A method for recovering methane gas from a landfill involves the use of a main absorber, a flash system, an optional ancillary absorber and an optional polishing absorber. The recovered gas is maintained at a temperature that enhances a solvent's ability to absorb carbon dioxide from the recovered gas. While the main absorber uses the solvent for absorbing most of the carbon dioxide from the recovered gas, the flash system removes much of the carbon dioxide from the solvent exiting the main absorber. In some examples, at least portion of the flash system operates at subatmospheric pressure to create a vacuum that draws in a generally inert stripper gas (e.g., air, nitrogen, etc.) at atmospheric pressure. The stripper gas helps remove carbon dioxide from the solvent in the flash system.

This invention is directed to methods and systems for controlling water in acid gas removal processes comprising the steps of a) treating the gas stream in an absorption zone with the NAS absorption liquid; b) direction the acid gas-loaded NAS absorption liquid to a regeneration zone; c) directing the regenerated NAS absorption liquid to step a); and d) controlling the first and second set of conditions.

A method for removing components to be separated from industrial gases using an absorption and desorption processes having liquid absorbents. At least one absorption device and one desorption device are provided, at least a part of the laden solution leaving the absorption device is diverted before being heated and delivered to the head of the heat transfer section. The laden partial stream is heated by the steam rising from the lower part of the desorption device through heat exchange in the heat transfer section. The remaining stream of cold, laden solution leaving the absorption device is expanded by so the relief valve and the heat exchanger into a pressure relief vessel, such that the stream leaving the heat exchanger separates into a liquid and a gaseous state. The pressure in the pressure relief vessel pressure is lowered so that the total energy demand in absorption and desorption processes is reduced.

An absorber of a carbon dioxide capture system according to an embodiment includes: a release region for releasing carbon dioxide from an absorbing liquid supplied from a stripper; and a second gas-liquid contact unit to which carbon dioxide released in the release region is supplied together with exhaust gas discharged from a first gas-liquid contact unit. The absorbing liquid having released the carbon dioxide therefrom in the release region is supplied to the second gas-liquid contact unit by an absorbing liquid supply device. The absorbing liquid having passed through the second gas-liquid contact unit is guided to the first gas-liquid contact unit while bypassing the release region. The second gas-liquid contact unit brings the exhaust gas and the absorbing gas into contact with each other so as to cause the carbon dioxide contained in the exhaust gas to be absorbed in the absorbing liquid.

A method for removing SOx from a gas using an ethylene glycol composite solution is provided. The ethylene glycol composite solution is made by mixing ethylene glycol and/or polyethylene glycol with an organic acid and/or organic acid salt containing no nitrogen atom in a molecule, the ethylene glycol composite solution is brought into contact with the gas containing SOx to absorb the SOx in the gas, wherein x=2 and/or 3. The ethylene glycol composite solution with absorbed SOx is regenerated by one or more of a heating method, a vacuum method, a gas stripping method, an ultrasonication method, a microwave method, and a radiation method to release by-products of sulfur dioxide and sulfur trioxide, and the regenerated ethylene glycol composite solution is recycled for use. This method can be used for desulfurization of flue gas, burning gas, coke-oven gas, synthesis waste gas from dyestuff plants, sewage gas from chemical fiber plants, and other industrial raw material gases or waste gases containing SOx.

A method for processing includes reacting hydrogen sulfide (H.sub.2S), in a sour NG stream, and a sulfur dioxide (SO.sub.2) stream, the sour NG stream having a molar concentration of at least about 0.5% H.sub.2S, the reactor output including sulfur, water, and a reacted NG stream having a lower molar concentration of H.sub.2S compared to the sour NG stream; contacting the reactor output and a liquid solvent in a solvent wash column to remove at least some H.sub.2S from the reacted NG stream to produce a treated NG stream, the treated NG stream having a lower molar concentration of H.sub.2S compared to the reacted NG stream, the solvent wash column further outputting a solvent mixture stream that includes at least the liquid solvent and the sulfur; and separating, with a centrifuge, the solvent mixture stream into solid sulfur and a recyclable liquid solvent stream.

In a crude oil purification process including phase separators, a vapor recovery unit (VRU), and dew pointing/dehydration and CO.sub.2 removal membranes, instead of compressing the low boiling point (i.e., C.sub.1-5) hydrocarbon vapor stream from the VRU along with the main portion of gas from the separation train and feeding it to the membranes, it is compressed and dehydrated along with the H.sub.2O/C.sub.3+ hydrocarbon enriched permeate from the dew pointing and dehydration membranes.

A tri-ethylene glycol (TEG) circulation system and method is implemented by a computer system, which periodically receives, from a temperature sensor and a flow sensor, respectively, a temperature signal representative of a temperature of a process gas upstream of a contactor column of a gas dehydration unit, and a flow rate signal representative of a flow rate of the process gas upstream of the contactor column. The process gas is cross-contacted with TEG within the contactor column to reduce water content of the process gas to satisfy a threshold water content. Using the temperature signal and the flow rate signal, the computer system periodically determines a quantity of TEG to be introduced into the contactor column to reduce the water content of the process gas to satisfy the threshold water content, and periodically controls an operation of a flow control valve configured to flow the TEG into the contactor column.

A natural gas (NG) processing plant and method of operating the NG processing plant including: receiving feed NG, removing acid gas from the feed NG gas via a gas sweetening unit having an amine absorber column that absorbs the acid gas, collecting an amine sample in the gas sweetening unit, removing water from the feed NG via a NG dehydration system having a column vessel that contacts the feed NG with liquid desiccant including glycol to remove the water, collecting a glycol sample in the NG dehydration system, adding reagent water and ferrozine to each of the amine sample and the glycol sample, and measuring total dissolved iron via ultraviolet-visible (UV-Vis) spectrophotometry in each of the amine sample and the glycol sample.

Disclosed in certain embodiments are processes for heavy hydrocarbon removal that implement a regeneration loop that introduces an absorbent into a regeneration gas stream, and systems for implementing the same.