Cansolv Technologies Inc.

Union Carbide Chemicals & Plastics Technology Corporation

Union Carbide Canada Limited

Leo Ernest Hakka

Michel A Ouimet

Paul J Parisi

John Nicolas Sarlis

Veronique Roy

Paulino Forte

John C Chang

John N Sarlis

Colin Francis Ryan

Jean I Sarlis

William Charles Morro

James Mackay Brophy

Jean Claude Courtes

Patrick M Ravary

Michel Jacques Hebrard

A cyclic process for the removal of NOfrom a NOcontaining feed gas, and optionally removal mercury vapour and/or sulfur dioxide is provided. A process is also provided by which an iron chelate absorbent may be thermally regenerated.

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A process for removing contaminants from a waste gas stream comprises treating the waste gas stream to remove at least one of SOand NOand to obtain a lean stream having a reduced level of at least one of SOand NOand, contacting the lean gas stream with a mercury absorbent solution comprising permanganate to remove mercury vapour and to obtain a mercury lean stream and a mercury rich absorbent solution. The mercury rich absorbent solution may be subsequently treated on a batch basis to remove precipitated manganese dioxide and obtain a solution containing mercury ions.

Waste gas treatment process including removal of mercury

Sulphur dioxide is removed from gas streams by contacting the gas stream with an absorbing medium containing an amine capable of forming an amine salt, heat stable salt and sulfite. The level of heat stable salt is selected such that during the regeneration process of the sulphur dioxide rich amine, the pH of the absorbing medium is at a selected level or below when the level of sulfite in the absorbing medium has been reduced to a specified value. The amine that absorbs the sulphur dioxide has a pKa less than that of sulfite. If the absorbent includes a diamine, then the spent absorbing medium is regenerated under conditions such that at least one amine group remains in salt form.

A process for recovering COfrom a feed gas stream comprises treating the feed gas stream with a regenerated absorbent comprising at least one tertiary amine absorbent having a pKfor the amino function of from about 6.5 to about 9 in the presence of an oxidation inhibitor to obtain a COrich stream and subsequently treating the COrich stream to obtain the regenerated absorbent and a COrich product stream. The feed gas stream may also include SOand/or NO.

Method for recovery of CO2 from gas streams

NO is removed from a gas stream by reacting NO with an absorbent to form a metal nitrosyl complex. The metal nitrosyl complex is reacted with sulfite and/or bisulfite to produce recoverable reaction products containing nitrogen and/or sulfur and to regenerate the reagent. The recoverable reaction products are then separated from the regenerated reagent.

Method and apparatus for NOx and SO2 removal

The present invention provides a process for removing sulfur compounds including sulfur in the (&minus;2) oxidation state such as mercaptans, dialkyl sulfides, carbonyl sulfide, hydrogen sulfide, thiophenes and benzothiophenes, from liquid or gas feed streams, particularly hydrocarbon feed streams such as, for example, natural gas and refinery process streams. According to the process, such a feed stream including these sulfur impurities is contacted with an absorbent which includes a metal ion-containing organic composition such as, for example, iron, copper, lead, nickel, tin, zinc or mercury cation-containing phthalocyanine or porphyrin to thereby form sulfur-metal cation coordination complexes in which the oxidation state of the sulfur and the metal cation remains essentially unchanged. The complexes are separated from the feed stream, and the absorbent is regenerated by disassociating the sulfur compound from the complexes.

Process for removing sulfur compounds from gas and liquid hydrocarbon streams

The invention relates to a method of confining sulfur dioxide for storage or transportation under safe conditions. The method of the invention comprises the steps of (a) contacting a sulfur dioxide-containing gas stream with an absorbing medium comprising water and a water-soluble amine absorbent having at least one amine group with a pKa value greater than about 7 and at least one other amine group with a pKa value less than about 6.5 so that the at least one amine group with a pKa value greater than about 7 irreversibly absorbs sulfur dioxide in salt form rendering the amine absorbent non-volatile and the at least one other amine group with a pKa value less than about 6.5 reversibly absorbs sulfur dioxide, to thereby saturate the absorbing medium with sulfur dioxide against a partial pressure of sulfur dioxide of no more than about 1 atmosphere at 25&deg; C.; and (b) charging the absorbing medium saturated with sulfur dioxide obtained in step (a) into a container for storage or transportation.

Safe storage and transportation of sulfur dioxide

Processes are disclosed for converting heat stable amine salts to heat regenerable amine salts using a modified electrodialysis zone. The processes of the present invention can be used to reduce the level of heat stable salts in a lean solvent stream in an acid gas removal process and can be integrated with the acid gas removal process to utilize process streams as a source of ions.

Process for converting heat stable amine salts to heat regenerable amine

Processes for the removal of sulfur dioxide from gas streams, e.g., stack gases, are disclosed wherein the absorption occurs in the presence of a diamine. The first amine group, i.e., stronger amine group, of the diamine is in salt form, having sulfite anions associated therewith, and absorbs by a sulfite/bisulfite absorption mechanism. The second amine groups absorbs sulfur dioxide in free base form. The sulfite salt on the first amine group is maintained by controlling the level of heat stable salts in the absorbent. Both the first and second amine groups can be conveniently regenerated together, e.g., by steam stripping.

Removal of sulfur dioxide from gas streams

Processes are provided for the removal of sulfur dioxide from gas streams using aqueous lime or limestone slurries containing an additive comprising an amine. The amines have an available alkalinity of at least 0.5 meq/gram at a pH between 3.0 and 5.5. The amines are highly soluble in the slurry and can have a low volatility, thereby reducing amine losses with the gas product. Furthermore, amines which are absorbed on the calcium sulfate or calcium sulfite by-products can be recovered by water-washing with a water make-up stream.

Sulphur dioxide is removed from gas streams by contacting the gas stream with an absorbing medium containing less than about 80 wt. % of water and the spent absorbing medium subsequently is regenerated by removing absorbed SO.sub.2. The absorbing medium comprises amine salt absorbent having at least two amine groups, at least one of which is a salt and at least one of which has a pKa of about 4.5 to 7.3. The absorption is at a temperature of less than about 60.degree. C. The spent absorbing medium is regenerated under conditions such that at least one amine group remains in salt form.

Removal and recovery of sulphur dioxide from gas streams

Components are removed from gas streams by contact in a contact zone with finely-divided droplets of reversible liquid sorbent wherein a portion of the droplets is coalesced, which droplets contain a concentration of component sorbed greater than that predicted by vapor-liquid equilibrium at the condition of the gas stream at the exit of the contact zone.

Gas scrubbing process

A low temperature lubricant oil composition having improved viscosity-temperature properties, lubricating properties and pour point is described. The composition comprises a homogeneous mixture of from 1% to 50% by weight of poly(dimethylsiloxane) having an average viscosity at 100.degree. F between 100,000 cs and 1,000,000 cs, the remainder of the mixture being a hydrocarbon oil selected from certain alkenes, isoparaffins and naphthenics. The composition can also contain a foam inhibitor such as a perfluoroalkylpolyether.

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Dollard des Ormeaux, Canada

Leo Ernest Hakka