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Integrated Technology in Processing High Co2, High INTEGRATED TECHNOLOGY IN PROCESSING HIGH CO2, HIGH N2 OFFSHORE GAS FOR LNG PRODUCTION Authors: John Mak, Tang Bin, Curt Graham Affiliate: Fluor Energy & Chemicals Abstract In many offshore gas reservoirs, the produced gas is a lean gas, but often has high CO2 content ranging from 30% to 60%, with nitrogen content higher than 5%. These gases are left untapped due to their low heating values, and difficulties in treating to meet the sales gas specification. Locating in an offshore environment adds complexity to the processing facility, due to space constraints, stringent safety requirements, limited utility supply, and limited staffing for operation and maintenance. Even after the gas is treated for CO2 removal, transportation to onshore requires long distant pipe lines. The innovation disclosed here is a Fluor Solvent process that is specifically designed for offshore installation for CO2 removal. The Fluor Solvent process is proven to be an economic process for high CO2 gas removal. It is a non-heated process that can eliminate fuel gas consumption, avoiding greenhouse emissions. The process utilizes the potential energy in CO2 to generate refrigeration, thus minimizing the power consumption in CO2 removal. For LNG production for high nitrogen gas, the treated gas must be processed in a nitrogen rejection unit to reduce its nitrogen content to less than 1 mole%. The integrated process utilizes the rejected nitrogen from the nitrogen rejection unit as a stripping gas in the Fluor Solvent unit, which can treat the feed gas to below 200 ppmv CO2, further reducing the CO2 removal requirement for LNG liquefaction. Page 1 of 13 John Mak, Fluor Energy & Chemicals Introduction Offshore gases, such as from South China Sea and Pre-salt regions are high in CO2 content and N2 content, which are costly to develop with conventional treating technologies. Even when these gases are treated to meet pipeline specifications, the pipeline cost for transporting to on-shore facilities is an additional cost. One of the methods is to liquefy the treated gas such that it can be transported by ship, avoiding the high cost of undersea pipelines. To develop these untapped resources, innovative methods on treating these high CO2 gases to meet LNG specifications are necessary. An innovative process was developed using the Fluor Solvent process which has been specifically designed for offshore operation. The integrated process would avoid the use of external heating, and cooling, producing a product gas with minimum CO2 and nitrogen, suitable for LNG liquefaction. Offshore Design Considerations From a design and operation standpoint, an offshore gas treating facility requires a different focus than an onshore facility. Daily routine operations that are taken for granted onshore can present serious problems offshore. Operationally, the focus offshore needs to be on safety, simplicity, and reliability. Offshore operation must consider environmental requirements, corrosion mitigation, and operational flexibility. The facilities are limited in staffing, which makes monitoring and controlling a complex process difficult. Equipment modifications are restricted and are difficult to accommodate higher CO2 content if necessary. From a construction and cost standpoint, an offshore treating plant should have a minimum equipment count. This usually results in a smaller platform footprint and less weight for the jacket to support. Eliminating fired equipment reduces equipment safety spacing requirements and makes the platform footprint smaller. Eliminating a steam or heat medium system, or water supply system reduces the total equipment count and simplifies plant operation. Treating Options For small gas plants, membrane separation has been installed offshore for high CO2 removal. These units are compact and can be installed at a lower cost than conventional process. However, membrane separators are designed for bulk acid gas removal, and their hydrocarbon loss is relatively high. The membrane permeate contains substantial amounts of hydrocarbons, which must be recycled or reinjected to formation to avoid releases of greenhouse gases. There is also no economy of scale with membrane units. Multiple identical units are required to handle higher CO2 content or larger flow rates. When hydrocarbon recovery is required, membrane separation is not a good choice, especially for larger plants. Common solvent treating processes are the amine treating and the physical solvent treating technologies. Amine treating is typically used for low CO2 content gases. Amine unit requires heating with steam or hot oil and cooling with ambient air or cooling water for amine regeneration. The fuel consumption and water usage by the amine units are operational and environmental issues for offshore operation. Hence, amine process is not suitable for treating high CO2 gas for offshore operation. Page 2 of 13 Physical Solvents Physical solvent uses less energy than amine processes. The solvent can be regenerated by