Gas pre-treatment and their impact on liquefaction processes

Conference · Thu Jul 01 04:00:00 EDT 1999

OSTI ID:20000919

Klinkenbijl, J M; Dillion, M L; Heyman, E C

Natural gas generally requires removal of H{sub 2}S, CO{sub 2}, COS, organic sulfur compounds, mercury and water prior to liquefaction in order to meet product specifications, avoid blockages and to prevent damage to process equipment. The cost of pre-treatment is dependent on the type and concentrations of the contaminants in the natural gas. Most of the operational base load LNG plants process feed gas with only low concentrations of CO{sub 2}, mercury and water as contaminants. This type of gas requires the minimum of treating, often comprising of a CO{sub 2} removal unit, molecular sieves for drying and a carbon bed for mercury removal. The Shell sulfinol process is the most widely applied acid gas removal process, serving some 40% of the installed base load LNG capacity, and has proven to be very reliable and cost effective. If substantial quantities of H{sub 2}S are present in the feed, a sulfur recovery unit is required as well. When mercaptans are also present in gas feed, the Shell Sulfinol process is strongly preferred, Almost the automatic choice for as the acid gas removal step, since it combines total CO{sub 2} and H{sub 2}S removal with mercaptan removal up to 97%. Formulated methyl diethanol amine (MDEA) solvents have a comparable capital cost to Sulfinol, but lack the mercaptan removal capabilities. There is one exception, the Flexsorb formulation (from Exxon) which also contains sulfolane. Later revamp of a gas pre-treatment unit from limited mercaptan handling capability to significant mercaptan handling capability can also elegantly be done using an integrated Sulfinol based concept. Whereas the capital cost for dehydration and mercury removal depend mainly on the natural gas throughput, the relative capital investment for acid gas removal treating in a LNG plant increases significantly with increasing CO{sub 2} content., At 2% mol CO{sub 2} the acid gas unit represents from 6% of the processing equipment cost at 2% mol CO{sub 2} but at 14% mol CO{sub 2} it represents 15% of the processing equipment cost. The capital cost for dehydration and mercury removal depend mainly on the natural gas throughput. New developments such as membrane technologies are starting to be considered as an option for bulk removal of CO{sub 2} but solvent absorption remains the only cost effective treatment process for gas to meet LNG specifications. Further developments may change this in the future.

• Research Organization: Shell International Oil Products, Amsterdam (NL)
• OSTI ID: 20000919
• Report Number(s): CONF-990331--
• Country of Publication: United States
• Language: English

Related Subjects

03 NATURAL GAS
CAPITALIZED COST
DEHYDRATION
DEMETALLIZATION
DESULFURIZATION
LNG PLANTS
MATERIALS RECOVERY
MERCURY
NATURAL GAS
SULFINOL PROCESS
SULFUR