Honeywell International Inc.

Uop Lcc

Other

William J Whyman

Jan De Ren

Tom M Jackson

Ian Clarke

David A Roman

Lev Davydov

Richard A Johnson, Ii

Rajeswar R Gattupalli

Jonathan Andrew Tertel

Kurt Kraus

James W Harris

Haiyan Wang

James P Glavin

Chad A Williams

Dusty Ray Richmond

Nickolas D Kapaun

Anil Nivrutti Pachpande

David Farr

Alexander Green

Kenny Arnold

Zudtky Wisecarver

Cameron Kardel

Aric G Fisher

David K Borland

Cooper W Bauer

Joao Jorge Da Silva Ferreira Alves

Andrew J Craig

Jeffrey M Knight

Raymond S Chan

Eldar Khamidulin

Bart J T Beuckels

Manu Gustaaf Rosa Van Leuvenhaege

A control process and apparatus provide feed forward control of stoichiometric proportions of hydrogen sulfide and ammonia to a thermal oxidizer and an ammonia scrubber, respectively. To account for unmeasured or uncalculated sulfur feed to the thermal oxidizer, a feed back measurement of sulfur dioxide and ammonia concentration is used to correct the flow rate of hydrogen sulfide to the thermal oxidizer and/or ammonia to the ammonia scrubber.

Process for controlling hydrogen sulfide and ammonia flow rates

A process for adsorbing impurities from hydrocarbon gas streams is disclosed. The process involves passing a hydrocarbon gas stream and a solid dry adsorbent under inert environment to a scrubbing chamber for adsorbing impurities from the hydrocarbon gas streams within the scrubbing chamber. The process adsorption of impurities in scrubbing chamber is carried under non-oxidative conditions to generate a clean product gas.

Process and apparatus for scrubbing a hydrocarbon gas stream

A burner apparatus and process are described. The burner apparatus includes an inlet chamber in communication with a combustion chamber. The combustion chamber has a cylindrical shape defining a longitudinal axis and a radial direction orthogonal to the longitudinal axis. The combustion chamber has an upstream end and a downstream end, and an air inlet is disposed in the inlet chamber. A pilot, a fuel gas inlet, and a refractory material are disposed in the combustion chamber downstream of the air inlet. A mixed gas inlet is positioned downstream of the fuel gas inlet and the pilot in the combustion chamber. The mixed gas inlet includes a manifold having an inlet, a body, and a plurality of nozzles.

Burner system and process for natural gas production

A process for the treatment of waste water, spent air, and hydrocarbon containing liquid and gaseous streams in the cumene/phenol complex is described. Various effluent streams are combined in appropriate collection vessels, including a spent air knockout drum, a hydrocarbon buffer vessel, a fuel gas knockout drum, a phenolic water vessel, and a non-phenolic water vessel. Streams from these vessels are sent to a thermal oxidation system.

Cumene-phenol complex with thermal oxidation system

A process and apparatus for managing hydrogen sulfide in a refinery is provided. In the process, a hydrogen sulfide stream from said refinery is fed to a sulfur recovery unit to produce sulfur and a sulfur compound stream or to a thermal oxidizer. The sulfur compound stream and the hydrogen sulfide stream are then thermally oxidized to produce a sulfur oxide stream. The sulfur oxide stream is then reacted with an ammonia stream. In aspect, the product of the reaction can be a fertilizer. The ammonia stream can be obtained from stripping the hydrogen sulfide stream.

Process for managing hydrogen sulfide in a refinery

Processes involving the use of a dry sorbent injection (DSI) unit or slurry reagent injection (SRI) unit to remove sulfur compounds form flue gas are described. Flue gas from an FCC regenerator, for example, is used to make superheated steam and saturated steam. The flue gas is then sent to a DSI unit to remove the sulfur compounds, and then to an economizer (or heat exchanger) to heat boiler feed water or combustion air. Because the temperature is not reduced as much as with a wet scrubber process, additional energy can be recovered in the economizer.

Energy optimization in fluid catalytic cracking and dehydrogenation units

A burner and methods of using the burner. The burner utilizes bypass conduits to separate the combustion air that is passed to the primary combustion zone into two or more portions. The two portions are injected into the primary combustion zone at different points so as to reduce the flame temperature. A NOx reducing medium may be mixed with the combustion air in the bypass conduit. The NOx reducing medium may be flue gases from a combustion chamber having the primary combustion zone.

Low NOx burner with bypass conduit

A process for treating effluent streams in a naphtha complex is described. One or more of the sour water stripping unit for the NHT sour water from the NHT, the amine treatment unit and the caustic treatment unit for the NHT stripper off-gas, the caustic scrubber unit or other chloride treatment unit for the off-gas from the C-Cisomerization zone and the Cisomerization zone, and the caustic scrubber unit or other chloride treatment unit for the regenerator off-gas are replaced with a thermal oxidation system.

Naphtha complex with thermal oxidation system

Processes for treating effluent streams in alkylation processes are described. One or more process streams rom HF alkylation processes, HSOalkylation processes, or ionic liquid alkylation processes can be thermally oxidized in a thermal oxidation system. The thermal oxidation system can replace at least one of the caustic wash unit, the neutralization unit, and the acid gas treatment unit.

Alkylation process with thermal oxidation system

Processes for natural gas production are described. The processes involve combining a membrane separation system and a thermal oxidizing system. The high and low hydrocarbon permeate streams from the membrane separation system are introduced into the thermal oxidizing system separately. The high hydrocarbon permeate stream provides fuel for the thermal oxidizing system, allowing a reduction in external fuel usage. The reduction in total fuel required yields increased gas production for the total plant. A solvent based acid gas removal system can optionally be included.

Process for natural gas production

An integrated mercaptan extraction and/or sweetening and thermal oxidation and flue gas treatment process for a wide variety of sulfur, naphthenic, phenolic/cresylic contaminated waste streams is described. It provides comprehensive treatment for the safe disposal of sulfidic, naphthenic, phenolic/cresylic spent caustic streams, disulfide streams, spent air streams, spent mixed amine and caustic streams (also known as COS solvent streams) from sulfur treating processes. It allows the use of regenerated spent caustic in the sulfur oxide removal section of the thermal oxidation system reducing the need for fresh NaOH. It may also contain an integrated make-up water system. The integration allows the use of the liquefied petroleum gas or other hydrocarbon feeds to the respective extraction or sweetening process to offset external fuel gas requirements for the thermal oxidation system and for the push/pull system of the spent caustic surge drum and optional hydrocarbon surge drum.

Integrated mercaptan extraction and/or sweetening processes combined with thermal oxidation and flue gas treatment

Processes and apparatuses for treating a sour synthesis gas are provided. The process comprises passing the sour synthesis gas stream to an acid gas removal unit to provide a treated synthesis gas stream and a COrich stream. At least a portion of the COrich stream is passed to a thermal oxidizer unit to provide a treated COgas stream. At least a portion of the treated synthesis gas stream is passed to a pressure swing adsorption unit to obtain a purified hydrogen stream and a tail gas stream. At least a portion of the tail gas stream is passed to the thermal oxidizer unit.

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Tulsa, OK, United States of America

William J Whyman