Patent Publication Number: US-2010108315-A1

Title: Method for reducing the H2S content of an H2S-containing subterranean formation

Description:
RELATED CASES 
     This application is entitled to and hereby claims the benefit of the filing date of U.S. provisional application Ser. No. 61/198,100 entitled “Method for Reducing the H 2 S-Containing Subterranean Formation” filed Nov. 3, 2008 by David K. Stevens, Peter D. Clark and Justin J. A. Lamar. 
    
    
     FIELD OF THE INVENTION 
     This invention relates to a method for reducing the hydrogen sulfide content of a hydrogen sulfide-containing subterranean formation and of fluids produced from the subterranean formation. 
     BACKGROUND OF THE INVENTION 
     In many subterranean formations which contain crude oil, hydrocarbon gases and combinations thereof, the formation may contain substantial quantities of hydrogen sulfide (H 2 S). This gas is considered to be a serious pollutant in crude oil, light hydrocarbon liquids and hydrocarbon gas. It is also poisonous in certain concentrations. As a result, a continuing effort has been directed to the development of methods whereby the amount of H 2 S produced with hydrocarbon gases, liquids and or crude oil may be reduced. 
     In processes such as the well-known Claus process, H 2 S can be reacted with sulfur dioxide (SO 2 ) for form sulfur from SO 2  and H 2 S. The formation of sulfur occurs according to reactions as set out below. 
     The Claus process reactions can be considered to be: 
       2 H 2 S+3O 2 →2SO 2 +2H 2 O  (1) 
       SO 2 +2H 2 S→3S+2H 2 O  (2) 
     Previously, it has been proposed to dispose of liquid or gaseous SO 2  by injection into subterranean spent formations. These formations were not considered to be productive of any hydrocarbon fuels or other materials of interest. Applicants are unaware of any attempts to reduce the amount of H 2 S in such formations. 
     In the  Alberta Sulphur Research, Ltd. Quarterly Bulletin No.  121, April-June, 2002 published by Alberta Sulphur Research, Ltd., The University of Calgary, Calgary, Alberta, Canada, it was proposed that a method for disposing of sulfur or SO 2  is the injection of this material into H 2 S-containing, depleted, sour-gas reservoirs. 
     Since many reservoirs containing substantial quantities of H 2 S also contain substantial quantities of desirable hydrocarbon materials which it is desired to produce, it would be desirable if a method could be found to reduce the amount of H 2 S in such reservoirs and in the produced materials before bringing them to the surface. 
     Accordingly a considerable effort has been directed to the development of a method whereby the H 2 S content of a subterranean formation and of produced materials from such a formation, such as crude oil, light hydrocarbon liquids, hydrocarbon gases and the like, could be reduced prior to bringing these materials to the surface. 
     SUMMARY OF THE INVENTION 
     The invention comprises a method for reducing the hydrogen sulfide content of fluids produced from a hydrogen sulfide-containing subterranean formation, the method comprising: providing a supply of sulfur dioxide at an injection site for the subterranean formation; injecting the sulfur dioxide into the subterranean formation; and, recovering fluids having reduced hydrogen sulfide content from the subterranean formation. 
     The invention also comprises a method for reducing the hydrogen sulfide content of a hydrogen sulfide-containing subterranean formation, the method comprising: providing a supply of sulfur dioxide at an injection site for the subterranean formation; and, injecting the sulfur dioxide into the subterranean formation. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a schematic diagram of an embodiment of the present invention; and, 
         FIG. 2  is a graph showing the projected reduction in H 2 S in a subterranean formation during the injection of SO 2 ; 
         FIG. 3  is a schematic diagram of two wellbores positioned to penetrate a subterranean formation; 
         FIG. 4  is a top view of a typical five spot injection and production arrangement of oil wells; and, 
         FIG. 5  is a further top view of an embodiment of an oil field wherein five spot arrangements are used in combination to produce fluids from the field. 
     
    
    
