Saudi Arabian Oil Company

Halliburton Energy Services, Inc.

Aramco Services Company

The City University of New York

Case Western Reserve University

William Marsh Rice University

Feng Liang

Leiming Li

B Raghava Reddy

Ghaithan Al-Muntasheri

Philip D Nguyen

Loan K Vo

Jason R Cox

Hooisweng Ow

Rajesh Kumar Saini

Martin E Poitzsch

Tao Chen

Wenwen Li

Bradley Leon Todd

James William Ogle

Yanhui Han

Jilin Jay Zhang

Michael Linley Fripp

Jimmie Dean Weaver, Jr

Thomas Donovan Welton

Ashok K Santra

Ronnie Glen Morgan

Zachary William Walton

Zachary R Murphree

Russell M Fitzgerald

Hui-Hai Liu

Mohammed Sayed

Mohammed Abdullah Bataweel

Stanley J Heath

Amy J Cairns

Jinhong Chen

Gary P Funkhouser

Peter James Boul

Robert H Hauge

Anil Sadana

Lewis R Norman

Jeremy A Holtsclaw

Phillip C Harris

Wengang Li

Jin Huang

Tingji Tang

Fakuen Frank Chang

Sehmus Ozden

Christopher R Parton

George John

Abdulrahman F Alharbi

Hejian Sun

Vidyasagar Adiyala

Dwight David Fulton

Bitao Lai

Jose I Rueda

Hui Hai Liu

Khalid Mohammed Alruwaili

Mohammad Hamidul Haque

David Michael Loveless

Narongsak Tonmukayakul

Mohammed Abudullah Bataweel

Ping Sui

David Leon Meadows

Corneliu Stanciu

Jeff T Fleming

Huseyin Onur Balan

David Patrick Duckworth

Diana Rasner

Ghaithan A Al-Muntasheri

Nam Mai

W Edward Billups

Weishu Zhao

Adrian Buenrostro

Jin Ge

Hung Q Truong

Tanner W Green

Rocky M Fitzgerald

A treatment fluid and method for water shut-off applications containing an amine-functionalized solid support, an epoxy resin, a second curing agent, and a carrier fluid. Prior to use of the treatment fluid, the amine-functionalized solid support has reacted with carbon dioxide to produce a carbamate-functionalized solid support. The treatment fluid is introduced into a geological formation with high-permeability pathways, curing the epoxy resin, and sealing these pathways.

Carbon dioxide capturing polymeric system for water shutoff applications

A method for developing a procedure for pretreating a section of a wellbore prior to hydraulic fracturing stimulation of the section of the wellbore includes determining an optimized notch geometry and determining an optimized chemical treatment for the section of the wellbore. The optimized notch geometry is determined by modeling a notch in the section of the wellbore using a computing system, simulating a pressure increase in the section of the wellbore and on the notch from a hydraulic fracturing stimulation, identifying breakdown pressure in the section of the wellbore, and repeating the modeling, simulating, and identifying to determine the optimized notch geometry in the wellbore as the notch having a lowest breakdown pressure. The optimized chemical treatment is determined by determining a rock type in the section of the wellbore and determining a conditioning fluid that reduces the tensile strength of the rock type.

Workflow for optimizing engineering procedure to reduce borehole breakdown pressure by combination of oriented notching/perforation and fluid chemical conditioning process in open and cased hole

One or more embodiments relates to a productive consolidated sand pack product. The sand pack product may be a cured resin that is bound to sand particles and has a porous structure. The sand pack product is obtained from curing a resin composition which may include a resin, a curing agent, a chemical blowing agent, a surfactant, a carrier fluid, a pH agent, and a salt. The porous volume may include one or more of trapped gas, bubbles, and open or connected pore space.

Blowing agent incorporated resin systems for consolidating subterranean oil and gas bearing formations

Wellbore treatment fluids are provided that include an aqueous component and an amphiphilic hyperbranched copolymer comprising the polymerized reaction product of at least a first monomer and a second monomer, where the first monomer comprises at least one surface reactive end group chosen from the group consisting of carboxylates, phosphonates, sulfonates, and zwitterions. Also provided are methods of modifying subsurface energy of a carbonate formation using the wellbore treatment fluids.

Wellbore treatment fluids comprising an amphiphilic hyperbranched copolymer

Methods and systems including a composition of a hydratable polymer slurry comprising a hydrocarbon-based solvent. The hydrocarbon-based solvent includes a hydratable polymer powder and at least one of a polar surfactant, a hydrocarbon-soluble polymer, and/or an organophilic clay, wherein the polymer slurry is prepared at a temperature greater than 22° C. by mixing.

Reduced-polymer-loading, high-temperature fracturing fluids and methods and systems related thereto

In accordance with one or more embodiments of the present disclosure, a low-density treatment fluid includes a base water-control system and at least one light-weight filler material. The base water-control system may include an inorganic material system comprising an aqueous colloidal silica and a water-soluble chemical activator for gelling the colloidal silica, or the base water-control system may include an organic material system comprising of polymeric material. The low-density treatment fluid may have a density of from 0.1 g/cmto 0.75 g/cm. Also described are methods of recovering a target fluid from a subterranean cavity using such a low-density treatment fluid.

Low-density treatment fluid and methods for treating thief zones located above pay zones

This disclosure relates to a fracturing fluid including an acrylamide-based copolymer, a graphene oxide additive, and a crosslinker, and methods of using the fracturing fluid to reduce fluid friction during treatment of a subterranean formation.

