Saudi Arabian Oil Company

King Fahd University of Petroleum and Minerals

Case Western Reserve University

Akzo Nobel Chemicals International B.v.

Mohammed Abudullah Bataweel

Rajendra Arunkumar Kalgaonkar

Nisar Ullah

Muhammad Mansha

Eyad Alali

Tao Chen

Fahd Ibrahim Alghunaimi

Hind Saleh Aldossary

Nour Baqader

Feng Liang

Hui-Hai Liu

Ming Han

Ayman Mohammed Almohsin

Qiwei Wang

Hans Olof Lagnemo

Ime Bassey Obot

Jin Huang

Ahmad A Sorour

Bader Ghazi Al-Harbi

Prasad Baburao Karadkar

Mustafa Alkhowaildi

Norah W Aljuryyed

Jose I Rueda

Mumtaz Ahmad Quraishi

Per Anders Restorp

Abdulmohsen A Al-Humam

Mohamed Ahmed Nasr El Din Mahmoud

Ziyuan Qi

Manar A AlAhmari

Jin Ge

Andreas Ake Sundblom

Mona Saad Dossary

Abadi A Mutairi

A method of desulfating seawater includes adding a produced water to a sulfated seawater, forming a first precipitate, separating the first precipitate from the sulfated seawater, measuring the sulfate ion concentration of the desulfated seawater, adding a precipitating agent to the sulfated seawater, and separating a second precipitate from the sulfated seawater. Another method of desulfating seawater includes determining concentrations of sulfates in a sulfated seawater and a precipitating agent in a produced water, adding the produced water to the sulfated seawater based on the determined concentrations of sulfates in the sulfated seawater and the precipitating agent in the produced water, forming a first precipitate, separating the first precipitate from the sulfated seawater, measuring the sulfate ion concentration of the desulfated seawater, adding a precipitating agent to a sulfated seawater, and separating a second precipitate from the sulfated seawater.

Method of sulfate removal from seawater using high salinity produced water

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

A hydraulic fracturing fluid and methods for using the hydraulic fracturing fluid fracturing a formation are provided. An exemplary hydraulic fracturing fluid includes a polymer additive, a breaker, a non-ionic surfactant. The hydraulic fracturing fluid also includes an amphoteric surfactant, or a cationic surfactant, or both, and a base fluid.

Low surface tension surfactant system for enhancing flow-back performance

A method, wellbore, and pill for treating a region of a subterranean formation adjacent a wellbore zone of the wellbore, including injecting a gellable treatment composition (e.g., as the pill) through the wellbore zone into the region of the subterranean formation adjacent the wellbore zone, allowing the gellable treatment composition to form nanoparticles in-situ in the region and gel in the region via heat provided by the region to prevent or reduce flow of an unwanted fluid from the region into the wellbore zone. The gellable treatment composition may include a zwitterionic gemini surfactant (ZGS).

Treatment of subterranean formations

A method of controlling a permeability zone in a reservoir includes introducing a diverter agent comprising a morpholinium based zwitterionic surfactant including a sulfonate terminal moiety, an ammonium-based zwitterionic surfactant, and an activator in a wellbore. Once introduced, the diverter agent contacts a high permeability zone in the reservoir. The diverter agent heats and gels to form a gelled diverter agent in the high permeability zone, subsequently forming a zone of decreased permeability.

Viscoelastic surfactants for acid diversion in downhole operations

A process of treating nano-filtration membrane retentate comprises introducing seawater comprising a sulfate ion concentration of greater than or equal to 3000 mg/l to the NF membrane to produce a retentate stream and a permeate stream, wherein the retentate stream has a sulfate ion concentration greater than or equal to 10,000 mg/l, and mixing barium additives comprising barium chloride dehydrate (BaClHO), barium chloride (BaCl), or both with the retentate stream to precipitate sulfate from the retentate stream to form barite (BaSO) and reduce the sulfate ion concentration, wherein the barium additives are added into the retentate stream at a barium ion concentration of greater than 10,000 mg/l.

Method to treat nano-filtration membrane retentate for reuse in fracturing and drilling applications

Methods for treating a formation may include introducing components of a treatment solution into a wellbore such that the treatment solution contacts the formation to be treated, where the treatment solution may include urea, urease, a calcium ion source, one or more polysaccharides, a casein protein, a protease, an ionic compound, and a sugar, where the formation may have an amount of sand production before treatment and may be in fluid contact with the wellbore, and where an amount of sand production after treatment may be less than the amount of sand production before treatment. Consolidated sand structure compositions may include previously unconsolidated sand interlinked by inter-particle cementitious bonds comprising deposited calcium carbonate crystals, where the consolidated sand has a structural strength and the consolidated sand structure is porous to permit fluid flow through the composition.

