2 S in the production zone, ppmv 
                 7000 
               
               
                   
                 Concentration of CO 2  in the production zone, % v/v 
                 21 
               
               
                   
                   
               
             
          
         
       
     
     Steam injections were conducted at conditions as shown below in Table 2. 
     
       
         
               
             
               
               
               
             
               
               
               
             
           
               
                 TABLE 2 
               
             
             
               
                   
               
               
                 STEAM INJECTION CONDITIONS 
               
             
          
           
               
                   
                 Property 
                 Value 
               
               
                   
                   
               
             
          
           
               
                   
                 Steam injection temperature (C. °) 
                 247 
               
               
                   
                 Saturation pressure at the injection T, MPa 
                 3.79 
               
               
                   
                   
               
             
          
         
       
     
     Under these conditions, and in this well, a number of additives were determined to be evaluated, as detailed below in Table 3. 
     
       
         
               
             
               
               
               
             
           
               
                 TABLE 3 
               
             
             
               
                   
               
               
                 ADDITIVES EVALUATED 
               
             
          
           
               
                   
                 Property 
                 Description 
               
               
                   
                   
               
               
                   
                 MDEA/SMC 
                 Deionized Water: 47.5% v/v 
               
               
                   
                   
                 MDEA: 47.5% v/v 
               
               
                   
                   
                 SMC: 5% v/v 
               
               
                   
                 SMC/DEA 
                 SMC: 80% v/v 
               
               
                   
                   
                 DEA: 20% v/v 
               
               
                   
                 Commercial Mixture (CM) 
                 Liquid H 2 S Sequestering Agent 
               
               
                   
                   
                 Amine-based 
               
               
                   
                   
                 Film-forming 
               
               
                   
                 Fish Processing Residues 
                 Aqueous effluent obtained 
               
               
                   
                 (FPR) 
                 from the fishing industry 
               
               
                   
                 Histamine (HM) 
                 Histamine from conventional 
               
               
                   
                   
                 synthesis, 5,000 ppm in 
               
               
                   
                   
                 deionized water 
               
               
                   
                   
               
             
          
         
       
     
     As shown, the additives to be evaluated included combinations of MDEA/SMC and SMC/DEA in accordance with the invention, as well as a Commercial Mixture (CM), Fish Processing Residues (FPR) by itself, and a synthesized histamine (HM). 
     The injection water has properties set forth below in Table 4. 
     
       
         
               
             
               
               
               
             
           
               
                 TABLE 4 
               
             
             
               
                   
               
               
                 INJECTION WATER 
               
             
          
           
               
                   
                 Property 
                 Value 
               
               
                   
                   
               
               
                   
                 pH (25° C.) 
                 10.68 ± 0.06 
               
               
                   
                 Sodium, mg/l 
                 397.00 
               
               
                   
                 Carbonate, mg/l 
                 468.00 
               
               
                   
                 Chloride, mg/l 
                 575.00 
               
               
                   
                 Sulfate, mg/l 
                 36.00 
               
               
                   
                 Nitrate, mg/l 
                 20.40 
               
               
                   
                 Potassium, mg/l 
                 100.00 
               
               
                   
                   
               
             
          
         
       
     
     Properties in the oilfield are shown below in Table 5. 
     
       
         
               
             
               
               
               
             
           
               
                 TABLE 5 
               
             
             
               
                   
               
               
                 OIL IN THE OILFIELD 
               
             
          
           
               
                   
                 Property 
                 Value 
               
               
                   
                   
               
               
                   
                 API Gravity (15.56° C.) °API 
                  8.88 ± 0.06 
               
               
                   
                 Viscosity (50° C.), Pa · s 
                 28.0 ± 0.6 
               
               
                   
                 H/C ratio 
                  0.132 ± 0.033 
               
               
                   
                 Saturates, % w/w 
                  9.5 ± 0.5 
               
               
                   
                 Aromatics, % w/w 
                 36.5 ± 2     
               
               
                   
                 Resins, % w/w 
                 37 ± 2 
               
               
                   
                 Asphaltenes, % w/w 
                 17 ± 1 
               
               
                   
                 Sulfur, % w/w 
                  3.36 ± 0.14 
               
               
                   
                 Nickel, ppm 
                 95 ± 5 
               
               
                   
                 Vanadium, ppm 
                 378 ± 20 
               
               
                   
                   
               
             
          
         
       
     
     The sand in the oilfield has properties as shown below in Table 6. 
     
       
         
               
             
               
               
               
             
           
               
                 TABLE 6 
               
             
             
               
                   
               
               
                 SAND IN THE OILFIELD 
               
             
          
           
               
                   
                 Property 
                 Value 
               
               
                   
                   
               
               
                   
                 Carbon, % w/w 
                 1.19 ± 0.02 
               
               
                   
                 Sulfur, % w/w 
                 0.44 ± 0.01 
               
               
                   
                 Quartz, % w/w 
                 95 ± 2  
               
               
                   
                 Potassium Feldespar, % w/w 
                 2.00 ± 0.04 
               
               
                   
                 Calcite, % w/w 
                 1.00 ± 0.02 
               
               
                   
                 Dolomite, % w/w 
                 2.00 ± 0.04 
               
               
                   
                 Clays, % w/w 
                 Trace 
               
               
                   
                   
               
             
          
         
       
     
     The SMC used in this evaluation had properties as shown below in Table 7. 
     
