HK1210247B - Treating sulfur containing hydrocarbons recovered from hydrocarbonaceous deposits - Google Patents

Description

Treatment of sulfur-containing hydrocarbons recovered from hydrocarbonaceous deposits

Technical Field

The present invention relates to methods and apparatus for treating and processing liquid, semi-solid, and gaseous hydrocarbons obtained from hydrocarbonaceous geologic materials, including tar sands, oil sandstones, and oil shales. In particular, the present invention relates to a method of removing sulfur contaminants found in gaseous hydrocarbons obtained from processes such as Steam Assisted Gravity Drainage (SAGD) processes.

Background

As used herein, a hydrocarbon-containing deposit is to be considered to include tar sands, oil sandstones, oil shales, and all other naturally occurring geologic materials having hydrocarbons contained within a generally porous, petrophysical inorganic matrix. The matrix may be loose, brittle or hard.

Tar sands are naturally occurring geological formations found, for example, in canada (labda) (alberta). The sand has the potential to produce large quantities of oil. Tar sands are porous, typically loose or friable, and typically contain large amounts of clay and have interstitial spaces filled with high viscosity hydrocarbons, commonly referred to in the art as bitumen. Most of these tar-like pitch materials are residues that remain after lighter (lower molecular weight) hydrocarbons have escaped or been degraded by the action of microorganisms, water washing and possibly inorganic oxidation. Extremely extensive tar sand deposits are present in northern sband and elsewhere along the asian pascal river (athabascaiver). The deposits are estimated to contain potential yields in excess of 1.6 trillion barrels of oil.

Oil shale is associated with oil sands and tar sands; however, the matrix is a fine-grained laminated sedimentary rock usually containing oil-producing organic compounds (known as kerogen). Oil shale is present in many places around the world. In particular, kerogen-rich shales exist in Wyoming (Wyoming), Colorado (Colorado), and Utah (Utah) in the United States (United States) and are estimated to contain over 5400 billion barrels of potential oil.

Hydrocarbons that may be recovered from tar sands and oil shale may include, but are not limited to, bitumen, kerogen, asphaltenes, paraffins, alkanes, aromatic hydrocarbons, olefins, naphthalenes, and xylenes.

In known techniques for recovering oil from hydrocarbon-containing deposits, high molecular weight bitumen or kerogen materials can be driven out of sand, sandstone, or shale using heat. For example, in a Steam Assisted Gravity Drainage (SAGD) process, two parallel horizontal wells are drilled into the formation, one well being about 4 to 6 meters above the other. The upper well injects steam and the lower well collects heated crude oil or bitumen flowing out of the formation and any water from condensation of the injected steam. The process is based on the injected steam forming a "steam chamber" that grows vertically and horizontally in the formation. The heat from the steam reduces the viscosity of the heavy crude oil or bitumen, which allows it to flow down into the lower wellbore. The steam and gas rise due to their low density compared to the underlying heavy crude oil, ensuring that no steam is produced at the lower production well. The released gases, which include methane, carbon dioxide and often some hydrogen sulfide, tend to rise in the steam chamber, filling the void spaces left by the oil and forming an insulating blanket to some extent over the steam. Oil and water flow into the lower wellbore by countercurrent gravity-driven drainage. The condensed water and crude oil or bitumen is recovered to the surface by using the underground system pressure or by a pump (e.g., a thrust cavity pump) that facilitates the movement of high viscosity fluids with suspended solids.

After removal from the SAGD well, the dissolved and entrained gases are separated from the bitumen and the bitumen is then combined with a medium molecular weight "carrier" (known as a diluent) to produce a thin bitumen (dilbit). Thin bitumens are hydrocarbon materials that are lighter and less viscous than the raw bitumen and are easier to transport via pipelines to refineries. At the refinery, the dilute bitumen is processed into a final product, and in some cases, a portion of the intermediate product is returned to the production site for use as a diluent.

