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

Abstract

A process to reduce the hydrogen sulfide content of a hydrogen sulfide-containing subterranean formation and of products recovered from the subterranean formation by injecting sulfur dioxide into the subterranean formation.

Description

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 (H₂S). 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 H₂S produced with hydrocarbon gases, liquids and or crude oil may be reduced.

In processes such as the well-known Claus process, H₂S can be reacted with sulfur dioxide (SO₂) for form sulfur from SO₂ and H₂S. The formation of sulfur occurs according to reactions as set out below.

The Claus process reactions can be considered to be:

2 H₂S+3O₂→2SO₂+2H₂O  (1)

SO₂+2H₂S→3S+2H₂O  (2)

Previously, it has been proposed to dispose of liquid or gaseous SO₂ 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 H₂S 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 SO₂ is the injection of this material into H₂S-containing, depleted, sour-gas reservoirs.

Since many reservoirs containing substantial quantities of H₂S 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 H₂S 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 H₂S 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 H₂S in a subterranean formation during the injection of SO₂;

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 SO₂ for injection into a subterranean formation containing H₂S. 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 H₂S and producing gas. Sour gas is recovered through a line 14 and passed to a gas treatment facility 16 where the H₂S 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 H₂S 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 H₂S 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 SO₂ 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 SO₂ is then passed via line 44 to a SO₂ 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 SO₂ is desirably injected on a continuous or intermittent long-term basis. In FIG. 2, the reduction of the H₂S in a formation is shown. In the formation shown, the calculations of the results are based upon the recovery of gas containing H₂S 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 SO₂. After ten years, the H₂S in the formation has been reduced from about 36 percent initially to about 24 percent. This reduction is accomplished by simply returning the SO₂ produced by processing the H₂S removed from the formation and returning it to the formation as SO₂ at an injection well. Desirably well 10 is periodically tested to determine when and whether an SO₂ breakthrough has occurred. The injection of SO₂ can be stopped when the products contain levels of SO₂.

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 SO₂. 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 H₂S in the formation.

While a representative process has been shown utilizing a Claus process and sulfur oxidation, it is well known that SO₂ 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 H₂S at the production site. Such H₂S can be converted to SO₂ and re-injected. Alternatively other sources of SO₂ may be used.

As noted previously it has been proposed in the past to dispose of unwanted SO₂ and SO₂ 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 SO₂ to remove H₂S from a formation and to remove H₂S 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.

Claims

1. A method for reducing the hydrogen sulfide content of a hydrogen sulfide-containing subterranean formation and providing energy, the method consisting essentially of: a) providing a supply of sulfur dioxide at an injection site for the subterranean formation;b) injecting the sulfur dioxide into the subterranean formation; and,c) recovering a product stream from the subterranean formation.

2. The method of claim 1 wherein the injection site comprises an injection well extending from an earth surface into the subterranean formation.

3. The method of claim 1 wherein the sulfur dioxide is passed through at least a portion of the subterranean formation.

4. The method of claim 1 wherein at least a portion of the hydrogen sulfide is reacted with the sulfur dioxide in situ in the subterranean formation to produce sulfur.

5. The method of claim 1 wherein at least a portion of the sulfur dioxide injected is produced from hydrogen sulfide recovered from at least one product stream from the subterranean formation. gas.

6. The method of claim 5 wherein the product stream comprises a hydrocarbon gas.

7. The method of claim 5 wherein the product stream comprises crude oil.

8. The method of claim 5 wherein the product stream comprises a light hydrocarbon liquid.

9. A method for reducing the hydrogen sulfide content of fluids produced from an hydrogen sulfide-containing subterranean formation, the method comprising: a) providing a supply of sulfur dioxide at an injection site for the subterranean formation;b) injecting the sulfur dioxide into the subterranean formation; andc) recovering fluids having a reduced hydrogen sulfide content from the subterranean formation.

10. The method of claim 9 wherein the injection site is an injection well extending from an ear surface into the subterranean formation.

11. The method of claim 9 wherein the fluid is at least one of a gas, a liquid or a mixture thereof.

12. The method of claim 9 wherein the sulfur dioxide is injected alone or with a drive fluid.

13. The method of claim 9 wherein sulfur dioxide injection is stopped when sulfur dioxide is present in the recovered fluids.