Exxonmobil Research and Engineering Company

Exxon Research and Engineering Company

Exxonmobil Technology and Engineering Company

Basf Corporation

Basf Se Corporation

Exxonmobil Upstream Research Company

Exxonmobile Research and Engineering Company

Basf Se (reitstÖtter, Kinzebach & Partner)

Michael Siskin

Simon Robert Kelemen

Glen Barry Brons

Leo D Brown

Ramesh Varadaraj

Glen Edward Phillips

Alan Roy Katritzky

Pavel Kortunov

Carla S Pereira

Christopher P Eppig

Lisa Saunders Baugh

Martin Ernst

Gerald Vorberg

Thomas Ingram

David Charles Calabro

Ramzi Yanni Saleh

David T Ferrughelli

Martin Leo Gorbaty

Christine Nicole Elia

Adeana Richelle Bishop

Joseph J Porcelli

Edmund John Mozeleski

Robert Basil Fedich

Kostyantyn Mykolayevich Kirichenko

Stephen Neil Vaughn

Michel A Daage

Georg Sieder

Quanchang Li

William Neergaard Olmstead

George A Knudsen

Frank Cheng-Yu Wang

Fritz A Bernatz

Dennis G Peiffer

Harry William Deckman

Roby Bearden, Jr

Guido Sartori

Jan Bock

Andrzej Malek

Walter Weissman

Charles John Mart

Cornelius Hendrick Brons

Pacifico V Manalastas

Nicholas Charles Nahas

Michael Ehle

Harald Schwahn

Benjamin A McCool

Max Leo Robbins

Frank C Wang

Kuangnan Qian

Rustom Merwan Billimoria

Andrzej Mariusz Malek

Patrick P McCall

Peter Schreyer

Peter A Gordon

Marco Bergemann

Te-Hung Chen

Richard Henry Schlosberg

Daniel Paul Leta

Sophia Ebert

Guang Cao

David William Savage

Mark Alan Greaney

Hans Thomann

Alexander Panchenko

Preeti Kamakoti

Robert P Cahn

P Scott Northrop

David C Dankworth

Eric Bart Sirota

Claude C Culross

Richard Edwards Walter

Peter S Maa

Himanshu Gupta

Ronald Damian Myers

Sumathy Raman

Michael Charles Kerby

Craig Y Sabottke

Zhengdong Cheng

Ramesh R Hemrajani

Catherine L Coyle

John L Robbins

Mitchell Jacobson

Howard J Freund

Manuel Anthony Francisco

Joel R Livingston, Jr

Dean C Draemel

Virginia M Reiner

Thomas B Rauchfuss

Kathleen E Edwards

Ivan Mayer

Jos Wristers

Thomas Wesley Holcombe

Yitian Xiao

James Chi Sung

Theodore Sideropoulos

Matthew J Grossman

Thomas G Mason

Eric W Fryatt

Gerben Zylstra

Michael S Logan

Methods are provided for upgrading of pyrolysis carbon in order to allow for conversion of the pyrolysis carbon into higher value products. Instead of attempting to convert methane into a high value carbon product (such as carbon nanotubes) and Hin a single reaction step, pyrolysis conditions can be used to form Hand pyrolysis carbon. The pyrolysis carbon can then be treated in order to convert the pyrolysis carbon (H to C atomic ratio of less than 0.20) into a product with a higher hydrogen content (H to C atomic ratio of 0.25-0.9 or 2.0-7.0 wt % H). The treatment can correspond to exposing the pyrolysis carbon with hydrogen in the presence of a catalyst, exposing the pyrolysis carbon to conditions for alkylation, or a sequential combination thereof. This can convert the pyrolysis carbon into heavy hydrocarbon products that are resin-like solids at room temperature.

Upgrading pyrolysis carbon

Capture of hydrogen sulfide from a gas mixture may be accomplished using an aqueous solution comprising an amine. Certain sterically hindered amines may selectively form a reaction product with hydrogen sulfide under kinetically controlled contacting conditions and afford a light phase and a heavy phase above a critical solution temperature, wherein the hydrogen sulfide may be present in either phase. Upon separation of the light phase from the heavy phase, processing of one of the phases may take place to remove hydrogen sulfide therefrom. Recycling of the amine to an absorber tower may then take place to promote capture of additional hydrogen sulfide.

Acid gas scrubbing methods featuring amine phase separation for hydrogen sulfide capture

A process for selectively separating HS from a gas mixture which also comprises COis disclosed. A stream of the gas mixture is contacted with an absorbent solution comprising one or more amines, alkanolamines, hindered alkanolamines, capped alkanolamines, or mixtures thereof. The HS/COselectivity of the absorbent solution is preferably greater than about 4.0 for an acid gas loading [mol(CO+HS)/mol(amine)] between about 0.2 and about 0.6, and is achieved by reducing pH of the absorbent solution.

Process for increased selectivity and capacity for hydrogen sulfide capture from acid gases

Proppant particulates like sand are commonly used in hydraulic fracturing operations to maintain one or more fractures in an opened state following the release of hydraulic pressure. Fracturing fluids and methods of hydraulic fracturing may also use proppant particulates composed of fluid coke material (also referred to as fluid coke proppant particulates). In some instances, the fluid coke proppant particulates are characterized by a bulk density of less than about 0.9 grams per cubic centimeter.

Proppant particulates formed from fluid coke and methods related thereto

Proppant particulates like sand are commonly used in hydraulic fracturing operations to maintain one or more fractures in an opened state following the release of hydraulic pressure. Fracturing fluids and methods of hydraulic fracturing may also use proppant particulates composed of flexicoke material. Such proppant particulates may have improved transport into fractures because of lower density than traditional proppants like sand and may produce fewer fines that reduce fluid flow through proppant packs.