Sand consolidation by enzyme mediated calcium carbonate precipitation

A composition for inhibiting corrosion in gas wells includes a pyrazolopyridine derivative. The pyrazolopyridine derivative includes a pyridyl moiety, a first pyrazole moiety, a second pyrazole moiety, and a phenyl moiety. The first pyrazole moiety is bound to the pyridyl moiety. The second pyrazole moiety is bound to the pyridyl moiety. The phenyl moiety is bound to the pyridyl moiety. The composition can be flowed into a wellbore formed in a subterranean formation, thereby inhibiting corrosion in the wellbore.

Inhibiting corrosion in gas wells

A diverter agent includes a morpholinium based zwitterionic surfactant having a sulfonate terminal moiety; and an ammonium based zwitterionic surfactant.

Methods and materials for wellbore fluid diversion using visco-elastic surfactants

A composition for a fracturing fluid may include a chelating agent, a polymeric gelling agent, and a base fluid. The base fluid in the fracturing fluid composition may be a produced fluid having a hardness content of at least 7,000 ppm. Method for treating a hydrocarbon-bearing formation may include introducing a fracturing fluid in the hydrocarbon-bearing formation. The fracturing fluid contains a chelating agent, a polymeric gelling agent, and a base fluid. The base fluid may be a produced fluid that has a hardness content of at least 7,000 ppm. The fracturing fluid may have a viscosity of at least 200 cp at 150° F., 100 1/s shear rate, and 300 psia when tested using model 5550 HPHT rheometer. After contacting the hydrocarbon-bearing formation, the viscosity of the fracturing fluid may drop near a range of 1 cP to 5 cP.

Fracturing fluid based on oilfield produced fluid

A fracturing fluid may include a first surfactant and a second surfactant. The first surfactant may have a structure represented by formula (I): wherein m is an integer ranging from 2 to 3, and n, o, and k are each, independently, integers ranging from 2 to 10. The second surfactant having a structure represented by Formula (II): wherein Ris a C-Chydrocarbon group or a C-Csubstituted hydrocarbon group, Ris a C-Chydrocarbon group, and p and q are each, independently, an integer ranging from 1 to 4. Methods of treating a hydrocarbon-bearing formation include injecting the fracturing fluid in the hydrocarbon-bearing formation, the fracturing fluid being configured to transport a proppant in fractures of the hydrocarbon-bearing formation.

Fracturing fluids based on viscoelastic surfactants

A wellbore fluid including a first surfactant, a second surfactant, an activator and an aqueous base fluid is provided. The first surfactant has a structure represented by Formula (I): where Y, Y, Y, Yare each, independently, a sulfonate, a carboxylate, an ester or a hydroxyl group, m is an integer ranging from 2 to 3, and n, o, and k are each, independently, integers ranging from 2 to 10. The second surfactant has a structure represented by Formula (III): where Ris a C-Chydrocarbon group or a C-Csubstituted hydrocarbon group, Ris a C-Chydrocarbon group, and p and q are each, independently, an integer ranging from 1 to 4. A method of using the wellbore fluid for treating a hydrocarbon-containing formation is also provided.

Methods and compositions of piperazine-based viscoelastic surfactants as diversion agents

A wellbore fluid including a first surfactant, a second surfactant, an activator and an aqueous base fluid is provided. The first surfactant has a structure represented by Formula (I): where Y, Y, Y, Yare each, independently, a sulfonate, a carboxylate, an ester or a hydroxyl group, m is an integer ranging from 2 to 3, and n, o, and k are each, independently, integers ranging from 2 to 10. The second surfactant has a structure represented by Formula (III): where Ris a C&#x2014;Chydrocarbon group or a C&#x2014;Csubstituted hydrocarbon group, Ris C&#x2014;Chydrocarbon group, and p and q are each, independently, an integer ranging from 1 to 4. A method of using the wellbore fluid for treating a hydrocarbon-containing formation is also provided.

Piperazine-based viscoelastic surfactants for hydraulic fracturing applications

A wellbore fluid including a first surfactant, a second surfactant, an activator and an aqueous base fluid is provided. The first surfactant has a structure represented by Formula (I): where m is an integer ranging from 2 to 3, and n, o, and k are each, independently, integers ranging from 2 to 10. The second surfactant has a structure represented by Formula (III): where Ris a C-Chydrocarbon group or a C-Csubstituted hydrocarbon group, Ris a C-Chydrocarbon group, and p and q are each, independently, an integer ranging from 1 to 4. A method for treating a hydrocarbon-containing formation with the wellbore fluid is also provided.

Methods and compositions of using viscoelastic surfactants as diversion agents

A composition useful for subterranean water or gas shut off applications includes organosilane-modified colloidal silica and an accelerator. The accelerator includes one or more organic or inorganic salts. A method of using a composition, including an organosilane-modified colloidal silica and an accelerator, includes forming a fluid system that is flowed to a formation in a subterranean zone, such as through a wellbore, where the composition forms a gel to plug the formation and shut off water flow into the wellbore.

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Dhahran, Saudi Arabia

Mohammed Abudullah Bataweel