Systems and methods for controlling a natural gas production system in an upset scenario, and/or during startup of turbo-expander system are disclosed. In one embodiment, a method of operating a Joule-Thomson valve of a natural gas production system includes determining an upset event within the natural gas production system, obtaining a flow rate through at least one expander prior to the upset event, and calculating, based on the flow rate, a percent opening of the Joule-Thomson valve. The method further includes opening the Joule-Thomson valve to the percent opening, controlling the Joule-Thomson valve by a PID controller in a set point tracking mode for a period of time, and controlling the Joule-Thomson valve by the PID controller in an automatic mode.

A heavies removal heat exchanger cools at least a portion of a feed gas stream. A scrubbing section receives the cooled main feed gas stream. A stripping section receives a fluid stream from the scrubbing section. A stripping gas feed expansion device receives a portion of the feed gas stream and is in fluid communication with the stripping section. A side draw vapor line receives a vapor stream from the vapor outlet of the stripping section and is in fluid communication with a reflux stream cooling passage of the heavies removal heat exchanger. A reflux separation device receives fluid from the heavies removal heat exchanger and has a liquid outlet and a vapor outlet. The liquid outlet is in fluid communication with the scrubbing section. A return vapor expansion device receives a vapor stream from the scrubbing section and directs a cooled vapor stream to a return vapor stream warming passage of the heavies removal heat exchanger. The reflux separation device vapor outlet is configured so that fluid passing therethrough joins with fluid that has exited the return vapor expansion device either before or after the fluid that has exited the return vapor expansion device flows through the return vapor stream warming passage of the heavies removal heat exchanger.

Systems and methods are provided for increasing the efficiency of liquefied natural gas production and heavy hydrocarbon distillation. Air within an LNG production facility can be utilized as a heat source to provide heat to HHC liquid for distillation in a HHC distillation system. The mechanism of heat transfer from the air can be natural convection. Heat provided by natural gas, or compressed natural gas, can be also used for HHC distillation. Various other liquids can further be used to transfer heat to HHC liquid for distillation.

A method for improved operation of a natural gas liquids stabilizer column, particularly a small-scale, is provided. The method can include the steps of: introducing a first feed stream comprising heavy hydrocarbons and natural gas to a stabilizer column to produce a top gas and a bottoms liquid, wherein the top gas has a higher concentration of natural gas as compared to the first feed stream, and the bottoms liquid has a higher concentration of heavy hydrocarbons as compared to the first feed stream; introducing a second feed stream into the stabilizer column, wherein the second feed stream has a higher concentration of natural gas as compared to the first feed stream, wherein the second feed stream is at a warmer temperature than the first feed stream when introduced into the stabilizer column, wherein the second feed stream is a gaseous stream; withdrawing the top gas from a top portion of the stabilizer column; withdrawing the bottoms liquid from a bottom portion of the stabilizer column; and sending at least a portion of the bottoms liquid to a liquid storage tank.

A method for an improved integration of refrigeration into conventional natural gas processing plants which use propane or similar hydrocarbon refrigerants either to supplement cooling by turbo-expanders or as the sole source of refrigeration.

A method to recover olefins and C.sub.2.sup.+ fractions from refineries gas streams. The traditional recovery methods employed at refineries are absorption with solvents and cryogenic technology using compression and expansion aided by external refrigeration systems. In contrast to known methods, there is provided first a pre-cooling heat exchanger on a feed line feeding the gas stream to a in-line mixer, secondly by injecting and mixing a stream of LNG to condense the C.sub.2.sup.+ fractions upstream of the fractionator. The temperature of the gas stream entering the fractionator is monitored downstream of the in-line mixer. A LNG stream is temperature controlled to flow through the injection inlet and mix with the feed gas at a temperature which results in the condensation of the C.sub.2.sup.+ fractions before entering the fractionator. A LNG reflux stream is temperature controlled to maintain fractionator overhead temperature. The fractionator bottoms temperature is controlled by a circulating reboiler stream.

A system includes a first separator that separates water from a fluid material. The water settles on the bottom of the water knock-out tank. The system includes multiple compressors to boost the pressure of the fluid material. The system includes a second separator that separates condensate from the fluid material. The system includes a mixing pipe that mixes glycol with the fluid material and a first heat exchanger that cools the mixed fluid material and glycol. The system includes a third separator that separates gaseous components and liquid components of the mixed fluid material and glycol and a fourth separator that separates the liquid components of the mixed fluid material and glycol. The system includes a fractional distillation column that heats a first liquid from the fourth separator, gasifying a first portion of the first liquid. A second portion of the first liquid remains liquid and is natural gas liquids.

Processes and apparatuses for recovering a high purity carbon dioxide stream. A first separation zone that may include a cryogenic fractionation column provides the high-purity CO.sub.2 stream. A vapor stream from the cryogenic fractionation column is passed to a second separation zone to separate the CO.sub.2 from the other components. The second separation zone may include a pressure swing adsorption unit or a solvent separation unit. The second separation zone provides a hydrogen enriched gas stream that may be used in a gas turbine. The second stream from the second separation zone includes carbon dioxide and, after a pressure increase in a compressor, may be recycled to the first separation zone.

A process for liquefying a natural gas feed stream including cooling a feed gas stream to obtain a liquefied natural gas stream; introducing the liquefied natural gas stream into a deazotization column to produce a liquefied natural gas stream and a nitrogen-enriched vapor stream; at least partially condensing at least part of the nitrogen-enriched vapor stream to produce a two-phase stream; introducing the two-phase stream into a phase-separating vessel to produce a first liquid stream and a first nitrogen-enriched gas stream; introducing at least part of the nitrogen-enriched gas stream into a distillation column thereby producing a second nitrogen-enriched stream containing less than 1 mol % of methane and a second liquid stream containing less than 10 mol % of nitrogen; wherein at least part of the liquefied natural gas stream is used to cool the at least part of the nitrogen-enriched vapor stream in said heat exchanger.

A method and system for controlling the nitrogen concentration in an LNG product and fuel from flash gas within preferred ranges. A cooled LNG stream is separated into a nitrogen-enriched vapor stream, a fuel stream, and an LNG product stream using a plurality of phase separating devices, such as flash drum or rectifying column. A portion of the vapor stream is recycled to the rectifying column as reflux. A portion of a stream having a higher concentration of nitrogen is combined with the fuel stream to maintain the fuel stream within a desired nitrogen concentration range.