The SAGD process has serious drawbacks in terms of the gaseous components obtained and the liquid or semi-solid bitumen. These gaseous components include not only hydrocarbons but also undesirable sulfur-containing compounds, such as hydrogen sulfide (H)₂S), mercaptans (RSH), carbonyl sulfide (COS) and carbon disulfide (CS)₂). Production sites typically utilize the associated gas initially separated from the bitumen as fuel for steam generators, however, sulfur-containing combustion products derived from the use of gas components as fuel are a major pollution problem. An economical way to prevent sulfur air pollution is to remove sulfur compounds from the gaseous components before use as fuel. In addition to SAGD processes, there are other processes that can benefit from the present invention for recovering hydrocarbons from hydrocarbon-containing deposits, such as periodic steam injection or "intermittent hot-shot oil recovery (Huffand Puff), in which steam is injected into a production well (often a vertical well) for a period of time, then soaked, and then petroleum is produced; or steam flooding, which is similar to SAGD, but utilizes a series of vertical wells to inject steam and recover oil; or water flooding, which is similar to steam flooding, but uses water that can be recovered and reinjected; or gas re-injection, where some of the produced natural gas is compressed and re-injected; or CO₂Injection, in which CO from an external source is introduced₂For injection into the reservoir; or in situ thermal methods, in which a portion of the well is buried underground to provide heat to the oil.

Although there are many compounds containing H₂Renewable processes for S gas removal and sulfur recovery, but the presence of mercaptans can still pose serious operational problems because these processes cannot reliably remove them. In fact, RSH will typically end up with "sweet" product gas, regeneration air discharge, and sulfur produced. COS and CS₂Will generally be able to pass through and not be absorbed or converted. The strong odor of RSH makes it difficult, if not impractical, to dispose of the sulfur produced, and the odor in the operating unit may make it practically inoperable. However, H₂S can be easily removed and converted intoElemental sulphur (S).

The invention thus relates to the removal of harmful sulphur-containing compounds, in particular RSH, from gaseous components, leaving H behind₂S, then H can be processed₂S to provide a sulfur-free gaseous fuel.

Disclosure of Invention

The present invention is directed to avoiding the problems associated with using and/or processing gaseous components obtained from hydrocarbon-containing deposits, particularly including those that use processes such as the SAGD process to recover bitumen from oil sands. In particular, the invention relates to treating a feed stream obtained from a SAGD process that avoids the deleterious effects of sulfur-containing mercaptan compounds contaminating the gaseous hydrocarbons obtained in the SAGD process.

More particularly, the invention relates to a process for treating hydrocarbons obtained from hydrocarbon-containing deposits, wherein the hydrocarbons comprise a mixture of liquid hydrocarbons and gaseous components comprising hydrogen sulfide and mercaptans. This mixture is first separated into a liquid or semi-solid hydrocarbon phase and a gas phase comprising mainly hydrocarbon fuel gas contaminated with sulphur-containing compounds such as hydrogen sulphide and mercaptans. When hydrocarbons are recovered from oil sands using an in situ SAGD process, the liquid or semi-solid hydrocarbons comprise bitumen. The separated gas components are then contacted with a lean oil (a light hydrocarbon, such as kerosene, naphtha, etc.) so that the mercaptans are absorbed by the lean oil to form a sour or rich oil. The gaseous product containing hydrogen sulfide is separated from the rich oil and treated to remove and/or convert the hydrogen sulfide to produce a desulfurized fuel gas product that can be used as a combustion product elsewhere in an above-ground facility, specifically to generate steam for a SAGD process.

The separated liquid hydrocarbons are then preferably treated by mixing with lean oil or equivalent hydrocarbons to reduce the viscosity of the liquid or semi-solid hydrocarbons so that they can be transported for processing in a refinery. Alternatively, the liquid or semi-liquid hydrocarbons may be mixed with a rich oil or a mixture of rich and lean oil. In this alternative process, the rich oil containing mercaptans is passed with the liquid hydrocarbons to a refinery where the mercaptans can be processed along with the hydrocarbons to form petroleum-related products. In a preferred process scheme, a mixture of liquid hydrocarbons and gaseous components is obtained using a SAGD process. When bitumen is a liquid or semi-solid hydrocarbon obtained in a SAGD process, the addition of a diluent hydrocarbon (i.e., lean, rich, or a mixture of both) results in the formation of a thin bitumen, which can then be readily transported to refinery operations from the area where SAGD in situ recovery of bitumen is performed.

