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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.
With increasing numbers of remote fields of a small-to-medium sulfur load (1-100 tpd S) starting to produce in the Middle East, the demand has arisen for sulfur recovery processes that operate safely and reliably at this scale. While several processes have been presented in the last two decades, some doubts exist with operating companies on the reliability, the operational simplicity and flexibility regarding inlet conditions. In this paper, several processes are compared qualitatively for desulfurization of associated gas. Specifically the applicability of the Thiopaq O&G bio-desulfurization process for treatment of associated gas in the Middle East is investigated in more detail.
The Thiopaq O&G process combines sweetening and sulfur recovery of gas streams containing H2S (50 ppmv-100% vol.), and is relatively insensitive to fluctuations in feed flow, pressure and H2S concentration. Because of this robustness, it is ideally suited for treatment of sour associated gas, as the composition and flow vary more than that of typical natural gas or amine tail gas feeding Sulfur Recovery Units (SRU). Besides associated gas, the broad range of suitable H2S concentrations makes it also very interesting for sulfur recovery from lean acid gas streams.
As a large part of the world’s sour associated gas is found in the Middle East, the influence of a desert environment on this ambient temperature process using bacteria is further investigated. Plant data are presented that underline the operational stability of the process. Also the simple engineering measures taken to apply this process in a desert environment (hot, arid, limited operators) are presented, along with the economic impact of these measures. Finally, a typical design of a sour associated gas treatment process is shared. In conclusion, the Thiopaq O&G process is a highly suitable solution for desulfurization of sour associated gas sources in (sub)tropical and desert climates.
Technology developments for lowering gas treating and sulfur recovery costs for Permian basin gas have been underway for several years by GRI (formerly Gas Research Institute) and other technology development organizations. Several of these technologies are now nearing the point where commercial applications should be evaluated since significant cost savings and operational simplifications could be achieved by early adopters. After a cursory review of current technology in gas treating and sulfur recovery, this paper summarizes applicable new technology in this area developed by the author's company and others including advances in H2S scavenging, small-scale sulfur recovery up to 15-20 TPD and large-scale gas treating for high acid gas concentration applications.
Gas treating and sulfur recovery from gas production in the Permian basin is not an insignificant contributor to total cost of production in the area. Much of the oil production in this region is with the use of CO2 flooding which carries with it attendant costs of CO2 recovery and reinjection. The presence of H2S in the gas complicates the recovery and reinjection of CO2 and adds to the cost. GRI and others have been developing new treating and sulfur recovery technology and software and the state-of-the-art with respect to these new developments is summarized herein.
GRI's gas composition databasei was used to examine the amount of gas needing treatment for high CO2 and/or H2S. The database uses the following 25 basins to define the aggregate Permian Basin statistics: Abo, Atoka, Canyon, Cisco, Clear Fork, Delaware, Devonian, Ellenburger, Fusselman, Grayburg, Judkins, Mckee, McKnight, Montoya, Morrow, Pennsylvanian, Queen, San Andres, Silurian, Strawn, Tubb, Wichita Albany, Wolfcamp, and Yates. There is an additional basin termed Other to aggregate any additional resources required. Defining several categories of subquality production, we have 300 Bcf of annual production (1996) where H2S is > 4ppmv, 90 Bcf where CO 2 > 2% by vol, and 179 Bcf where both of these conditions prevail at the same time. There is some additional production, around 100 Bcf, where the nitrogen level is in excess of 4%. Presumably, this latter gas is sold via blending with high BTU gas. EOR associated gas production is not included in these estimates. The total of ~700 Bcf represents on the order of 3% of U.S. current production. If we estimate the cost of treating and sulfur recovery of this production at 10¢ per Mscf, then we have a cumulative Permian basin-wide cost on the order of $70 million. It is clear that reduced costs for these operations are of some interest to producers, a fact that has not gone unnoticed by technology developers in this field.
The area's swift demographic and economic growth in the past decades has resulted in a rapidly expanding electricity grid Generally, H 2 S removal from natural gas with subsequent The demand for electricity is also outpacing the natural gas sulfur recovery is performed in amine and Claus plants. These processes are considered economical for quantities The USD 10 billion Shah field gas project in UAE, the of sulfur greater than 50 ton/day. In a paper presented at largest sour gas project in the world, is nearing completion ADIPEC, Hauwert (2014) reviewed processes for small-scale with approximately 98% of the development done. The sulfur recovery from sour associated gas, including liquid field was discovered in the 1960s, but was not considered reduction/oxidation (redox), Thiopaq O&G, CrystaSulf, technically feasible to develop. He described the processes as Abu Dhabi Gas Development Company (Al Hosn being applicable for removal of sulfur quantities ranging from Gas), a joint venture partnership between ADNOC and 1 ton per day to 20 tons per day, for direct treatment of highpressure Occidental Petroleum, aims to extract 1 billion scf/D of well natural gas and low-pressure associated petroleum fluid containing 23% H 2 S and 10% CO 2 from the Shah field.