       
         
               
             
               
               
               
             
           
               
                 TABLE 7 
               
             
             
               
                   
               
               
                 SOLUBLE MOLASSES CONDENSATE (SMC) 
               
             
          
           
               
                   
                 Property 
                 Value 
               
               
                   
                   
               
               
                   
                 pH (25° C.) 
                 4.42 ± 0.05 
               
               
                   
                 Brix 
                 70 ± 1  
               
               
                   
                 Density (25° C.), g/cm 3   
                 1.2411 ± 0.0005 
               
               
                   
                 Solids in suspension, % w/w 
                 54.64 ± 0.05  
               
               
                   
                 C, % w/w 
                 20 ± 1  
               
               
                   
                 H, % w/w 
                 8 ± 2 
               
               
                   
                 S, % w/w 
                 0.135 ± 0.01  
               
               
                   
                 N, % w/w 
                 1.50 ± 0.05 
               
               
                   
                   
               
             
          
         
       
     
     The pH density content for each of the additives considered is shown below in Table 8. 
     
       
         
               
             
               
               
               
               
             
           
               
                 TABLE 8 
               
             
             
               
                   
               
               
                 STEAM INJECTION ADDITIVES 
               
             
          
           
               
                   
                   
                 Density, 25° C. 
                 Active amine 
               
               
                 Additive 
                 pH, 25° C. 
                 (g/cm 3 ) 
                 (% w/w) 
               
               
                   
               
               
                 MDEA/SMC 
                 10.54 ± 0.05  
                 1.051 ± 0.005 
                 47.5 ± 0.5 
               
               
                 SMC/DEA 
                 9.89 ± 0.05 
                 1.078 ± 0.005 
                 20.0 ± 0.5 
               
               
                 CM 
                 12.10 ± 0.05  
                 1.013 ± 0.005 
                 35.0 ± 0.5 
               
               
                 FPR 
                 6.82 ± 0.05 
                 0.988 ± 0.005 
                  3.6 ± 0.2 
               
               
                 HM 
                 10.7 ± 0.05 
                 1.081 ± 0.005 
                  1.0 ± 0.2 
               
               
                   
               
             
          
         
       
     
     The composition of the effluent gas from the production process carried out with each of the additives being considered is shown below in Table 9. 
     
       
         
               
             
               
               
             
               
               
               
               
               
               
               
               
             
               
               
               
               
               
               
               
               
             
               
               
               
               
               
               
               
             
           
               
                 TABLE 9 
               
             
             
               
                   
               
               
                 COMPOSITION OF THE EFFLUENT GAS 
               
             
          
           
               
                 Compound 
                   
               
             
          
           
               
                 M 
                 Gas 
                   
                   
                   
                   
                   
                   
               
               
                 (g/mol) 
                 (% mol) 
                 CAV 
                 +MDEA/SMC 
                 +SMC/DEA 
                 +CM 
                 +FPR 
                 +HM 
               
               
                   
               
             
          
           
               
                 2 
                 H 2   
                 0.8960 
                 1.0510 
                 0.2595 
                 0.0000 
                 0.2225 
                 0.2798 
               
               
                 16 
                 CH 4   
                 54.8500 
                 43.6660 
                 78.9445 
                 83.2060 
                 69.5465 
                 71.0848 
               
               
                 28 
                 N 2   
                 19.1240 
                 43.0360 
                 13.8020 
                 11.9540 
                 20.1630 
                 18.167 
               
               
                 32 
                 O 2   
                 3.6210 
                 5.1220 
                 1.0525 
                 2.0520 
                 3.7220 
                 4.2220 
               
               
                 34 
                 H 2 S 
                 0.5148 
                 0.0514 
                 0.0514 
                 0.2574 
                 0.3089 
                 0.1214 
               
               
                 44 
                 CO 2   
                 21.4360 
                 6.2770 
                 5.8670 
                 2.5860 
                 6.3125 
                 6.125 
               
             
          
           
               
                   M  (g/mol) 
                 24.74 
                 23.46 
                 19.42 
                 18.45 
                 20.75 
                 20.55 
               
               
                   
               
             
          
         
       
     
     In Table 9, CAV was a blank test or control against which the additives of Table 8 can be compared. The blank test used water, oil, gas and sand under steam injection conditions. 
     In addition to reduction of H 2 S in the effluent gas which is further discussed below, Table 9 shows other benefits of the present invention as well. Table 9 shows higher resulting concentrations of H 2 S and CO 2  than the other additives. The presence of additional H 2  from the water gas shift reaction can hydrogenate unsaturated centers present in the heavy fractions of crude oil. 
     Higher levels of CO 2  can also be beneficial when miscible with the oil as this reduces viscosity of the oil which increases flow and production rates. 
     Effectiveness of the additive was also measured in terms of both hydrogen sulfide in the gas effluent and API gravity of the resulting produced crude.  FIGS. 4 and 5  show these results. 
       FIG. 4  shows that the control generated a concentration of H 2 S of approximately 5,000 ppmv, while the additives in accordance with the present invention reduced this amount by approximately 90%, to a level below 1,000 ppmv. This compared extremely favorably with the commercial additive (CM) which showed only a 50% reduction, and to the fish processing residue (FPR) by itself, which showed a 40% reduction. Reduction was 82% for synthesized histamine (HM). 
       FIG. 5  also shows that the additive according to the most preferred embodiment of the invention (MDEA/SMC) shows an increase approximately in the API gravity of the oil produced, and this increase was greater than any change obtained using any other additives including the fish processing residue (FPR) by itself and synthesized histamine (HM). 
     While  FIGS. 4 and 5  show beneficial results with MDEA/SMC, SMC/DEA and even HM, it is also clear that the best combination of results is obtained with MDEA/SMC in accordance with the invention. 
     It is to be understood that the present specification is not limited to the illustrations described and shown herein, which are deemed to be merely illustrative of the best modes of carrying out the present specification and which are susceptible of modification of form, size, arrangement of parts and details of operation. The present specification, i.e. the invention, rather is intended to encompass all such modifications which are within its spirit and scope as defined by the claims.