     DESCRIPTION OF PREFERRED EMBODIMENTS 
     In the discussion of the Figures, numerous valves, heat exchangers, and the like required to achieve the process flows shown have not been shown in the interest of simplicity since such equipment is well known to those skilled in the art. 
     in  FIG. 1  a representative process is shown for the production of SO 2  for injection into a subterranean formation containing H 2 S. In the process shown schematically in  FIG. 1 , a production well  10  is shown extending from an earth surface  12  into a subterranean formation  13  containing H 2 S and producing gas. Sour gas is recovered through a line  14  and passed to a gas treatment facility  16  where the H 2 S is removed, along with other materials such as carbon dioxide, condensable gases and the like, as known to those skilled in the art. The sweet gas is then passed through a line  18  as a product to a pipeline or the like. The H 2 S is recovered through a line  20  and passed to a Claus sulfur recovery unit  22 . Such units, as well known to those skilled in the art, are able to convert acid gas streams containing H 2 S and other constituents, such as hydrocarbons and the like into sulfur by the reactions discussed previously. 
     In the process shown, the off gases are recovered through a line  26  as a Claus tail gas stream passed to a tail gas unit  28  and treated to enable the venting of the tail gases through a line  30  to the atmosphere. Such processes are well known to those skilled in the art. A sulfur steam  24  is recovered from Claus unit  22  and passed to sulfur combustion in a sulfur combustor  32 . The resulting SO 2  stream is passed through a line  32  to a waste heat recovery section  36  where heat is recovered, for instance as steam, which is passed via line  38  to a steam turbine  40 , which drives a generator  42  for the production of electrical power. The cooled SO 2  is then passed via line  44  to a SO 2  liquefaction section  46  where it is liquefied with the production of additional low grade steam through a line  48 , which could be used for a variety of purposes, such as salt water desalinization  50  or the like. The resulting liquefied sulfur is recovered through a line  52  and pumped by a pump  54  through a line  56  to an injection well  58 . 
     The SO 2  is desirably injected on a continuous or intermittent long-term basis. In  FIG. 2 , the reduction of the H 2 S in a formation is shown. In the formation shown, the calculations of the results are based upon the recovery of gas containing H 2 S from a ten-trillion cubic foot reservoir at a six hundred million standard cubic foot per day gas extraction rate with the recovered sulfur being injected as SO 2 . After ten years, the H 2 S in the formation has been reduced from about 36 percent initially to about 24 percent. This reduction is accomplished by simply returning the SO 2  produced by processing the H 2 S removed from the formation and returning it to the formation as SO 2  at an injection well. Desirably well  10  is periodically tested to determine when and whether an SO 2  breakthrough has occurred. The injection of SO 2  can be stopped when the products contain levels of SO 2 . 
     In  FIG. 3 , a well  200  is shown extending from an earth surface  202  through an overburden  204  into a formation  206 . Well  200  comprises a wellbore  212 , which includes a casing  208  which is cemented in place by cement  210 . The bottom of the well is shown at  214  near the bottom of formation  206 . A tubing  216  is positioned to extend from formation  206  to the surface for the production of fluids. The production of fluids from tubing  216  is shown by arrow  228 . A packer  218  is positioned between the outside of tubing  216  and the inside of casing  208  to prevent the flow of fluids upwardly between the outside of tubing  216  and the inside of casing  208 . Such techniques are well known to those skilled in the art and will not be further discussed. Perforations  220  are shown into formation  206  for the production or injection of fluids into formation  206 . In well  200 , the production of fluid is shown by arrows  224  to indicate the production of fluids into well  200 . 
     A second well  200 ′ is shown and includes the same components as well  200 , with substantially the same components being indicated by prime numbers corresponding to the numbers in well  200 . The exceptions are that the injection of sulfur dioxide is shown via an arrow  226 , down tubing  216 ′ and injection is shown by arrows  222  into formation  206  through perforations  220 ′. In the operation of the wells to inject sulfur dioxide into the formation, the sulfur dioxide may be injected at any suitable pressure alone or with a second fluid, which could be a material such as nitrogen, carbon dioxide, water or the like to react with hydrogen sulfide in formation  206  to reduce the concentration of the hydrogen sulfide in formation  206  and in the fluids produced through well  200 . Clearly the wells are not shown at a spacing to scale, 
     In the practice of the present invention to inject sulfur dioxide into a subterranean formation to reduce the hydrogen sulfide content of the formation, a pattern such as shown in  FIG. 4 , which is commonly referred to as a five spot pattern, may be used. Wells  230 ,  232 ,  234 , and  236  are production wells with the injection of a production enhancing material being made through a central well  238 . In such an embodiment sulfur dioxide, optionally with an additional fluid may be introduced into well  238  and as production begins and continues is drawn outwardly toward wells  230 ,  232 ,  234 , and  236 . 
     In  FIG. 5  a further embodiment of a well pattern is shown. In this instance, two five spot patterns are shown together and it will be appreciated by those skilled in the art that this pattern could be repeated over and entire field. In such instances the injected material may be used to drive gas or other desired materials toward production wells, which include not only  230 ,  232 ,  234 , and  236  but also  240  and  242 , with injection being through wells  244  and  238 . 
     The use of materials to push desired fluids, such as hydrocarbons or the like, from a subterranean formation is well known and may be practiced in combination with the injection of the SO 2 . The sulfur dioxide as produced above is usable for injection without the purification required when pure sulfur dioxide is desired. For instance, the stream produced through line  56  is frequently of adequate purity for use for this purpose. 
     Accordingly, when processes, such as discussed above are available, the produced sulfur as well as available additional sulfur dioxide may be used to reduce the amount of H 2 S in the formation. 
     While a representative process has been shown utilizing a Claus process and sulfur oxidation, it is well known that SO 2  may be produced or available from a variety of sources. Any such source is considered to be suitable for use for this purpose. Further, while the process shown in  FIG. 1  utilizes the recovery of sour gas it is clear that the process of the present invention is also useful when materials such as crude oils or light hydrocarbons, such as condensates, are produced. The sulfur recovery may be at a remote location in this instance since the oils will be refined at a refinery location. Typically such crude oils may be treated for the removal of readily removeable H 2 S at the production site. Such H 2 S can be converted to SO 2  and re-injected. Alternatively other sources of SO 2  may be used. 
     As noted previously it has been proposed in the past to dispose of unwanted SO 2  and SO 2  and carbon dioxide mixtures, as well as mixtures with other gases, into spent subterranean formations which are considered capable to contain the undesired gases. The use of such depleted formations for the storage of waste gases is not considered to show or suggest to those skilled in the art the present invention, which is directed to the use of SO 2  to remove H 2 S from a formation and to remove H 2 S from products recovered from the formation. 
     While the present invention has been described by reference to certain of its preferred embodiments, it is pointed out that the embodiments described are illustrative rather than limiting in nature and that many variations and modifications are possible within the scope of the present invention. Many such variations and modifications may be considered obvious and desirable by those skilled in the art based upon a review of the foregoing description of preferred embodiments.