Operating Experience With SuperclausTM-99 Tail Gas Cleanup Unit

Abstract

Abstract In 1993, Midgard Energy Company started up a 200 MM scfd natural gas processing plant near Sunray, Texas. The sulfur emissions controls included an enhanced three stage Claus sulfur recovery unit, designed to achieve initial sulfur recovery efficiencies of 97.2%. After a careful post-construction BACT analysis, a Superclaus-99 tail gas cleanup unit was added in 1994 to achieve 98.5% recovery efficiencies. Introduction Midgard Energy Corporation constructed a 200 million (MM) standard cubic feet per day at 60 F (scfd) gas processing plant near Sunray, Texas in the Texas Panhandle which started up in the first half of 1993. This dual train facility was designed to treat both sweet Ochiltree gas, as well as sour West Panhandle and Texas Hugoton field gasses. The facility included a nominal 14 long tons per day (LTPD) sulfur recovery unit (SRU). This facility was built under a Construction Permit issued by the Texas Air Control Board (TACB) [now the Texas Natural Resources Conservation Commission (TNRCC)] in late 1991. This permit required the facility to initially meet a sulfur control efficiency of 97.2%, monitored continuously, after start-up. The permit required that an additional best available control technology (BACT) review be performed and submitted to the TACB within six months, with the objective being to further reduce these emissions. Whatever tail gas controls were identified in this second BACT review would then have to be constructed and started up within 18 months. As a consequence of this post-start-up BACT review, a Superclaus-99 tail gas cleanup unit was added to the sulfur recovery facility during early 1994. This plant was only the second U.S. natural gas processing plant to operate a Superclaus-99 unit. After the startup of the tail gas cleanup unit (TGCU), the minimum acceptable sulfur recovery efficiency limit of 97.2% was increased to 98.5%. This requirement was based on the facility's overall sulfur control efficiency. Because of the H2S that would bypass the sulfur recovery unit in the amine system slip streams and vents, the effective sulfur plant control efficiency limit became 98.7%. While these control efficiency limits are considerably higher than were in place at any other similar gas plant in Texas, the technologies employed have allowed both required control efficiencies to be met. This analysis focuses on the plant's sulfur control systems and their performance histories, and will consequently also focus on the West Panhandle processing train. Facility Description As noted above, the gas processing plant was designed to treat 200 MM scfd of inlet gas. Two separate gas streams are processed: 80 MM scfd of sour oil field gas processed in the West Panhandle gas train, and 120 MM scfd of sweet gas processed in the Ochiltree gas train. Pipeline condensate processing is also included, with the plant generating four products: Y-grade natural gas liquids, residue gas, crude helium, and elemental sulfur. This facility, including the original Claus SRU, was designed by ABB Randall Corporation of Houston, Texas and has been fully described in the SPE 27923. The oil field gas enters the facility at a nominal rate of up to 80 MM scfd and variably contains up to 4500 ppmv of H2S. The permit for this facility allows 80 MM scfd to be exceeded, provided the sulfur content of this gas treated is proportionately smaller and other permit terms are met. This inlet raw gas is combined with the condensate stabilizer overhead stream and is compressed to 650 psig using reciprocating inlet gas compressors. The gas is then cooled to 120 F using inlet gas coolers before entering the amine gas treating system. The first amine gas contactor, which uses a selective MDEA-based solvent, removes H2S to a level of 4 ppmv (or less) in the gas, while recovering less than 50% of the CO2 contained in the inlet gas. The resulting rich liquid amine stream is sent to the first amine regeneration system, where the H2S and CO2 are stripped out of the amine. The resulting acid gas stream from the amine still reflux accumulator contains between 60 and 67 percent H2S, depending on the amount of CO2 that was present in the inlet gas stream. This acid gas is then sent to the SRU. The gas out of the first amine-gas contactor is then routed to the second amine-gas contactor, which uses DEA as the amine. This contactor removes the final traces of H2S (to 2 ppmv or less) and all remaining CO2 (to 50 ppmv or less) from the inlet gas stream. P. 247^