Water-soluble graphene oxide nanosheet assisted high temperature fracturing fluid

A method and a system for consolidating a subterranean formation are provided. An exemplary method includes injecting a water-in-oil emulsion into an unconsolidated subterranean formation, wherein the water-in-oil emulsion includes comonomers in an oil phase to form a polyurethane resin, and a catalyst in an aqueous phase. The method also includes allowing the polyurethane resin to cure to form a porous polymeric network.

Porous polyurethane for consolidation of material in subterranean formations

A treatment fluid composition includes a carrier fluid and a curable hybrid resin. The curable hybrid resin includes a first curable resin (A) including a reactive silyl group that reacts with water downhole, a second curable resin (B), and a curing agent for the second curable resin (B). A method of treating a subterranean formation includes injecting a treatment fluid including a curable hybrid resin into a target zone of the subterranean formation. The target zone may have unconsolidated or weakly consolidated sand. The method then includes maintaining the treatment fluid in the target zone for a period of time such that the curable hybrid resin cures and forming a consolidated formation in the target zone.

Curable hybrid chemical resin for sand consolidation

A method is used to determine the permeability of a hydraulic fracture. The method includes obtaining formation parameters and a plurality of formation samples, dividing the plurality of formation samples into a first group and a second group, measuring mechanical and hydraulic properties of the first group, soaking the second group in a fracturing fluid for a plurality of time periods, and measuring, after each soaking time period, the mechanical and hydraulic properties of the second group. The soaking the second group in the fracturing fluid includes soaking the second group in a plurality of different fracturing fluids. The method further includes building, using a computer processor, a proppant-rock interaction model based, at least in part, on the mechanical and hydraulic properties of the first group and the second group, and determining, using the computer processor, the permeability of a hydraulic fracture based, at least in part, on the proppant-rock interaction model and the formation parameters.

Workflow to evaluate the time-dependent proppant embedment induced by fracturing fluid penetration

A method for determining SRV and EUR includes: monitoring an amount and a density of a hydrocarbon fluid produced from the production well; obtaining a cumulative amount of the fluid that has accumulated from a beginning of production; obtaining a relationship between the cumulative amount and a square root of the time; determining a deviation point where the relationship changes from linear to non-linear; determining a deviation amount of the fluid corresponding to the deviation point; determining a first density of the hydrocarbon fluid at the beginning of production, a second density at a pore pressure equal to a bottom hole pressure in the production well, a first porosity at the beginning of production, and a second porosity for a pore pressure equal to the bottom hole pressure; and determining SRV and the EUR based on the deviation amount, the first and second densities, and the first and second porosities.

Determination of stimulated reservoir volume and estimated ultimate recovery of hydrocarbons for unconventional reservoirs

A silicon oxide Janus nanosheets relatively permeability modifier (RPM) for carbonate and sandstone formations. The silicon oxide Janus nanosheets RPM may be used to treat a water and hydrocarbon producing carbonate or sandstone formation to reduce water permeability in the formation and increase the production of hydrocarbons. The silicon oxide Janus nanosheets RPM for carbonate formations includes a first side having negatively charged functional groups and a second side having alkyl groups. The silicon oxide Janus nanosheets RPM for sandstone formations includes a first side having positively charged functional groups and a second side having alkyl groups. The negatively charged functional groups may include a negatively charged oxygen group groups and hydroxyl groups. The positively charged functional groups may include amino groups and an amine. Methods of reducing water permeability using the silicon oxide Janus nanosheets RPM and methods of manufacturing the silicon oxide Janus nanosheets RPM are also provided.

Silicon dioxide Janus nanosheets relative permeability modifier (RPM) for reducing subterranean formation water permeability in carbonate and sandstone formations

A chemical gel system having a polymer and a silicon oxide Janus nanosheets crosslinker for treating thief zones in carbonate formations. The polymer and silicon oxide Janus nanosheets crosslinker may form a crosslinked polymer gel to reduce or prevent water production via thief zones during hydrocarbon production. The silicon oxide Janus nanosheets crosslinker includes a first side having negatively charged functional groups and a second side having amines. The negatively charged functional groups may include negatively charged oxygen groups and hydroxyl groups. Methods of reducing water production in a thief zone using the silicon oxide Janus nanosheets crosslinker and methods of manufacturing the silicon oxide Janus nanosheets crosslinker are also provided.

Methods and compositions for treating thief zones in carbonate formations using crosslinked polymeric systems with silicon dioxide janus nanosheets crosslinker

A chemical gel system having a polymer and a graphene oxide Janus nanosheets crosslinker for treating thief zones in carbonate formations. The polymer and graphene oxide Janus nanosheets crosslinker may form a crosslinked polymer gel to reduce or prevent water production via thief zones during hydrocarbon production. The graphene oxide Janus nanosheets crosslinker includes a first side having negatively charged functional groups and a second side having amines. The negatively charged functional groups may include carboxyl groups, negatively charged oxygen groups, and hydroxyl groups. Methods of reducing water production in a thief zone using the graphene oxide Janus nanosheets crosslinker and methods of manufacturing the graphene oxide Janus nanosheets crosslinker are also provided.

Methods and compositions for treating thief zones in carbonate formations using crosslinked polymeric systems with graphene oxide Janus nanosheets crosslinker

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Feng Liang