Dealing With H2S In Heavy Oil Thermal Projects
- Wayne Monnery (Xergy Processing Inc.)
- Document ID
- Society of Petroleum Engineers
- SPE International Thermal Operations and Heavy Oil Symposium, 1-3 November, Calgary, Alberta, Canada
- Publication Date
- Document Type
- Conference Paper
- 2005. SPE/PS-CIM/CHOA International Thermal Operations and Heavy Oil Symposium
- 4.1.5 Processing Equipment, 5.8.3 Coal Seam Gas, 5.4.2 Gas Injection Methods, 5.2.1 Phase Behavior and PVT Measurements, 4.2.3 Materials and Corrosion, 5.7.5 Economic Evaluations, 5.3.9 Steam Assisted Gravity Drainage, 4.9 Facilities Operations, 4.6 Natural Gas, 4.3.4 Scale, 4.1.4 Gas Processing, 5.4.6 Thermal Methods
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There is an abundance of natural gas being discovered and produced that is slightly sour.According to a US Department of the Environment (DOE) survey that includes Canada, about 80% of current and new gas has a hydrogen sulphide (H2S) concentration of 1% or less. Of course, this must be treated to remove the H2S to meet sales gas specifications.For small scale (less than 50 - 100 kg) and large scale (greater than 20 tonne/d) of equivalent sulphur, current technologies appear reasonable.Conversely, for intermediate range (0.1 - 20 tonne/d) equivalent sulphur, current technology has proven to have high capital and/or operating costs and some processes are difficult to operate. Therefore, there is a need for an intermediate scale (0.1 to 20 tonne/d) process with lower capital and operating cost than those currently available. The applications of such a process range from the removal of H2S from acid gas at low pressure produced from the amine process to high pressure raw sour gas. There are additional challenges from sour gas associated with heavy oil thermal projects in that it is at low pressure and contains substantial C7?. The elemental sulphur produced should be of sales grade quality such that the handling of the product can fit into the existing sulphur infrastructure and sold into existing markets. Otherwise, disposal of the product becomes costly and in some cases becomes another environmental problem.
In answer to this need, Xergy Processing Inc. has developed a gas phase direct oxidation process for the above applications as well as treating heavy oil off-gas, fuel gas, power generation gas.The process has relatively low capital and operating costs and is easy to operate, with no equipment that is unfamiliar to the petroleum industry.Conversion to sulphur depends on the process configuration and pressure but ranges from 80% to 99.9+% based on lab and field data.
There is an abundance of natural gas being discovered and produced that is slightly sour.According to recent US Department of Energy (DOE) and Gas Research Institute (GRI) surveys (Dalrymple et al., 1991; Hugman et al., 1993), up to 25% of current and new natural gas is sour.About 80% of that sour gas has a hydrogen sulphide (H2S) concentration of 1% or less and CO2 concentration of 3% or less.Worldwide, the percentage of gas that is sour may be as high as 30% (Cornot-Gandolphe, 1995).Since sales gas specifications of 4-16 ppm H2S are required, such sour gas must be treated to remove it.
Recently, government regulatory bodies have introduced more stringent regulations in certain jurisdictions concerning the recovery of sulphur and release of sulphur as SO2 to the atmosphere.The new regulations imposed will cause the sour gas processing industry to initiate facility modifications and additions in order to substantially reduce sulphur emissions.This means that more small scale sulphur recovery will be required as well as more tail gas clean up in larger existing sulphur units. In addition to non-associated natural gas, there is a substantial amount of associated gas with the numerous heavy oil thermal projects as the projects move from pilot to commercial scale.The concentration of H2S in the associated gas is difficult to quantify because it depends on the amount of steam injected and the steam chamber temperature and pressure.However, several projects in Alberta are having to deal with sulphur ranging from 1 - 5 tonnes/d with a few ranging as high as 15 tonnes/d.
For small scale (less than 50 - 100 kg) and large scale (greater than 20 tonne/d) of equivalent sulphur, current technologies appear reasonable.For small scale H2S removal, scavenger chemicals are often used.However, above the small scale range, the chemical and hence operating cost can be excessive. For large scale H2S removal, sweetening with a solvent process followed by sulphur recovery via the modified Claus process has been the traditional approach, although acid gases with a low H2S concentration are difficult to process.However, for intermediate range (0.1 - 20 tonne/d) equivalent sulphur, current technology has proven to have high capital and/or operating costs and some processes are difficult to operate (Royan and Wichert, 1996). In addition, gas associated with heavy oil thermal projects presents additional challenges with pressure typically at about 210 - 350 kPag (30 - 50 psig), H2S concentration less than 5% and containing substantial C7+.
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