Processes for purifying and liquefying natural gas in conjunction and integration with cryogenic processing natural gas to recover natural gas liquids (NGL) is disclosed. In the process, the natural gas stream to be purified and liquefied is taken from top outlet stream of demethanizer in the cryogenic NGL recovery plant, first purified and then cooled under moderate pressure to condense it as a liquefied natural gas (LNG) product stream. Some of the cooling required for the demethanizer reflux stream is provided by natural gas liquefaction section before supplied to top of the column to serve as reflux. The top outlet stream from the demethanizer preferentially contains up to 3 mole percent of CO.sub.2 and the majority of methane and small portion of any hydrocarbon heavier than methane, a split portion of this stream is taken and routed to cryogenic CO.sub.2 removal section, in which a molecular sieve that forms a physical adsorption column is used to extract pure CO.sub.2 as a product stream, then purified stream is routed to the liquefaction section where only two stages of coil-wound exchangers with a Semi-C3-MR cycle are used to liquefy natural gas. This present invention process is suited for LNG production in small-scale. This zeolite-based small-scale LNG process can be integrated with the design of any new natural gas facility and the technology can also be retrofitted to existing natural gas liquid (NGL) recovery plants, allowing for co-production of LNG and CO.sub.2 with high purity.

The system is provided for generating a mixed methane gas feed stream using at least one source of biogas and an alternate source of methane gas. The system includes a biogas subsystem, a control device for the methane gas from the at least one alternate source of methane gas, and a vertically-extending gas mixing vessel. A method of controlling a methane gas mass flow rate of a mixed methane gas feed stream is also disclosed. The proposed concept is particularly well adapted for situations where an uninterrupted and relatively constant input of methane gas is required to ensure an optimum operation of, for instance, a LMG production plant.

A natural gas liquefaction vessel including an increased deadweight tonnage, as compared to a liquefied natural gas carrier (LNGC) of a comparably-sized ship, is achieved by reducing the LNGC's cargo capacity. This difference creates room on the port and starboard sides of cargo tanks to increase the size of the adjacent wing tanks. The increased size of the wing tanks occupy the space created by the reduced cargo tank size of the vessel and may support a larger upper trunk deck. The ballast wing tanks and smaller cargo tanks increase the deadweight available. With this approach, the larger upper trunk deck of the vessel is able to support an efficient floating liquefaction plant that improves the LNG value chain because it is capable of producing 2.0-3.0 MTPA in the footprint of a standard vessel hull, such as for example a Q-Max hull.

The method is carried out for continuously producing a liquefied methane gas (LMG) from a pressurized mixed methane gas feed stream. It is particularly well adapted for use in relatively small LMG distributed production plant, for instance those ranging from 400 to 15,000 MT per year, and/or when the mixed methane gas feed stream has a wide range of nitrogen-content proportions, including nitrogen being substantially absent. The proposed concept can also be very useful in the design of medium-scale and/or large-size plants, including ones where the nitrogen content always remains above a certain threshold. The methods and arrangements proposed herein can mitigate losses of methane gas when venting nitrogen, for instance in the atmosphere.

Disclosed is a method of discharging lubricant oil from a BOG reliquefaction system configured to reliquefy BOG by compressing the BOG by a compressor, cooling the compressed BOG through heat exchange with non-compressed BOG by a heat exchanger, and reducing a pressure of fluid cooled through heat exchange by a pressure reducer. In the lubricant oil discharge method, the compressor comprises at least one oil-lubrication type cylinder and it is determined that it is time to discharge condensed or solidified lubricant oil, if at least one of preset conditions is satisfied.

Provided is a production facility for liquefied hydrogen and a liquefied natural gas from a natural gas, including: a first heat exchanger configured to cool a hydrogen gas through heat exchange between the hydrogen gas and a mixed refrigerant for liquefying a natural gas containing a plurality of kinds of refrigerants selected from the group consisting of methane, ethane, propane, and nitrogen; a second heat exchanger configured to cool the mixed refrigerant through heat exchange between the mixed refrigerant and propane; and a third heat exchanger configured to cool the hydrogen gas through heat exchange between the hydrogen gas and a refrigerant containing hydrogen or helium, wherein the first heat exchanger has a precooling temperature of from 100 C. to 160 C.

A method for separating a vapor from a carrier gas is disclosed. A hydrocyclone is provided with one or more nozzles on the wall of the hydrocyclone. A cryogenic liquid is provided to the tangential feed inlet at a velocity that induces a tangential flow and a cyclone vortex in the hydrocyclone. The carrier gas is injected into the hydrocyclone through the one or more nozzles. The vapor dissolves, condenses, desublimates, or a combination thereof, forming a vapor-depleted carrier gas and a vapor-enriched cryogenic liquid. The vapor-depleted gas is drawn through the vortex finder while the vapor-enriched cryogenic liquid is drawn through the apex nozzle outlet. In this manner, the vapor is removed from the carrier gas.

A method and apparatus for removing benzene from a lean natural gas feed is provided. The method and apparatus are capable of removing benzene from lean natural gas that is predominantly composed of methane and contains very little heavier hydrocarbon components.

The invention relates to a method and system of preparing a lean methane-containing gas stream (22), comprising: feeding a hydrocarbon feed stream (10) into a separator (100); withdrawing from the separator (100) a liquid bottom stream (12); passing the liquid bottom stream (12) to a stabilizer column (200); withdrawing from the stabilizer column (200) a stabilized condensate stream (13) enriched in pentane, withdrawing from the stabilizer column (200) a stabilizer overhead stream (14) enriched in ethane, propane and butane; splitting the stabilizer overhead stream (14) according to a split ratio into a main stream portion (15) and a slip stream portion (16), passing the slip stream portion (16) to a fractionation unit (300) to obtain an ethane enriched stream (17) and a bottom stream enriched in propane and butane (18).

A method for removing heavy hydrocarbons from a feed gas by: feeding, into an absorber, a top reflux stream and a second reflux stream below the top reflux stream, wherein the absorber produces an absorber bottom product stream and an absorber overhead product stream; depressurizing and feeding the absorber bottom product stream to a stripper to produce a stripper bottom product stream and a stripper overhead product stream; cooling and feeding a portion of the absorber overhead product stream back to the absorber as the top reflux stream; and pressurizing and feeding the stripper overhead stream back to the absorber as the second reflux stream. A system for carrying out the method is also provided.