Q. Zane Rhodes II, President, Zachary Browne, and Steven Cuffle, Newpoint Gas, LLC, USA, detail utilising amine plants and catalytic oxygen removal for LNG pretreatment.
In 1999, Newpoint Gas, LLC installed its first natural gas treating plant, and has been designing, building, installing, and operating gas treating and purification plants since. Two technologies that benefit the LNG industry are amine treating and catalytic oxygen removal. Amine plants remove hydrogen sulfide (H2S) and carbon dioxide (CO2) from gas streams utilising a regenerable amine solvent. The catalyst oxygen removal system converts oxygen to CO2 and water using catalytic combustion. These contaminants cause corrosion issues, off spec product, and can also lead to solids formation in cold processes such as LNG liquefaction.
Efficient utilisation of these pretreatments can expand the inlet gas streams that are appropriate for LNG facilities, which can reduce the feedstock costs and allow biogas to be used for carbon-neutral LNG. Typically, LNG feedstock requirements are less than 4 ppmv H2S, 50 ppmv CO2, and less than 10 ppmv oxygen (O2). Reliable, modular pretreatment systems can significantly increase profitability, viability, and sustainability of LNG systems by eliminating contaminants from feedstock, lowering feed-stock costs, and allowing biogas to be used for carbon-neutral LNG.
Amine treating uses an aqueous solution of amine to remove H2S and CO2 from a gas stream. This technology is applicable for natural gas, biogas, and even carbon capture from flue gas streams. A variety of amine solutions are available that are chosen based on pressure, composition, contaminants, and outlet requirements.
In Figure 1, a typical amine system process flow diagram (PFD) is shown. Inlet gas enters the bottom section of the amine contactor, where it contacts with sufficient amine solution to meet the required outlet CO2 specifications (typically less than 50 ppmv). The gas exiting the top of the amine contactor(s) is routed to the sweet gas cooler and any condensed water is removed in the overhead gas scrubber. Inlet filter separation/coalescing is provided upstream of the amine contactor.
The rich amine will enter the amine regeneration system, feeding into the amine flash tank. The amine flash tank is designed to provide 10 mins. of residence time and includes a hydrocarbon collection sump. Any flashed vapours from the amine will be pressure controlled and routed to the skid edge for disposal.
The liquid amine from the amine flash tank flows through a 100 gpm capacity charcoal filter and then through a 100% capacity sock filter before going to the lean/rich exchanger, where the rich amine is heated to approximately 210°F. A level control valve is located on the rich amine stream, downstream of the lean/rich exchanger, to control the level in the amine flash tank.
The rich amine and reflux stream combine to feed the top stage of the amine still. The amine still is also packed with structured packing. An air-cooled heat exchanger is provided for the reflux condenser and a horizontal vessel serves as the reflux accumulator. The acid gas vapours off the reflux accumulator will be pressure controlled and routed to the edge of the skid for final disposal. Two reflux pumps (one operating and one stand-by) are also provided. The amine still reboiler utilises a horizontal thermosiphon design, with a TEMA Type BEM exchanger. Heat for the amine still reboiler will typically be provided by 50 psig, saturated steam, or hot oil.
The lean amine from the bottom of the amine still flows into an equalised lean amine surge tank. This is a horizontal vessel designed to provide five minutes of surge capacity. The lean amine leaves this vessel and flows through the shell side of the lean/rich exchanger and is cooled to approximately 215°F.
The lean amine out of the lean/rich exchanger is then pumped to about 60 psig in one of the two amine booster pumps. From the amine booster pumps, the lean amine is cooled to 120°F in the lean amine cooler. The lean amine cooler is a shell and tube exchanger that uses cooling water.
The lean amine from the lean amine cooler is then fed to the amine circulation pumps. These pumps (one operating, one stand-by) will pump the amine to a pressure approximately 50 psi above that of the entering gas stream, for delivery to the top of the amine contactor(s).
O2 can be present in inlet gas in addition to CO2 and H2S.The oxygen poses several problems to plant facilities, and removal of O2 is an important part of natural gas purification. Oxygen is corrosive and can reduce plant life and affect downstream pro-cesses. Oxygen is also included in LNG product specifications so must be removed to very low levels.
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