Union Oil Company of California

Walter Albertson

Robert H Hass

Chien-Cheng J Shih

Michael C Smith

Marvin J Schwedock

David A Lindsay

Darcel L Hulse

Gravity flow mixing apparatus for the packed bed flow mixing of particulate matter, such as hot, retorted oil shale, comprises a mixing tower having therein a plurality of parallel mixing tubes. A plurality of three dimensional mixing members are axially spaced apart at about 60.degree. to about 120.degree. rotational separation so that, with packed bed flow through the tubes, each member is below the particulate matter repose surface at the above-adjacent member. Means are included for introducing a cooling fluid, preferably, water, into the tubes just above one or more of such repose surfaces, apertures being provided in the tubes to enable disengagement of gases, for example, steam, from the particulate matter. Comprising each mixing member are primary, secondary and tertiary mixer elements. The primary element has a 'W' shaped free edge and the secondary and tertiary elements each have first and second triangular sides connected together to form a linear peak and define a tetrahedral shape, the tertiary element being substantially smaller than the secondary element. The secondary element is joined to the primary element so that the secondary element projects upwardly and outwardly from the primary element. In turn, the tertiary element is joined to the secondary element so that the linear peaks of each meet at an obtuse angle, the tertiary element thereby projecting forwardly and outwardly from the secondary element at upper regions thereof. Corresponding mixing methods are provided.

Static, gravity-flow mixing apparatus for particulate matter

In the catalytic processing of hydrocarbons, a hydrocarbon oil is successively contacted with a particulate catalyst in a first reaction zone and contacted at a higher temperature with a second portion of the particulate catalyst in the same reaction zone or in a second reaction zone.

Temperature controlled catalytic demetallization of hydrocarbons

Elemental sulfur or aqueous sodium hydrogen phosphate is added to an arsenic-containing hydrocarbon, yielding a product hydrocarbon of reduced arsenic content. The process of the invention is particularly useful in the treatment of shale oils and other syncrudes containing relatively large concentrations of arsenic.

Arsenic removal from hydrocarbons

A gas stream containing SO.sub.x and NO.sub.x compounds is first treated for SO.sub.x removal by absorbing the SO.sub.x components in an aqueous liquid absorbent comprising formic or oxalic acid and an alkanolamine containing a tertiary amine functional group. When spent, this absorbent is regenerated by subjection to an elevated temperature sufficient to produce sulfur and/or hydrogen sulfide. The SO.sub.x -purified gas recovered from the first absorption step is then treated for NO.sub.x removal by contact with a second liquid absorbent solution containing a ferrous chelate in an aqueous, acidic medium. This absorbent is regenerated by contact, under conditions of elevated temperature and pressure, and in the presence of added formate ion, with a catalyst comprising a water-insoluble substance containing one or more tertiary amine functional groups such that absorbed NO.sub.x components are converted to elemental nitrogen.

Process for removing SO.sub.x and NO.sub.x compounds from gas streams

Gas streams containing SO.sub.x and/or NO.sub.x compounds are treated in an absorption-regeneration process for removal of the SO.sub.x and/or NO.sub.x compounds. The process in one embodiment removes SO.sub.x compounds from a stack gas or other feed gas stream by (1) absorbing the SO.sub.x into a novel aqueous liquid absorbent comprising formic acid and an alkanolamine containing a tertiary amine functional group and (2) regenerating the absorbent when spent by subjecting the spent absorbent to an elevated temperature above that utilized for absorption of said SO.sub.x, said elevated temperature being sufficient to convert a substantial proportion of the dissolved SO.sub.x to elemental sulfur and/or H.sub.2 S. If NO.sub.x compounds are present in the stack gas stream, they may also be removed, NO.sub.2 being removed without modification of the process for removing SO.sub.x compounds, and NO by providing in the absorbent an iron (II) chelate, such as a chelate of ferrous ion with ethylenediaminetetraacetic acid. Regeneration of the spent absorbent containing absorbed NO is accomplished under conditions similar to those employed for spent absorbents containing absorbed SO.sub.x compounds. During regeneration, the dissolved SO.sub.x compounds are converted to hydrogen sulfide and/or sulfur and the dissolved NO.sub.x compounds are converted to nitrogen. The invention is most useful for removing SO.sub.2 from gas streams.

Growing community of inventors

Brea, CA, United States of America

Walter Albertson