The gaseous product or sweet alcohol fuel gas obtained after contact with or scrubbing with lean oil may be treated using a number of gas-liquid contact processes to remove hydrogen sulfide and/or convert it to elemental sulfur. In one preferred process, the gaseous product is contacted with a caustic solution or caustic solution in a gas-liquid mass transfer device wherein hydrogen sulfide is absorbed and converted by the caustic solution to produce a sulfur-free fuel gas that can be used for combustion in other process unit operations. The spent or sulfur-rich caustic solution is then treated with air in a bioreactor where bacteria oxidize the absorbed sulfur under oxygen-limiting conditions to form elemental sulfur and at the same time regenerate the caustic solution for recycle back to contact the incoming gaseous products.

Other hydrogen sulfide removal processes that can be used to produce sulfur-free fuel gases include those that employ the claus reaction (claus). For example, sulfur dioxide (SO) may be used₂) Treatment of a mercaptan-free gaseous product in a process as an oxidant to convert H by a modified liquid phase Claus reaction₂S is converted to elemental sulphur. The elemental sulphur formed is soluble in the reaction solution, which eliminates circulating solids in the high-pressure apparatus. Elemental sulfur is then crystallized and separated from the process using equipment designed to handle solids, while the remainder of the process remains solids free.

Yet another preferred process (also known as a redox process, exemplified and disclosed in U.S. Pat. Nos. 4,238,462 and 5,160,714, the teachings of which are incorporated herein by reference) involves a gas-liquid mass transfer operation in which a liquid catalyst is formulatedThe product is contacted with a gaseous product containing hydrogen sulfide to catalytically oxidize the hydrogen sulfide to elemental sulfur, preferably using an iron chelate catalyst. The used polyvalent metal chelate mixture is continuously regenerated by oxidation by contacting the reaction solution with dissolved oxygen, preferably in the form of ambient air, in a separate contact zone. In this continuous process for removing hydrogen sulfide by contact with, for example, a catalytic ferric solution, the catalytic solution is placed in an absorbent zone where H is present₂S is absorbed by the catalytic ferric chelate solution and the solution is reduced to ferrous iron) and an oxidant zone in which the reduced ferrous iron is oxidized back to ferric state.

Regardless of the process used to ultimately convert and remove hydrogen sulfide from the gaseous product, an important step in the present invention is to first remove mercaptans from the gaseous components that were initially separated from the liquid or semi-solid hydrocarbons obtained from the hydrocarbonaceous deposit. The lean oil used to contact or scrub the gaseous components to absorb mercaptans can include naphtha, kerosene, medium hydrocarbons, gasoline streams, jet fuel, diesel and mixtures of these hydrocarbons. As mentioned, the removal of mercaptans using the lean oil can be accomplished using an absorber, preferably a countercurrent gas-liquid contactor, such as a random packed column, a structured packed column, or a bubble tray column. The Number of Transfer Units (NTU) that can be achieved depends directly on the type of column used and the type of lean oil used. Preferably, the absorber will operate at a pressure in the range of about 30psig to 70psig and a temperature of less than 135 ° F. The mercaptan content of the gaseous components fed to the absorber need not be maintained or controlled at a particular level, however, a preferred level is less than 8500ppm by volume. The absorber column should be designed to reduce the total mercaptan concentration in the gas product to an economically viable low level. The preferred low level will be as low as about 2 ppmv.

The rich oil obtained as a bottoms product from the absorber can be used directly as a diluent hydrocarbon by adding it to the bitumen to form a thin bitumen. It may be desirable to process the rich oil to remove mercaptans to obtain a recycled or regenerated lean oil for recycle back to contact with gaseous components and/or with liquids recovered from the hydrocarbonaceous depositMixing with solid or semi-solid hydrocarbons. However, in some cases, the design of the absorber may result in a lean oil versus unacceptable level of H₂S and in such cases a stripping process is required to remove the absorbed hydrogen sulphide and produce a rich oil substantially free of hydrogen sulphide.

