Abstract: A method of treating a subterranean formation by contacting the formation with the following: (a) an ammonium compound; (b) an oxidizing agent selected from a perchlorate or a nitrite or combinations thereof; and (c) one or more acids, at least one of which is a bisulfate salt.

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: Loss circulation material (LCM) and method for treating loss circulation in a wellbore in a subterranean formation, including placing the LCM having a solid body with permeable portions or pores into the wellbore to dispose the LCM at the loss circulation zone, and collecting solids onto the LCM at the loss circulation zone to form a barrier. The LCM may be applied at a loss circulation zone in a hydrocarbon reservoir section of the subterranean formation, and upon subsequent hydrocarbon production the collected solids may be dislodged by the produced hydrocarbon to allow for hydrocarbon production through the permeable portions or pores of the disposed LCM.

Abstract: A method of treating a subterranean formation by contacting the formation with the following: (a) ammonium sulfamate; (b) an oxidizing agent selected from a perchlorate or a nitrite or combinations thereof; and (c) an acid.

Abstract: The present invention relates to a hydraulic fracturing fluid composition comprising a homogeneous non-aqueous organic phase mixture which mixture comprises a base fluid and one or more surfactants.

Abstract: Methods of enhancing water injectivity into a subterranean wellbore may include injecting a first composition comprising nitrate anions having a nitrate concentration into a target zone of the subterranean wellbore; injecting a second composition comprising nitrate anions into the target zone of the subterranean wellbore, where the second composition has a nitrate concentration of from about 20% to about 70% the nitrate concentration of the first composition; optionally injecting a third composition comprising nitrate anions into the target zone of the subterranean wellbore, where the third composition has a nitrate concentration of from about 20% to about 70% the nitrate concentration of the second composition; and injecting water, where the water injection pressure is reduced by about 5% to 25% compared to the water injection pressure in an untreated subterranean wellbore, where the nitrate anions are reduced by bacteria present in the subterranean wellbore.

Abstract: A method for the use of a monocarboxylic acid composition additive to inhibit formation of naphthenic deposits from crude oil is described. The invention provides for the inhibition of naphthenic using environmentally acceptable compositions, reducing waste water contamination. In use of the monocarboxylic acid compositions, the requirements for further additives, such as emulsion breakers, may also be reduced or eliminated.

Abstract: Foaming fluid composition and methods for enhanced oil recovery are provided with enhanced foaming properties. The foaming composition may include a surfactant and Allium sativum oil where Allium sativum oil may be included in an amount ranging from 20 to 75 vol % in respect to the total volume of the surfactant and the Allium sativum oil. Methods of enhancing recovery of oil from an oil containing formation are also provided. Methods may include injecting a foaming composition into the oil containing formation, where the foaming composition may include a surfactant and Allium sativum oil. Methods may also include the foaming composition that includes Allium sativum oil in an amount ranging from 20 to 75 vol % in respect to the total volume of the surfactant and the Allium sativum oil.

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 includes injecting an aqueous-based injection fluid into a wellbore at a first temperature, where the aqueous-based injection fluid includes phase-changing nanodroplets having a liquid core and a shell. The method also includes exposing the phase-changing nanodroplets to a second temperature in the wellbore that is greater than or equal to a boiling point of the liquid core to change a liquid in the liquid core to a vapor phase and expand the phase-changing nanodroplets, thus removing debris from the wellbore and surrounding area.

Abstract: An additive composition for improving one or more cold temperature properties in oil-based fluids is provided. One additive composition may include a first additive component selected from at least one alcohol ethoxylate, at least one amine ethoxylate, at least one ethylene oxide/propylene oxide copolymer, or a combination thereof, wherein the first additive component has an HLB ranging from about 4 to about 10. The additive composition may also include a second additive component selected from at least one alcohol, propylene glycol, at least one alcohol ethoxylate, or a combination thereof, wherein the second additive component has a total number of carbons from about 2 to about 30 carbons and a degree of ethoxylation is from zero to about 10.

Abstract: Multiple charged cationic compounds, which are derived from polyamines through an aza-Michael addition with an ?, ?-unsaturated carbonyl compound, in a clay treatment composition to reduces clay swelling, clay migration, and sludge formation in a subterranean formation in oil and gas operations are provided. The disclosed methods or compositions are found to be more effective than those methods or compositions commonly used for reducing clay swelling, clay migration, and sludge formation.

Abstract: Methods of cementing include providing a geopolymer cement composition that includes a monophase amorphous hydraulic binder material (MAHBM), a metal silicate, an alkaline activator, and a carrier fluid, introducing the geopolymer cement composition into a subterranean formation, and allowing the geopolymer cement composition to set in the subterranean formation. The MAHBM includes silica or alumina core particulates coated with an amorphous calcium silicate hydrate.

Abstract: A method of cementing may include preparing a cement composition comprising: cementitious components comprising: a cement; a supplementary cementitious material; and nanoparticulate boehmite; and water; and introducing the cement composition into a subterranean formation.

Abstract: Some reservoirs have tight oil formations, such as the Changqing reservoir. The surfactant polymer flooding and low tension gas flooding are two potential chemical flooding methods for use in tight oil formations. In these methods, an oil displacement agent, or surfactant, is added. Nonionic surfactants with extended chains (by propylene oxide and ethylene oxide) from dialkyl alcohols or dialkyl amines were tested. A synergistic blend of surfactants was developed between the nonionic surfactants and anionic surfactants that lowers interfacial tension and improves surfactant solubility in water and oil.

Abstract: Provided are compositions and methods that use a true crystallization temperature reduction additive in the aqueous internal phase. An example method may comprise providing an oil-based treatment fluid in the form of an invert emulsion comprising an aqueous internal phase and an oil external phase. The aqueous internal phase may include a bromide brine and a true crystallization temperature reduction additive, wherein the bromide brine has a density of about 14.2 lbs/gal or greater. The method may further include placing the oil-based treatment fluid into a wellbore.

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: Method of making and using a proppant from captured carbon in either a carbon mineralization process or in a carbon nanomaterial manufacturing process, followed by treatments to ensure the quality control of the proppants so that they are suitable for use in hydraulic and other reservoir fracturing methods.

Abstract: A method of servicing a wellbore may comprise providing a treatment fluid comprising a carrier fluid and hollow particles, wherein the hollow particles may comprise an outer wall that encapsulates a gas. The method may further comprise introducing the treatment fluid into a wellbore annulus and trapping at least a portion of the treatment fluid in the wellbore annulus. The carrier fluid may degrade the outer wall of the hollow particles in the wellbore annulus and release the encapsulated gas.

Abstract: A wellbore fluid may include a non-oleaginous internal phase, an oleaginous external phase, and an emulsifier having a molecular weight of at least 700 daltons, whereby the emulsifier may include at least one tertiary amine. A method of completing a wellbore operation may include injecting a wellbore fluid downhole, the wellbore fluid including a non-oleaginous internal phase, an oleaginous external phase, and an emulsifier having a molecular weight of at least 700 daltons. The emulsifier may include at least one tertiary amine. The method may further include injecting a wash fluid comprising a protonating agent downhole.