Union Oil Company of California

Donald M Fenton

Dennis D Delaney

Raoul P Vaell

Hugh W Gowdy

Dennis L Saunders

Darrell L Gallup

LeRoy W Holm

Kevin R Kitz

Brian J Kelly

F Emmett Bingham

Manuel E Obando

Byron B Woertz

Frank W Stechmeyer

Paul A Peaden

An integrated system of non-condensable gas (NCG) and condensate treatment allows geothermal power plant condensate and non-condensable gas effluent streams containing H.sub.2 S and ammonia to be commercially useful for more than for cooling tower makeup. In the preferred embodiment, the pH of the condensate is increased by adding ammonia and the pH increased stream is contacted with NCG to scrub and oxidize the H.sub.2 S constituent of the NCG. By reducing the pH, the condensate or aqueous stream mixture can also be used to further transfer ammonia from the non-condensable gas stream to the aqueous stream, enriching the stream for use as a fertilizer/irrigation water mixture. If other commercial uses are desired for the mixture and/or oxidized NCG streams, they can be resin treated to remove the ammonia constituent. With the ammonia and H.sub.2 S constituents decreased, the condensate may be used for a variety of applications and the NCG can be injected or used as a commercial feed stream. Rejuvenation of the resin may be accomplished by recycling and purging with the treated NCG. The effluent purge gas may be used to further enrich irrigation waters. A nearly total elimination of all emissions from the geothermal power is thereby made possible.

Method to treat geothermal fluid streams

Non-brackish water can be produced from the brackish water or brine containing at least 500 ppm total dissolved solids coproduced in many active hydrocarbon product wells and found in many inactive gas wells. The brackish water or brine is desalinated producing non-brackish water, preferably, potable water. A preferred method of desalination is by reverse osmosis.

Desalination of brackish water or brine from hydrocarbon wells

Non-brackish water can be produced from the brackish water found in many inactive oil wells. The inactive well is perforated at the level known to have brackish water and the water is pumped out. The brackish water is desalinated producing non-brackish water, preferably, potable water. A preferred method of desalination is by reverse osmosis.

Desalination of brackish water from oil wells

A method for pollution abatement in groundwaters comprises drilling a series of wells in the path of an advancing front of contaminants in an aquifer, and using the wells to introduce into the aquifer an adsorbent for the particular contaminants present.

Groundwater pollution abatement

This invention provides a novel heterogeneous catalyst system adapted for alkanol homologation, which comprises lanthanum hydroxide and a rhodium or ruthenium moiety, e.g. RhCl.sub.3 or RuCl.sub.3.

Lanthanum hydroxide and a rhodium or ruthenium moiety catalyst for

Shale oil produced from arsenic-containing oil shale is treated with an aqueous solution of one or more sulfide materials and separated therefrom, yielding an oil fraction of reduced arsenic content. Preferred sulfide materials include ammonium sulfide and ammonium polysulfide.

Arsenic removal from shale oils

This invention provides a process for converting alkanols into higher alkanols, e.g. methanol into ethanol, by contacting a basic solution comprising said alkanol in the absence of added hydrogen, with a catalyst comprising a lanthanum moiety. Preferably said catalyst further comprises a rhodium or a ruthenium moiety in combination with said lanthanum moiety. This invention further provides a novel heterogeneous catalyst system adapted for alkanol homologation, which comprises lanthanum hydroxide and a rhodium or ruthenium moiety, e.g. RhCl.sub.3 or RuCl.sub.3.

Hemologation of alkanols

Aqueous and organic fluids which contain arsenic are contacted with spent oil shale from an oil shale retorting operation and separated therefrom, yielding a fluid of reduced arsenic content. In one embodiment, shale oil is placed in contact with spent oil shale under conditions of elevated temperature and pressure to reduce the arsenic content of the oil.

Arsenic removal method

A method is provided for removing elemental sulfur particles from a hydrogen sulfide removal process which employs a regenerable, aqueous washing solution capable of absorbing hydrogen sulfide from an industrial gas stream and converting that hydrogen sulfide to elemental sulfur. The washing solution of such a process is contacted with bubbles of an oxygen-containing gas while in the presence of controlled concentrations of a selected hydrocarbon and a selected surfactant.

Method for removing elemental sulfur particles from the aqueous washing

A method is provided for reconditioning a hydrogen sulfide removal system, such as a Stretford process system in which elemental sulfur is formed, after the system has become contaminated with sulfur-feeding bacteria to an extent that operation thereof is substantially impaired. The method includes adding a bactericide to the washing solution employed in the system to destroy the bacteria and adding a surfactant to the solution to remove dead bacteria from the surfaces of particulate sulfur formed in the system so that the particles can agglomerate in the intended manner to enable sulfur removal from the solution.

Method for reconditioning bacteria-contaminated hydrogen sulfide

Mineral-derived fines are contacted with a polymeric material to agglomerate the fines. The agglomerating polymeric materials are the homopolymers and salts of homopolymers of acrylic acid and methacrylic acid, the copolymers and salts of copolymers of acrylic acid with methacrylic acid, and the copolymers and salts of copolymers of one or more monomers of acrylic acid and methacrylic acid together with any one or more monomers selected from the group consisting of acrylamide, methacrylamide, acrylonitrile, methacrylonitrile, styrene, N,N-dimethylacrylamide, vinyl acetate, and monomers having the structural formula: ##STR1## where R.sub.1 is hydrogen or a methyl group and R.sub.2 is an alkyl radical, alkoxyalkyl radical, hydroxyalkyl radical, or aminoalkyl radical, having from 1 to 20 carbon atoms.

Agglomeration of mineral-derived fines

A hydrogen sulfide removal and conversion method in which a hydrogen sulfide-containing gas stream is contacted with a regenerable washing solution having a pH between about 5 and about 10 and containing solubilized vanadium, thiocyanate ions, a carboxylate complexing agent, one or more water-soluble quinones and one or more water-soluble nonquinone aromatic compounds capable of solubilizing tetravalent vanadium. The absorbed hydrogen sulfide is converted to elemental sulfur which, after oxidative regeneration of the washing solution, is separated from the regenerated solution.

Method for removing hydrogen sulfide from gas streams

A thiocyanate compound is added to metals-containing hydrocarbon oils under reaction conditions, and a product hydrocarbon of reduced metals content is separated from a metals-containing solid.

Process for removal of metals from hydrocarbon oils

A composition and method for reducing the pour point of syncrude, such as those from oil shale, tar sands, oil-impregnated diatomite ore, or coal, by adding thereto an effective amount of a nitrogen-containing compound such as ammonia, ammonium hydroxide or a primary, secondary or tertiary water-soluble aliphatic amine or alkanolamine having one or more alkyl groups containing 1 to 4 carbon atoms.

Pour point reduction of syncrude

A method is provided for reconditioning a hydrogen sulfide removal system, such as a Stretford process system in which elemental sulfur is formed, after the system has become contaminated with sulfur-feeding bacteria to an extent that operation thereof is substantially impaired. The method includes adding a bactericide to the washing solution employed in the system to destroy the bacteria and adding a non-ionic surfactant to the solution to remove dead bacteria from the surfaces of particulate sulfur formed in the system so that the particles can agglomerate in the intended manner to enable sulfur removal from the solution.

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Anaheim, CA, United States of America

Donald M Fenton