Separation of mercaptans and hydrogen sulfide from the rich oil stream is difficult to achieve. To promote H₂S separation from rich oil, the stripper must operate at a significantly higher pressure than the absorber and requires a reflux condenser and a bottoms reboiler. The use of reflux condenser and reboiler allows for sufficient vapor and liquid flow in the column to allow for nearly all of the H₂S leaves in the overhead vapor. Unfortunately, some mercaptans also leak with the overhead vapors. Since the amount of mercaptans in this vapor stream is significantly lower than the sour gas component that was originally separated from the liquid hydrocarbons, a portion of this overhead can be recycled back to the front of the absorber where it is mixed or blended with the sour gas component feed.

The pressure of the stripping column should be selected so that H₂The removal of S is maximized. The preferred method is to run the stripper between 50psig to 200psig to achieve an acceptable separation. This requires a feed pump or rich feed pump to bring the rich oil above the column operating pressure, including pipeline and other system losses. Preferably, the rich oil is fed into the lower half of the column, which is preferably a tray distillation column. Use of a bottoms reboiler to generate the necessary vapor flow within the column to remove H₂S and then a small portion of thiol. As the vapor travels up the column, it contacts the rich oil and then reflux condensate, which further promotes the desired separation. As mentioned, mercaptans tend to leak with the overhead vapors because the separation is not very efficient.

An alternative method of removing mercaptans from gaseous components is to perform a distillation process in which liquid from the overhead reflux condenser and vapor from the reboiler are used to distill the lean oil and gaseous components. This alternative approach eliminates the need to combine the absorption and stripping mentioned above.

The petroleum oil rich in mercaptans and low hydrogen sulphide content leaving the scrubbing process can be further processed to remove and convert mercaptans or, as mentioned, used as a diluent to reduce the viscosity of liquid or semi-solid hydrocarbons obtained from hydrocarbonaceous deposits. If these liquid or semi-solid hydrocarbons comprise bitumen, the resulting mixture, when enriched with or without lean oil, is referred to as thin bitumen. To remove and convert mercaptans from the rich oil, the preferred method is to contact the rich oil with caustic, thereby converting the mercaptans to mercaptides and retaining them in the caustic solution, thereby forming a regenerated lean oil. The mercaptides in the spent caustic are finally further treated to convert the mercaptides to disulfide oils (DSO) via oxidation reactions, which can then be collected and further processed at a refinery with liquid hydrocarbons. The regenerated caustic solution is then recycled to be mixed with fresh or make-up caustic to treat the rich oil feed.

Another more preferred process for converting mercaptans (as opposed to extraction) to disulfide oils uses aqueous treatment solutions and oxidation reactions. Disulfide oils remain in the separated hydrocarbon product stream removed from the process. More specifically, the rich oil containing mercaptans is combined with an oxygen-containing gas to form a feed stream. This feed is contacted with an aqueous treatment solution comprising water, alkali metal hydroxide, a sequestered metal catalyst, in a contactor vessel where the catalyst and oxygen are used to convert mercaptans to disulfide oils via an oxidation reaction. The contacting step forms a product mixture that is directed to at least one separation zone where an upgraded hydrocarbon stream containing disulfide oils is separated from the mixture. This DSO-containing lean oil stream may also be used in addition to or as an alternative to the lean oil described above. After being replenished with make-up catalyst and/or other components of the treating solution, the treating aqueous solution is recycled to treat the rich oil feed, if necessary.

The catalyst composition used in the aqueous treatment solution is preferably a liquid chelated polyvalent metal catalyst solution. Multivalent catalysts include, but are not limited to, metal phthalocyanine, wherein the metal cation is selected from the group consisting of manganese (Mn), iron (Fe), cobalt (Co), nickel (Ni), copper (Cu), zinc (Zn), ruthenium (Ru), rhodium (Rh), palladium (Pd), silver (Ag), and the like. The catalyst concentration is from about 10ppm to about 10,000ppm, preferably from about 20ppm to about 4000 ppm. The particular catalyst selected may be included during preparation of the treatment solution and/or added to the solution at a later time where the solution is used.

Contacting of the hydrocarbon feed with the aqueous treating solution may be accomplished by any liquid-liquid mixing device (e.g., packed column, bubble tray, stirred vessel, plug flow reactor, fiber-membrane contactor, etc.). Preferably, the contacting is carried out using a contactor that achieves rapid liquid-liquid mass transfer without causing difficulties in obtaining rapid and clean phase separation between the hydrocarbon and the aqueous treatment solution. The contactor is configured to cause little or no agitation and reduce entrainment of aqueous solution in the hydrocarbon. Two or more stages of contacting with the aqueous treatment solution may be employed to achieve a higher degree of treatment efficiency.

