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 CO2 > 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.