Systems and methods for crude oil separations including degassing, dewatering, desalting, and stabilization. One method includes separating crude oil into a crude oil off-gas and a partially degassed crude oil output; compressing the crude oil off-gas; applying the compressed crude oil off-gas for indirect heating through reboilers of the partially degassed crude oil output; and directly mixing with the crude oil a compressed atmospheric pressure gas. In some embodiments, multiple reboilers are used. In some embodiments, heat exchangers are used. Aftercoolers are used after the compressor to cool the gas; knockout drums are used after the coolers to separate liquids.

An ammonia stripper (32) and method for stripping ammonia from ammonia-containing water is described, comprising an ammonia-containing water inlet (56), a steam inlet (70), and a forced air inlet (82), and an ammonia-containing gas outlet (36) and a wastewater outlet (72). The steam and air contact the ammonia-containing water in counter-flow to release ammonia from the ammonia-containing water. The ammonia stripper further comprises a steam and air mixing duct (200) shaped to create turbulence in the steam and air flow to promote mixing of the steam and air flow prior to contacting the ammonia-containing water. Also described is an ammonia stripper and method comprising a precipitation unit for precipitating solids from the ammonia-containing water prior to the inlet, and an ammonia stripper and method comprising a steam flash vessel for generating steam from the wastewater produced by the ammonia stripper for recycling into the ammonia stripper. Further described are thermal destructors for destroying ammonia in ammonia-containing gas from an ammonia stripper; and a method of removing ammonia from ammonia-containing gas wherein ammonia-containing gas is drawn from the ammonia-containing gas outlet and returned into the ammonia stripper to mix with the forced air entering the ammonia stripper.

A production stream from a well formed in a subterranean formation is flowed to a gas oil separation unit. The gas oil separation unit includes a separator vessel. The production stream includes an emulsion including an oil phase and an aqueous phase. Steam is mixed with the production stream prior to the production stream entering the separator vessel. Phases of the production stream are separated by the separator vessel to produce a vapor stream, an aqueous stream, and an oil stream.

A separator system and method may provide a four-way separator that may separate a material and remove a hazardous material. The hazardous material may include gas and sand that may be removed by the four-way separator. The separator system and method may further provide a main unit that may include three chambers or recirculation hoppers, an auger sand extractor, and a strap tank. The separator system and method may provide a faster rig-up time and may be exclusively driven by hydraulics.

A system and method for analyzing a gas in a drilling fluid involves a degasser operable to separate the gas from the drilling fluid. A gas analyzer in fluid communication with the degasser receives a sample of the separated gas and determines a property of the gas. A controller in communication with the gas analyzer automates the operation of the gas analyzer by adjusting a parameter of the separated gas sample as the gas sample is supplied to the gas analyzer.

Provided are degasification devices and methods of degasifying a liquid. Methods of degasifying a liquid can include filling a liquid chamber with a liquid; increasing an internal volume of the liquid chamber to generate a vacuum within the liquid chamber; applying one or more pressure waves to the liquid in the liquid chamber to accelerate the formation of a plurality of gas bubbles which rise to the surface of the liquid and release gas within the plurality of gas bubbles into a space above the liquid in the liquid chamber; and decreasing the internal volume of the liquid chamber to force the gas through a vapor outlet of the liquid chamber, wherein a degassed liquid remains in the liquid chamber.

A yield estimation device for a low-yield shale gas reservoir includes: a separation tank, a pulse gas detector, and a methane concentration detector; wherein a liquid inlet is provided at an upper portion of the separation tank; an exhaust pipe is provided on a top of the separation tank, and the pulse gas detector is installed at a middle section of the exhaust pipe; the methane concentration detector is installed at a tail end of the exhaust; a valve is installed in a liquid outlet; a float is arranged in the separation tank, which is connected to the valve through a telescopic float rod. A yield estimation method includes steps of: inputting flowback fluid into the separation tank through the liquid inlet; discharging the air in the separation tank; performing gas-liquid separation; detecting and displaying the shale gas in real time with the pulse gas detector.

A method for recovering a distillable, anhydrous methane-sulfonic acid (MSA) liquid phase from an anhydrous 2-phase gas-liquid mixture wherein the anhydrous 2-phase gas-liquid mixture is generated by sulfonating methane (CH.sub.4) with sulfur trioxide (SO.sub.3) in an MSA-forming reactor, or reactor system, according to a radical chain reaction wherein the method comprises (i) separating the gas phase from the liquid phase, (ii) passing the separated liquid phase into a stripping column, and (iii) recovering the stripped anhydrous liquid phase.

An apparatus and method for flow management and CO.sub.2-recovery from a CO.sub.2 containing hydrocarbon flow stream, such as a post CO.sub.2-stimulation flowback stream. The apparatus including a flow control zone, a gas separation zone, a pretreatment zone, and a CO.sub.2-capture zone. The CO.sub.2-capture zone is in fluid communication with the pretreatment zone to provide CO.sub.2-capture from a pretreated flowback gas stream and output a captured CO.sub.2-flow stream. The CO.sub.2-capture zone includes a first CO.sub.2-enricher and at least one additional CO.sub.2 enricher disposed downstream of the first CO.sub.2 enricher and in cascading relationship to provide a CO.sub.2-rich permeate stream, the CO.sub.2-capture zone further including at least one condenser to condense the enriched CO.sub.2-stream and output the captured CO.sub.2-flow stream.

A filtering device and a filtering method are provided. The filtering device includes a bubble filtering system. The bubble filtering system at least includes a first bubble filtering system and a second bubble filtering system. The first bubble filtering system configured for performing a first bubble filtration in the solution. The second bubble filtering system configured for performing a second bubble filtration in the solution. Filter fineness of the second bubble filtering system is higher than filter fineness of the first bubble filtering system.