These and other embodiments will become more apparent from the detailed description of the preferred embodiment contained below.

Drawings

Fig. 1 schematically illustrates a process flow diagram of one possible embodiment of the present invention.

Detailed Description

The present invention relates to the removal of sulphur contaminants, in particular mercaptans, present in gaseous components separated from liquid and/or semi-solid hydrocarbons obtained from in situ SAGD processing of hydrocarbon-containing deposits, preferably from oil or tar sands. With reference to fig. 1, one possible process flow scheme will be described, however, one skilled in the art will appreciate that alternative flow schemes may be devised. A mixture of liquid and/or semi-solid hydrocarbons (further referred to herein simply as "liquid hydrocarbons"), gaseous components and water is obtained from the hydrocarbonaceous deposit and delivered to a separator 2 in an above-ground processing facility where the gaseous components are removed via line 3 and the liquid hydrocarbons are removed via line 4. The separated water (not shown) may be recycled to reuse the steam in the SAGD process or used as other process water. When produced from oil sands, the recovered liquid hydrocarbons comprise bitumen.

The liquid hydrocarbons in line 4 are mixed with lean oil 13 as a diluent in vessel 14 to reduce the viscosity of the liquid hydrocarbons, allowing for easier transport to a refinery for processing into useful hydrocarbon products. When bitumen is a liquid hydrocarbon, the resulting diluted stream 15 is referred to as a thin bitumen. The lean oil 13 may be any hydrocarbon or mixture of hydrocarbons capable of diluting the liquid hydrocarbons 4, preferably with a low sulfur content. Preferred lean oils include naphtha, kerosene, medium hydrocarbons, gasoline streams, jet fuel, kerosene, diesel, naphtha, and mixtures thereof. One possible choice for the lean oil is a cracked naphtha, such as FCC naphtha or coker naphtha, which boils in the range of about 35 ℃ to about 230 ℃.

Separated gas component 3 comprises hydrocarbon fuel gas and sulfur contaminants such as mercaptans, hydrogen sulfide, carbonyl sulfide, and carbon disulfide. This sulfur contaminated fuel gas is further processed in vessel 40 to selectively extract or absorb mercaptans over hydrogen sulfide. This is done using a lean oil 6 which may be the same or different in composition from the lean oil 13 used to dilute the liquid hydrocarbons. The contacting vessel 40 may be a combination of a gas-liquid absorber, followed by a stripping fractionator, or may be a distillation column that uses reboiling and reflux to achieve the desired separation of mercaptans from hydrogen sulfide. A recycle lean oil 8, described more fully below, may be used in addition to lean oil 6. The rich oil containing mercaptans is removed via line 7, all or a portion of which can be used as diluent 16 in line 7 to reduce the viscosity of the liquid hydrocarbons in the treatment process 14. In this case, the mercaptans are transported with the diluent hydrocarbons and liquid hydrocarbons to a refinery where the mercaptans are ultimately removed from the hydrocarbons using known processing techniques.

Alternatively, all or a portion of rich oil 7 may be further processed in situ to remove mercaptans and convert them to disulfide oils in process 17, thereby producing a regenerated or recycled lean oil that may be used in contactor 40 to absorb mercaptans from gaseous components. The process 17 preferably involves contacting the rich oil 7 with a caustic solution 18, thereby converting mercaptans to mercaptides, which remain in the caustic solution. Spent caustic is separated from the regenerated lean oil removed via line 8. The separated spent caustic 20 is mixed with an oxygen-containing gas (e.g., air) via line 19 in vessel 25 where an oxidation reaction takes place in the presence of a catalyst to convert mercaptides to disulfide oils (DSO) and form a regenerated caustic solution. The DSO is separated from the regenerated caustic solution and removed via line 27 for further processing or mixing back into the dilute bitumen. The regenerated caustic removed via line 26 can be recycled and mixed with the caustic in line 18.