pressure letdown, and can reduce heating consumption. The Fluor Solvent process uses propylene carbonate (PC) as the physical solvent proven for treating high CO2 gases. The process is competitive to amine treating when the partial pressure of the CO2 content is higher than 50 psi. Physical solvents have an advantage over chemical solvents when treating high CO2 partial pressure gases in that the physical solvent gas holding capacity (volume of CO2 per unit of solvent circulation) increases proportionally with the CO2 partial pressure according to Henry’s law. This is different from chemical solvent, such as amines, which loading is solely determined by chemical equilibrium, independently of CO2 partial pressure. These two relationships can be illustrated in Figure 1. Physical Solvent Figure 1 – Solvent Rich Loading- Physical Solvent versus Amine The Fluor Solvent Process, which was originally commercialized by Fluor in the early 1960s, uses propylene carbonate (PC) as the solvent for the removal of CO2 and H2S from natural gas and synthesis gas streams. Propylene carbonate, C4H6O3, is a polar solvent that has a high affinity for acid gases. For cases where the CO2 content that changes over time, the Fluor process unit can be operated with the same circulation, as the rich loading would increase with the higher CO2 partial pressure. This operation has been demonstrated in the earlier Fluor Solvent plants described in the following section. On the contrary, amine units would require higher amine circulation with additional trains to handle the higher acid gas contents. Most of the equipment in the amine unit is constructed of stainless steel to avoid wet CO2 corrosion. The Fluor Solvent process operates under a dry environment, and there are no water makeup or corrosion problems with the use of PC. The Fluor Solvent system is constructed of carbon steel. The PC is also a non-toxic and non-foaming solvent. The following table is a comparison of a promoted MDEA unit to the Fluor Solvent unit for high CO2 gases. Page 3 of 13 Table 1 – Fluor Solvent vs promoted MDEA for High CO2 Gases Fluor Solvent Promoted MDEA Equipment Count Lower Higher Operational Complexity Lower Higher Stainless Steel Materials No Yes Stress Relieving of Carbon Steel No Yes Fired Heat Required No Yes Modification for Increasing CO2 in feed Minimal Substantial Vulnerable to Solvent Foaming No Yes Winterization Required No Yes Solvent Concentration Monitoring No Yes Non-Toxic and Biodegradable Solvent Yes No Produces Dry, Cold Treated Gas Yes No Hydrocarbon Content of Acid Gas Higher Lower Feed Gas Shrinkage Lower Higher Net Sales Gas Delivery Higher Lower There are other physical solvents that can be used to remove CO2. For example when compared to DMPEG (dimethylether of polyethylene glycol), PC has a higher affinity towards CO2 and a low solubility of hydrocarbons, and can operate at as low as -20°F. Lower solvent temperature would increase the rich solvent loading, which lowers solvent circulation and reduces hydrocarbon losses. Regeneration of DMPEG would require external heating while the Fluor process is a non-heated process. Fluor Solvent Plants PC plants can be designed to operate under ambient temperature, which are common in China for ammonia production. Ambient PC plant requires higher solvent circulation which would also increase co-absorb of hydrocarbons. The Fluor Solvent design is configured to operate under mildly refrigerated temperatures, to reduce solvent circulation and hydrocarbon losses. Two of the earliest Fluor Solvent plants are described in the following. Terrell County Natural Gas Plant The Terrell County Fluor Solvent plant, located in Terrell County, Texas, was built in 1960s. The plant was designed to treat natural gas to meet 2 mole% CO2 specifications. The original plant was designed to treat 220 MMscfd feed gas with 53 mole% CO2 and contains about 70 ppmv of H2S. The low pressure feed gas was compressed to about 900 psig pressure to feed the absorber. Currently, the gas plant is supplied from a different source, and is processing about 120 MMscfd of feed gas with 36 mole% CO2 at 650 psig. Page 4 of 13 The Fluor process uses four flash stages for solvent regeneration, with the last stage operating under vacuum pressure, as shown in Figure 2. A small amount of refrigeration is used on the rich solvent to lower the solvent temperature. A hydrocarbon re-absorber was used to reduce the hydrocarbon content in the CO2 vent gas to meet the emissions requirements of 2%. While the non-heated process can reduce the CO2 content to 2 mole% to meet specifications, the process, being a non-heated process, can only reduce the H2S content from 70 ppmv to about 6 ppmv. Subsequently, a sulfur scavenger bed was added on the treated gas to meet the 4 ppmv pipeline gas specification Terrell County Fluor Solvent Plant The process unit has been successfully operating with the same equipment for over 50 years. Re-absorber 650 psig Feed Gas 180 psig Absorber 27°F MP Vacuum HP Drum Drum LP Drum Drum 60°F Refrig Refrig Cond.
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