As used herein, hydrocarbonaceous deposit is to be taken to include tar sands, oil sands, oil sandstones, oil shales, and all other naturally-occurring geologic materials having hydrocarbons contained within a generally porous rock-like inorganic matrix. The matrix may be loose, friable, or indurate.
Tar sands are naturally-occurring geological formations found in, for example, Canada (Alberta). Such sands have potential for yielding large amounts of petroleum. Tar sands are porous, generally loose or friable, and typically contain substantial amounts of clay and have the interstices filled with high-viscosity hydrocarbons known generally in the art as bitumen. Most of these tar-like bituminous materials are residues remaining after lighter (lower molecular weight) hydrocarbons have escaped or have been degraded through the action of microorganisms, water washing, and possibly inorganic oxidation. Very extensive tar sand deposits occur in northern Alberta along the Athabasca River and elsewhere. Such deposits are estimated to contain a potential yield in excess of 1.6 trillion barrels of oil.
Oil shales are related to oil sands and tar sands; however, the substrate is a fine-grained laminated sedimentary rock typically containing an oil-yielding class of organic compounds known as kerogen. Oil shale occurs in many places around the world. Particularly kerogen-rich shales occur in the United States, in Wyoming, Colorado, and Utah, and are estimated to contain in excess of 540 billion potential barrels of oil.
Hydrocarbons recoverable from tar sands and oil shales may comprise, but are not limited to, bitumen, kerogen, asphaltenes, paraffins, alkanes, aromatics, olefins, naphthalenes, and xylenes.
In the known art of petroleum recovery from hydrocarbonaceous deposits, the high molecular weight bituminous or kerogenic material may be driven out of the sands, sandstones, or shales with heat. For example, in the Steam Assisted Gravity Drainage (SAGD) process, two parallel horizontal oil wells are drilled in the formation, one about 4 to 6 meters above the other. The upper well injects steam, and the lower one collects the heated crude oil or bitumen that flows out of the formation, along with any water from the condensation of injected steam. The basis of the process is that the injected steam forms 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 gases rise because of their low density compared to the heavy crude oil below, ensuring that steam is not produced at the lower production well. The gases released, which include methane, carbon dioxide, and usually some hydrogen sulfide, tend to rise in the steam chamber, filling the void space left by the oil and, to a certain extent, forming an insulating heat blanket above the steam. Oil and water flow is by a countercurrent, gravity driven drainage into the lower well bore. The condensed water and crude oil or bitumen is recovered to the surface by use of underground system pressure or by pumps such as progressive cavity pumps that work well for moving high-viscosity fluids with suspended solids.
Once removed from the SAGD well, the dissolved and entrained gases are separated from the bitumen and then the bitumen is combined with a mid-range molecular weight “carrier” referred to as diluent, creating dilbit. Dilbit is a lighter, less viscous hydrocarbon material than the raw bitumen, and is more easily transportable via pipeline to refineries. At the refinery, the dilbit is processed to final products, and in some cases, part of the mid-range production is returned to the production site for use as diluent.
The SAGD process has a serious shortcoming with regard to the gaseous components obtained along with the liquid or semi-solid bitumen. These gaseous components include not only hydrocarbons but also undesirable sulfur containing compounds such as hydrogen sulfide (H2S), mercaptans (RSH), carbonyl sulfide (COS), and carbon disulfide (CS2). The associated gas initially separated from the bitumen is typically utilized at the production site as fuel to steam generators, however, the sulfur containing combustion products from using the gaseous components as fuel is a major pollution problem. The economical route to prevent sulfur air pollution is to remove the sulfur compounds from the gaseous components before it is used as a fuel. In addition to the SAGD process there are other processes for recovery of hydrocarbons from hydrocarbonaceous deposits that can benefit from my invention, for example, cyclic steam injection or “Huff and Puff” where steam is injected into the producing well (usually a vertical well) for a period, then allowed to soak and then oil is produced; or steam flood, which is similar to SAGD, but with a series of vertical wells to inject steam and recover oil; or water flood that is similar to steam flood, but uses water that can be recovered and re-injected; or gas re-injection where some of the produced natural gas is compressed and re-injected; or CO2 injection where CO2 from an external source is brought in to inject into the oil reservoir; or in-situ thermal methods where a portion of the well is burned underground to supply heat to the oil.
Although there are a number of regenerable processes to remove and recover sulfur from H2S containing gases, the presence of mercaptans can cause serious operational problems because these processes do not reliably remove them. In fact, the RSH will typically end up in the “sweetened” product gas, the regeneration air vent, and on the sulfur produced. COS and CS2 will typically pass through and not be absorbed or converted. The strong smell of RSH makes it difficult (if not impractical) to handle the sulfur produced, and the smells in the operating unit can make it virtually inoperable. H2S can however can be easily removed and converted to elemental sulfur (S).
Accordingly, my invention is directed to removing the deleterious sulfur containing compounds, particularly RSH, from the gaseous components leaving behind the H2S, which can then be treated to provide a sulfur-free gaseous fuel.