A fuel gas reduced in mercaptans but enriched in hydrogen sulphide is removed from the process 40 via line 5 and sent to process 10 where hydrogen sulphide is converted to elemental sulphur in process 10, which is removed via line 12. The hydrogen sulfide can be converted and removed using a number of different processes to produce a sulfur-free fuel gas that is removed via line 11. One such process involves the use of a liquid-gas contactor in which a caustic solution is contacted with fuel gas and hydrogen sulfide to extract hydrogen sulfide. The sulfur-containing or spent caustic is then processed in a bioreactor to produce a regenerated caustic solution, which can be recycled and added with fresh make-up caustic to treat the fuel gas and hydrogen sulfide. Alternatively, process 10 may utilize a Claus reaction or modified Claus reaction in which hydrogen sulfide is absorbed in a hydrocarbon and sulfur dioxide (SO) is used₂) As an oxidant to supply the inlet H₂S is converted to elemental sulphur. Elemental sulfur is soluble in the resulting hydrocarbon and aqueous solutions, which eliminates circulating solids in the high pressure equipment. The sulfur is then crystallized and separated from the process using equipment designed to handle solids, while the remainder of the process remains solids free.

Removal of sulfur from fuel gasA third and preferred process for the hydrogenation involves reacting H₂The S contaminated fuel gas is contacted with a liquid redox catalyst solution 9 and air 30 to produce a sulfur-free fuel gas 11 and elemental sulfur 12. Regardless of the process used, the sulfur-free fuel gas is most preferably used as a combustion gas to heat another unit operation in situ, most specifically to generate steam for in situ recovery of liquid hydrocarbons from the hydrocarbon-containing deposits.

As used herein, thiol compounds include methyl mercaptan, ethyl mercaptan, n-propyl mercaptan, isopropyl mercaptan, n-butyl mercaptan, thiophenol, and higher molecular weight mercaptans. Thiol compounds are often represented by the symbol RSH, where R is a normal or branched alkyl or aryl group. Specific types of mercaptans that may be present in the gas stream and that can be converted to disulfides by the oxidation process of the present invention will include methyl mercaptan, ethyl mercaptan, propyl mercaptan, butyl mercaptan, pentyl mercaptan, and the like.

The treatment process 17 for removing mercaptans from the rich oil preferably uses an aqueous treatment solution containing an alkali metal hydroxide. The mercaptan levels of the rich oil may range from about 10wppm to about 10,000wppm, based on the weight of the rich oil. While the above description relates to a treatment process using a two-phase treatment solution in the absence of oxygen, another approach may use an aqueous treatment solution and an added oxygen-containing gas that oxidizes mercaptans in the hydrocarbon feed to disulfide oils that remain in the hydrocarbon phase. The treatment solution may be prepared by adding a metallophthalocyanine catalyst to an aqueous solution of an alkali metal hydroxide.

The foregoing description of the specific embodiments will so fully reveal the general nature of the invention that others can, by applying current knowledge, readily modify and/or adapt for various applications such specific embodiments without departing from the generic concept, and, therefore, such adaptations and modifications are intended to be comprehended within the meaning and range of equivalents of the disclosed embodiments. It is to be understood that the phraseology or terminology herein is for the purpose of description and not of limitation.

The means, materials, and steps for carrying out various disclosed functions may take a variety of alternative forms without departing from the invention. Thus, the expressions "means to.. and" means for.. or "any method step language capable of being found in the foregoing specification or the following claims and then described for a function is intended to define and encompass any structure, physical, chemical, or electrical component or structure, or any method step, which may exist now or in the future and which performs the recited function, whether or not exactly equivalent to the embodiment disclosed in the foregoing specification, i.e., other means or steps for performing the same function may be utilized; and is intended to be given its broadest interpretation in the terms of the appended claims.

Claims (19)

1. A method of treating hydrocarbons obtained from a hydrocarbon-containing deposit comprising

a) Providing a mixture of liquid hydrocarbons obtained from a hydrocarbonaceous deposit and gaseous components, wherein the gaseous components comprise hydrogen sulfide and mercaptans;

b) separating the liquid hydrocarbons from the gaseous component;

c) contacting the gaseous component with a lean oil, whereby the mercaptans are absorbed by the lean oil to form a rich oil;

d) separating a gaseous product containing the hydrogen sulfide from the rich oil;

e) treating the gaseous products to remove the hydrogen sulfide to produce a lean fuel gas; and

f) treating the liquid hydrocarbons obtained in step b) to reduce viscosity before being sent to a refinery for processing.

