An absorbent for selective removal of hydrogen sulfide from a fluid stream comprises an aqueous solution of a) a tertiary amine, b) a sterically hindered secondary amine of the general formula (I)

##STR00001##

in which R.sub.1 and R.sub.2 are each independently selected from C.sub.1-4-alkyl and C.sub.1-4-hydroxyalkyl; R.sub.3, R.sub.4, R.sub.5 and R.sub.6 are each independently selected from hydrogen, C.sub.1-4-alkyl and C.sub.1-4-hydroxyalkyl, with the proviso that at least one R.sub.4 and/or R.sub.5 radical on the carbon atom bonded directly to the nitrogen atom is C.sub.1-4-alkyl or C.sub.1-4-hydroxyalkyl when R.sub.3 is hydrogen; x and y are integers from 2 to 4 and z is an integer from 1 to 4; where the molar ratio of b) to a) is in the range from 0.05 to 1.0, and c) an acid in an amount, calculated as neutralization equivalent relative to the protonatable nitrogen atoms in a) and b), of 0.05 to 15.0%. One preferred amine of the formula I is 2-(2-tert-butylaminoethoxy)ethanol. The absorbent allows a defined H.sub.2S selectivity to be set at pressures of the kind typical in natural gas processing.

A compound of the general formula (I)

##STR00001##

in which R.sub.1, R.sub.2 and R.sub.3 are independently selected from C.sub.1-4-alkyl and C.sub.1-4-hydroxyalkyl; each R.sub.4 is independently selected from hydrogen, C.sub.1-4-alkyl and C.sub.1-4-hydroxyalkyl; each R.sub.5 is independently selected from hydrogen, C.sub.1-4-alkyl and C.sub.1-4-hydroxyalkyl; m is 2, 3, 4 or 5; n is 2, 3, 4 or 5; and o is an integer from 0 to 10. A preferred compound of the formula (I) is 2-(2-tert-butylaminoethoxy)ethylamine. Absorbents comprising a compound of the formula (I) have rapid absorption of carbon dioxide from fluid streams and are also suitable for processes for the simultaneous removal of H.sub.2S and CO.sub.2, where given H.sub.2S limits have to be observed but complete removal of CO.sub.2 is not required.

Biogas containing H.sub.2S and CO.sub.2 is upgraded by removing H.sub.2S using PTSA and CO.sub.2 using two stages of gas separation membranes. The first stage permeate may optionally be used a regeneration gas stream. The second stage permeate may optionally be used a cool down gas stream. The PTSA unit includes two or more adsorbent beds each selective for water, VOCs, and H.sub.2S over CO.sub.2 and for H.sub.2S over methane.

A method for producing an ashless coal which includes a slurry preparation step, an extraction step, a separation step, an ashless coal acquirement step, and a by-product acquirement step. The separation step is conducted under the state of being pressurized to a pressure equal to or higher than a vapor pressure of the solvent. In the by-product acquirement step, the solvent is evaporated and separated from the solid content-concentrated slurry by spraying the solid content-concentrated slurry into a flash tank in which a pressure is set to lower than a saturation pressure of the solid content-concentrated slurry from a spray nozzle while maintaining a pressure of the solid content-concentrated slurry in a nozzle orifice of the spray nozzle at a level equal to or higher than the vapor pressure of the solvent.

Rich natural gas is first compressed, then ambient air cooled and separated into lean natural gas, NGL and water. Hydrate formation during decompression of the lean gas is precluded by either heating the lean natural gas or mixing the lean natural gas with methanol or other additive before depressurization. Similarly, hydrate formation in the NGL is also precluded by either heating the NGL or mixing the NGL with methanol or other additive before depressurization. The NGL is conditioned for storage and transport in common propane tanks by a stabilizer or two-phase separator. The lean natural gas can be used for internal combustion, liquefied natural gas, compressed natural gas or liquid fuel processing.

A plant comprises a feed gas source, H2S removal unit, first absorber and a second, pressure reduction stages, first and second heat exchangers, stripping unit, and a conduit. The H2S removal unit selectively removes H2S from a feed gas from the feed gas source to produce an H2S depleted feed gas. The first absorber and the second absorber remove CO2 from the H2S depleted feed gas using a semi-lean and an ultralean solvent to produce a product gas and a rich solvent. The plurality of pressure reduction stages generates a cooled flashed solvent. The first heat exchanger and the second heat exchanger use the cooled flashed solvent to cool the H2S depleted feed gas and the semi-lean solvent. The stripping unit strips the flashed solvent with dried air to produce the ultralean solvent, and the conduit combines a portion of the ultralean solvent with the H2S depleted feed gas.

A plant includes a pretreatment unit for H2S removal and air dehydration, and at least two absorbers that receive a feed gas at a pressure of at least 300 psig with variable CO2 content (e.g., between 5 to 60 mol %), wherein the feed gas is scrubbed in the absorbers with an ultralean and a semi-lean physical solvent, respectively, at low temperatures to at least partially remove the CO2 from the feed gas. Such configurations produces a low CO2 dry treated gas and a H2S-free CO2 for sequestration while advantageously providing cooling by expansion of the rich solvent that cools the semi-lean solvent and the feed gas, wherein an ultralean solvent is produced by stripping using dry air.

Systems and methods that utilize feed gases that are supplied in a wide range of compositions and pressure to provide highly efficient recovery of NGL products, such as propane, utilizing isenthalpic expansion, propane refrigeration, and shell and tube exchangers are described. Plants utilizing such systems and methods can be readily reconfigured between propane recovery and ethane recovery.

A system and method for the on-site separating and treating of a hydrocarbon liquid stream at an oil and gas production site is disclosed. The system comprises an oil and condensate distillation unit and a vapor recovery unit. In one embodiment, the oil and condensate distillation unit operates at low pressure or vacuum conditions to reduce the vapor pressure above the column of oil within the tubing, thereby increasing the production of oil and condensate and capturing entrained natural gas otherwise lost or burned off. The system further functions to improve the quality and volume of recovered natural gas and to decrease air pollution, in addition to increasing oil and condensate production at the well site.

Capturing at least one heavy metal, from mercury and arsenic, contained in a moist gas comprising water vapor, by the following steps: a) heating the moist gas by heat exchange with a compressed heat transfer fluid obtained in step e) in order to obtain a condensed heat transfer fluid and a gas reheated to a temperature Tc; b) bringing the reheated gas into contact with a heavy metal capture mass in order to obtain a gas depleted in heavy metal; c) decompressing the cooled heat transfer fluid; d) cooling the gas depleted in heavy metal by heat exchange with the heat transfer fluid produced in step c) in order to obtain a cooled gas at a temperature Tf, the heat transfer fluid being vaporized; e) compressing the vaporized heat transfer fluid in a manner such as to obtain a compressed heat transfer fluid, the compressed heat transfer fluid being recycled.