Proppant particulates formed from flexicoke and methods related thereto

An absorbent for the selective removal of hydrogen sulfide from a fluid stream comprising carbon dioxide and hydrogen sulfide, wherein the absorbent contains an aqueous solution, comprising: a) an amine or a mixture of amines of the general formula (I) wherein Ris C-C-alkyl; Ris C-C-alkyl; Ris selected from hydrogen and C-C-alkyl; x is an integer from 2 to 10; and b) an ether or a mixture of ethers of the general formula (II): R&#x2014;[O&#x2014;CH&#x2014;CH]&#x2014;OH; wherein Ris C-C-alkyl; and y is an integer from 2 to 10; wherein Rand Rare identical; wherein the mass ratio of b) to a) is from 0.08 to 0.5. The absorbent is suitable for the selective removal of hydrogen sulfide from a fluid stream comprising carbon dioxide and hydrogen sulfide. The absorbent has a reduced tendency for phase separation at temperatures falling within the usual range of regeneration temperatures for the aqueous amine mixtures and is easily obtainable. 

Absorbent and process for selectively removing hydrogen sulfide

In a process for removal of acid gases from a fluid stream the fluid stream is contacted with an absorbent to obtain a treated fluid stream and a laden absorbent. The absorbent comprises a diluent and a compound of the general formula (I) wherein Ris C-C-alkyl; Ris C-C-alkyl; Ris selected from hydrogen and C-C-alkyl; and Ris selected from hydrogen and C-C-alkyl. 

Process for removal of acid gases from a fluid stream

A process for removing acid gases from a fluid stream, wherein the fluid stream is contacted with an absorbent comprising a compound of the general formula (I), wherein Rand Rare independently C-C-alkyl; Ris selected from hydrogen and C-C-alkyl, R, Rand Rare independently selected from hydrogen and C-C-alkyl; x and y are integers from 2 to 4 and z is an integer from 1 to 3, to obtain a treated fluid stream and a laden absorbent. The process allows for a high cyclic capacity while the compounds of the absorbent have a reduced tendency to foaming and low volatility. 

Use of morpholine-based hindered amine compounds for selective removal of hydrogen sulfide

A system and process for selectively separating HS from a gas mixture which also comprises COis disclosed. A water recycle stream is fed to the absorber in order to create a higher concentration absorbent above the recycle feed and having a greater HS selectivity at lower acid gas loadings, and a more dilute absorbent below the recycle feed and having a greater HS selectivity at higher acid gas loadings. Also disclosed is a system and process for selectively separating HS by utilizing two different absorbents, one absorbent for the upper section of the absorber, tailored to have a greater HS selectivity at lower acid gas loadings, and a second absorbent for the lower section of the absorber, tailored to have a greater HS selectivity at higher acid gas loadings.

Process designs for increased selectivity and capacity for hydrogen sulfide capture from acid gases

A delayed coking process in which shot coke and thermally cracked coker products are produced from a sponge coke- and/or transition coke-forming resid feed comprising sponge coke asphaltenes by mixing heteroatom (preferably nitrogen) containing asphaltenes from a shot coke-forming resid with a heated sponge coke-forming resid to form shot coke directing asphaltene aggregates in the resid. The mixture of resid with the added asphaltene is held at an elevated temperature to allow co-aggregates of sponge coke and shot coke asphaltenes to form which, upon delayed coking promote the production of a free-flowing shot coke product.

Control of coke morphology in delayed coking

A method is described for separating COand/or HS from a mixed gas stream by contacting the gas stream with a non-aqueous, liquid absorbent medium of a primary and/or secondary aliphatic amine, preferably in a non-aqueous, polar, aprotic solvent under conditions sufficient for sorption of at least some of the CO. The solution containing the absorbed COcan then be treated to desorb the acid gas. The method is usually operated as a continuous cyclic sorption-desorption process, with the sorption being carried out in a sorption zone where a circulating stream of the liquid absorbent contacts the gas stream to form a CO-rich sorbed solution, which is then cycled to a regeneration zone for desorption of the CO(advantageously at &#x3c;100&#xb0; C.). Upon COrelease, the regenerated lean solution can be recycled to the sorption tower. CO:(primary+secondary amine) adsorption molar ratios&#x3e;0.5:1 (approaching 1:1) may be achieved.

Non-aqueous amine scrubbing for removal of carbon dioxide

Promoter amines are used to enhance COuptake by sterically hindered or tertiary amines. The promoter amines can be cyclic amines, including aromatic cyclic amines or bridged cyclic amines. The combination of a promoter amine plus a sterically hindered or tertiary amines allows for improved uptake kinetics while reducing or minimizing the amount of formation of carbamate salts. The promoted sterically hindered or tertiary amines can be used as part of a COcapture and release system that involves a phase transition from a solution of amine-COproducts to a slurry of amine-COprecipitate solids.

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A liquid aminoether acid gas absorbent which is subject to freezing in a cold climatic zone though which the aminoether is to be shipped is rendered freeze-resistant by mixing the aminoether with water prior to transport through the cold climatic zone; the aminoether/water mixture typically contains 10 to 40 weight percent water, based on the weight of the aminoether. The aminoether/water mixture can also be stored in the cold climatic zone without being externally maintained at a temperature above the inherent freezing point of the aminoether.

Low temperature transport and storage of amine gas treatment solutions

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Westfield, NJ, United States of America

Michael Siskin