Abstract: 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.

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

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

Abstract: A method includes providing a well extending underground from a surface, using radial drilling to drill a primary tunnel extending in an outwardly direction from the well at a first axial location along the well, installing a chemical storage assembly in the primary tunnel, and ejecting chemicals from the chemical storage assembly into the well.

Abstract: A composition includes a polymer having a structure as shown in Formula (I): where x is from 20 to 70, y is from 20 to 30, z is from 1.0 to 10, and p is from 1.0 to 10. A method of making the polymer is also provided. The polymer composition may be used as a wellbore fluid. Also provided is a method of treating a hydrocarbon bearing formation. The method includes introducing the polymer-containing wellbore fluid into a high permeability zone of a hydrocarbon bearing formation such that it blocks at least a portion of the high permeability zone of the hydrocarbon bearing formation, stimulating the hydrocarbon bearing formation thereby creating pathways for hydrocarbon production, and recovering hydrocarbons.

Abstract: 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.

Abstract: 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 R2 is a C15-C27 hydrocarbon group or a C15-C29 substituted hydrocarbon group, R3 is a C1-C10 hydrocarbon 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.

Abstract: 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 Y1, Y2, Y3, Y4 are 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 R2 is a C15-C27 hydrocarbon group or a C15-C29 substituted hydrocarbon group, R3 is a C1-C10 hydrocarbon 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.

Abstract: 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).

Abstract: Provided is a loss circulation material that may consist essentially of an acidic nanosilica dispersion and an activator. The acidic nanosilica dispersion may consist of acidic silica nanoparticles, stabilizer, and water, and may have a pH in a range of 3 to 6. The activator may be one or more from the group consisting of sodium bicarbonate, sodium chloride, or an amine salt. A method is provided for controlling lost circulation in a lost circulation zone in a wellbore comprising introducing the loss circulation material and forming a gelled solid from the loss circulation material in the lost circulation zone.

Abstract: 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 Y1, Y2, Y3, Y4 are 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 R2 is a C15—C27 hydrocarbon group or a C15—C29 substituted hydrocarbon group, R3 is C1—C10 hydrocarbon 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.

Abstract: 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).

Abstract: Provided is a loss circulation material that may consist essentially of an acidic nanosilica dispersion and an activator. The acidic nanosilica dispersion may consist of acidic silica nanoparticles, stabilizer, and water, and may have a pH in a range of 3 to 6. The activator may be one or more from the group consisting of sodium bicarbonate, sodium chloride, or an amine salt. A method is provided for controlling lost circulation in a lost circulation zone in a wellbore comprising introducing the loss circulation material and forming a gelled solid from the loss circulation material in the lost circulation zone.

Abstract: This disclosure relates a method of reducing water production in a wellbore, which may include introducing an alkaline nanosilica dispersion to the wellbore such that it contacts a water producing zone of the wellbore, introducing a sodium bicarbonate activator to the wellbore such that it contacts the alkaline nanosilica dispersion in the water producing zone, and forming a gelled solid from the water shutoff material in the water producing zone, thereby reducing water production in the wellbore.

Abstract: Methods for making a low-density gel or composite in a wellbore are provided. An exemplary method includes injecting a sealer component including a low-density material into the wellbore, allowing the sealer component to float to the top of an oil column, injecting an activator component including another low-density material into the wellbore, allowing the activator component to float to the top of the oil column and contact the sealer component, and contacting the sealer component and the activator component to form a gel.

Abstract: 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 R2 is a C15-C27 hydrocarbon group or a C15-C29 substituted hydrocarbon group, R3 is a C1-C10 hydrocarbon 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.

Abstract: 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 Y1, Y2, Y3, Y4 are 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 R2 is a C15-C27 hydrocarbon group or a C15-C29 substituted hydrocarbon group, R3 is a C1-C10 hydrocarbon 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.

Abstract: 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 R2 is a C15-C27 hydrocarbon group or a C15-C29 substituted hydrocarbon group, R3 is a C1-C10 hydrocarbon 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.

Abstract: 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 Y1, Y2, Y3, Y4 are 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 R2 is a C15-C27 hydrocarbon group or a C15-C29 substituted hydrocarbon group, R3 is a C1-C10 hydrocarbon 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.

Abstract: 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 R2 is a C15-C27 hydrocarbon group or a C15-C29 substituted hydrocarbon group, R3 is a C1-C10 hydrocarbon 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.