2. The process of claim 1, where the mixture of liquid hydrocarbons and gaseous components is obtained using a SAGD process.

3. The method of claim 1, wherein the liquid hydrocarbon comprises bitumen.

4. The method of claim 1, wherein the treating of liquid hydrocarbons in step f) comprises mixing the liquid hydrocarbons with a diluent hydrocarbon.

5. The method of claim 1, wherein the treatment of liquid hydrocarbons in step f) comprises mixing the liquid hydrocarbons with the rich oil from step d).

6. The method of claim 1, wherein the treatment of liquid hydrocarbons in step f) comprises mixing the liquid hydrocarbons with a diluent hydrocarbon and the rich oil from step d).

7. The method of claim 1, wherein the treating of the gaseous product from step d) comprises contacting the gaseous product with a liquid solution in a gas-liquid contactor to convert the hydrogen sulfide to elemental sulfur.

8. The method of claim 1, wherein the treatment of the gaseous product from step d) comprises contacting the gaseous product with a liquid solution in a gas-liquid contactor followed by an oxidation reaction to convert the hydrogen sulfide to elemental sulfur.

9. The process of claim 1 wherein the rich oil from step d) is contacted with caustic to remove the mercaptans to form a regenerated lean oil, whereby the mercaptans are converted to mercaptides and transferred to the caustic to form a spent caustic.

10. The process of claim 9 wherein the regenerated lean oil is contacted with the gaseous component in step c) to remove the mercaptans from the gaseous component.

11. The method of claim 9, wherein the regenerated lean oil is added to the liquid hydrocarbons in step f) to reduce the viscosity of the liquid hydrocarbons.

12. The method of claim 9, further comprising regenerating the spent caustic by:

a) mixing the spent caustic with an oxygen-containing gas;

b) oxidizing the spent caustic with a catalyst to form a regenerated caustic, thereby oxidizing the mercaptides in the spent caustic to disulfide oils; and

c) separating the regenerated caustic from the disulfide oil and recycling the regenerated caustic for contact with the rich oil from step d) of claim 1.

13. The process of claim 1 wherein the contacting in step c) comprises contacting the gaseous components with the lean oil in a distillation column and distilling to form a rich bottoms and a sweet mercaptan gas overhead comprising fuel gas and hydrogen sulfide.

14. The process of claim 1, wherein the contacting in step c) comprises contacting the gaseous component with the lean oil in a countercurrent liquid-gas low pressure absorber.

15. The method of claim 14, further comprising fractionating to remove residual hydrogen sulfide from the rich oil.

16. A method of treating hydrocarbons obtained in situ from oil sands using a SAGD process, comprising

a) Separating bitumen from gaseous components, wherein the gaseous components comprise hydrocarbons, hydrogen sulfide and mercaptans;

b) mixing the bitumen with a sufficient amount of a hydrocarbon diluent to form a diluted bitumen;

c) contacting the separated gaseous components from step a) with a lean oil in a countercurrent liquid-gas column, whereby the mercaptans are absorbed in the lean oil to form a rich oil, and wherein a low mercaptan gas product is recovered; and

d) treating the low-mercaptan gas product with an aqueous liquid redox catalyst solution to oxidize the hydrogen sulfide to elemental sulfur and produce a sulfur-free fuel gas.

17. The method of claim 16, wherein the rich oil is mixed with the bitumen to form the thin bitumen.

18. The method of claim 16, wherein the rich oil is treated with caustic to remove the mercaptans to form a regenerated lean oil that is recycled and used in step c).

19. The method of claim 18 wherein spent caustic containing the mercaptans removed from the rich oil is mixed with an oxygen-containing gas and then oxidized using a catalyst to form regenerated caustic, thereby oxidizing mercaptides in the spent caustic to disulfide oils that are separated from the regenerated caustic, and wherein the regenerated caustic is recycled for use in treating the rich oil.