Chevron U.s.a. Inc.

University of South Alabama

Georgia Tech Research Corporation

Daniel Chinn

Shabbir Husain

Nitesh Bhuwania

Michael Sean Driver

Zunqing He

Russell Evan Cooper

Tapan Kumar Das

James Hillard Davis, Jr

Kevin N West

Ronald P MacDonald

Hye Kyung Timken

Clifford Michael Lowe

Michael S Driver

Huping Luo

William L Schinski

Lin Li

Zhen Zhou

Joshua Allen Thompson

Lyman Arnold Young

Marcus Vinicius Dutra E Mello

Graham J Forder

Scott Michael Husson

Alice Zunqing He

XiaoLin Wei

Jr Davis James H

Stephen Joseph Miller

Dennis John O'Rear

William John Koros

Charles Kibby

Curtis Lee Munson

De Q Vu

Steven Xuqi Song

John D Wind

Paul Bryan

Yaofan Yi

Evan Shigeto Hatakeyama

Yang Liu

Oluwasijibomi O Okeowo

Laura C Boudreau

Minquan Cheng

Stanley Hsing-Wei Huang

Gordon R Deppe

Ryan Oliver Owen

Christine Marie Long

Jen Kai Chen

Babak Fayyaz Najafi

Siji Okeowo

Shabbir Hussain

Jeff D Euhus

Rusell Evan Cooper

Hye Hyung Timken

Zhongyun Liu

Jinhua Bai

Brent A Hetrick

Sam J Mishael

Anne M Helgeson

James Ong

James H Davis

The present invention is directed to a method for removing elemental mercury from liquid natural gas comprising changing the stabilizer column operating conditions to beneficially transfer mercury from the stabilized condensate phase to the overhead gas phase, where it may be compressed and recycled with the gas going to the existing feed gas mercury removal units.

Method of reducing mercury in stabilized condensate

Disclosed is a method for removing hydrogen sulfide from natural gas. The method includes passing a natural gas feed including methane and hydrogen sulfide (H2S) through a membrane at normal operating conditions. The membrane is an asymmetric hollow fiber membrane or an asymmetric film composite membrane including a porous layer and a nonporous skin layer. The asymmetric hollow fiber membrane or the nonporous skin layer of the asymmetric film composite membrane plasticizes during the method by exposure to condensable gases with high critical temperature under the operating conditions. The membrane preferentially removes H2S over methane from the natural gas feed at a H2S/methane selectivity of from 7 to 40 when measured at 35° C. and 45 bar.

Membranes for contaminant removal from natural gas and methods for use thereof

Disclosed are methods and systems for reducing elemental sulfur production in a gas production plant that includes receiving produced fluids high in hydrogen sulfide, removing hydrogen sulfide and converting hydrogen sulfide to elemental sulfur in a Claus unit. An acid gas stream is diverted from a feed line to the Claus unit in the gas processing plant and directed to a multistage acid gas compressor. An elemental sulfur production rate is reduced without reducing a production rate of the produced fluids. The compressed acid gas stream can be injected into a subterranean formation. In some embodiments, the gas production plant is integrated with an oil processing and gas injection plant.

Processes and systems for high HS gas processing having reduced sulfur production

Disclosed are systems and methods for producing oil and gas while removing hydrogen sulfide from fluids produced from oil and gas reservoirs. Hydrogen sulfide-selective membranes are used to remove hydrogen sulfide from bottlenecked plant process steps including hydrogen sulfide removal. In some embodiments of the present disclosure, plant processing efficiency is improved for processing of high temperature associated gas streams by using membranes while integrating heat from other existing process streams. In other embodiments of the present disclosure, plant processing efficiency is improved for processing of high temperature associated gas streams by using high temperature tolerant polymer membranes. Oil and/or gas production is increased.

Systems and methods to manage heat in an integrated oil and gas processing plant with sour gas injection

Disclosed are systems and methods for processing gas produced from oil and gas reservoirs while removing mercaptans from the gas. Mercaptan-selective membranes are used to debottleneck known systems and methods by removing mercaptans from bottlenecked plant process steps including LPG fractionation and mercaptan sweetening. Hydrogen sulfide can be simultaneously removed by the membranes. Production of on specification LPG and sales gases can be increased.

Systems and methods to remove mercaptans from sour gas using membranes

Disclosed are systems and methods for producing oil and gas while removing hydrogen sulfide from fluids produced from oil and gas reservoirs and injecting a sour gas stream containing the hydrogen sulfide into an underground formation. Hydrogen sulfide-selective membranes are used to debottleneck known systems and methods by removing hydrogen sulfide from bottlenecked plant process steps including sour gas compression, hydrogen sulfide removal and sour gas injection. Pressure ratio across the membranes can also be manipulated to provide further debottlenecking. Gas-gas eductors are also disclosed for use in leveraging relatively high-pressure streams to boost the pressure of low pressure streams. Oil production is thus increased.

Systems and methods to debottleneck an integrated oil and gas processing plant with sour gas injection

Disclosed are systems and methods for increasing oil production in an integrated oil and gas production plant including hydrogen sulfide removal and sour-gas injection into an underground formation. Hydrogen sulfide-selective membranes are used to debottleneck known systems and methods by removing hydrogen sulfide from bottlenecked plant process steps including sour gas compression, hydrogen sulfide removal and sour gas injection. A method of retrofitting an integrated plant includes adding a hydrogen sulfide-selective membrane upstream of an amine unit to remove hydrogen sulfide from an associated gas stream and form a permeate stream enriched in hydrogen sulfide and a retentate stream depleted in hydrogen sulfide and enriched in hydrocarbon gases. Less hydrogen sulfide is sent to the amine unit and oil production is higher than in the integrated plant without the hydrogen sulfide-selective membrane.

Disclosed are systems and methods for producing oil and gas in a plant while removing hydrogen sulfide and water from fluids produced from oil and gas reservoirs and injecting a sour gas stream containing the hydrogen sulfide into an underground formation. Water-selective membranes are used to debottleneck known systems and methods by removing water from bottlenecked sections of the plant including pretreatment of a sour gas feed to one or more gas processing plants. In other aspects, water-selective membranes are used to debottleneck the pretreatment of an acid gas feed to a Claus unit to convert hydrogen sulfide to sulfur in a gas processing plant. The water-selective membranes pretreat the acid gas feed.

Systems and methods to dehydrate high acid gas streams using membranes in an oil and gas processing plant

A process for removal of mercury in a gas dehydration system comprising (a) adding a complexing agent to a recirculated glycol solvent as part of the glycol solution feed prior to or at the dehydration liquid contactor and recirculating continuously with the glycol solvent, (b) selectively reacting the complexing agent with mercury in the wet natural gas to remove the mercury from the dry natural gas product, (c) and feeding the rich glycol with the complexing agent to a regenerator and continuously regenerating.

Process, method and system for removal of mercury in a gas dehydration process

Disclosed herein is a method of making a crosslinked membrane such as a crosslinked hollow fiber membrane. The method comprises (a) preparing a polyimide polymer comprising carboxylic acid functional groups from a reaction solution comprising monomers and at least one solvent; (b) treating the polyimide polymer with a diol at esterification conditions to form a monoesterified polyimide polymer; (c) forming a monoesterified polyimide membrane or dense film from the monoesterified polyimide polymer; and (d) subjecting the monoesterified polyimide membrane or dense film to transesterification conditions under a COatmosphere to form a crosslinked polyimide membrane or dense film.

Methods of making crosslinked membranes utilizing an inert gas atmosphere

A process and system for separating COfrom a flue gas stream is disclosed. The process involves (a) contacting a flue gas stream containing water vapor and COwith an ionic absorbent under absorption conditions to absorb at least a portion of the COfrom the flue gas stream and form a CO-absorbent complex; wherein the ionic absorbent comprises a cation and an anion comprising an amine moiety; and (b) recovering a gaseous product having a reduced COcontent.

Process for the separation of carbon dioxide from flue gas

An aqueous ionic absorbent solution is disclosed containing (a) about 15 wt. % to about 80 wt. % of one or more diluents, based on the total weight of the aqueous ionic absorbent solution; and (b) an ionic absorbent containing a cation and an anion comprising an amine moiety.

Aqueous solutions of amine functionalized ionic compounds for carbon capture processes

Disclosed is a method of retrofitting a full-scale LNG plant to enhance the LNG production capacity of the LNG plant and a method for operating such a retrofit plant. A small scale LNG plant having a capacity less than 2 MTPA can be integrated with a main LNG plant having a capacity of at least 4 MTPA such that end flash gas and boil off gas from the main LNG plant can be liquefied by the small scale LNG plant as incremental LNG. It has been found that the production capacity of the integrated system can be improved by increasing the temperature of the gas stream exiting the main cryogenic heat exchanger of the main LNG plant between 5&#xb0; C. and 30&#xb0; C. as compared with the design temperature.

Integration of a small scale liquefaction unit with an LNG plant to convert end flash gas and boil-off gas to incremental LNG

A crude oil which contains at least 0.1 wt % unstable sulfur compounds is treated in a reaction zone at low temperature to convert at least 50 wt % of the unstable sulfur compounds contained therein. The reaction and removal of sulfur from the crude may be facilitated by contacting the crude oil with a catalytic material in the presence of a stripping fluid.

Removing unstable sulfur compounds from crude oil

Disclosed herein is a method for improving the total energy demand required to separate carbon dioxide (CO) from an aqueous ionic absorbent solution in a post-combustion carbon capture process. The method involves (a) contacting a flue gas stream containing COwith an aqueous ionic absorbent solution under absorption conditions to absorb at least a portion of the COfrom the flue gas stream and form a CO-aqueous ionic absorbent solution stream, wherein the aqueous ionic absorbent solution comprises one or more diluents and an ionic absorbent containing a cation and an anion comprising an amine moiety; and (b) subjecting at least a portion of the CO-aqueous ionic absorbent solution stream to desorption conditions to form a CO-rich stream and an aqueous ionic absorbent solution stream having a reduced COcontent.

Method for improving total energy demand in a post-combustion carbon capture process with ionic absorbent

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Bay Point, CA, United States of America

Daniel Chinn