Formulations for fracturing fluids that include (i) a fluid (D) including an oil phase in which the fluid (D) is an inverse emulsion including a water-soluble polymer (B) and said oil phase; and (ii) particles of a water-soluble polymer (C), which are different than water-soluble polymer (B), wherein the particles of polymer (C) are dispersed in said oil phase as solid discrete particles. The fluid (D) includes at least 15wt % polymer (B).

An acid treatment composition includes a nonionic surfactant, including nonyl phenol ethoxylate. The acid treatment composition also includes a retarding agent comprising magnesium, an acid, and water. The nonionic surfactant and retarding agent of the acid treatment composition are reactive with carbonate.

Described herein are methods of treating fluid comprising hydrocarbons, water, and polymer being produced from a hydrocarbon-bearing formation are provided. The method can include adding a concentration of a viscosity reducer to the fluid to degrade the polymer present in the fluid and adding a concentration of a neutralizer to the fluid to neutralize the viscosity reducer in the fluid. The viscosity reducer is buffered at a pH of 7 or less (e.g., at a pH of from 2 to 7, such as at a pH of from 3.5 to 7, or at a pH of from 5 to 7). The addition of the concentration of the viscosity reducer is in a sufficient quantity to allow for complete chemical degradation of the polymer prior to the addition of the concentration of the neutralizer in the fluid such that excess viscosity reducer is present in the fluid. The addition of the concentration of the neutralizer is sufficiently upstream of any surface fluid processing equipment to allow for complete neutralization of the excess viscosity reducer such that excess neutralizer is present in the fluid prior to the fluid reaching any of the surface fluid processing equipment.

A method for controlling fluid loss into the pores of an underground formation during fracturing operations is provided. Nanoparticles are added to the fracturing fluid to plug the pore throats of pores in the underground formation. As a result, the fracturing fluid is inhibited from entering the pores. By minimizing fluid loss, higher fracturing fluid pressures are maintained, thereby resulting in more extensive fracture networks. Additionally, nanoparticles minimize the interaction between the fracturing fluid and the formation, especially in water sensitive formations. As a result, the nanoparticles help maintain the integrity and conductivity of the generated, propped fractures.

Cementing compositions containing a hydraulic cement, halloysite nanoparticles, and silica flour. The cementing compositions may optionally include other additives such as a friction reducer, a defoamer, and a fluid loss additive. Cement samples made therefrom and methods of producing such cement samples are also specified. The addition of halloysite nanoparticles and silica flour provides enhanced mechanical strength (e.g. compressive strength, flexural strength) and improved durability (e.g. resistance to CO.sub.2 and salinity) to the cement, making them suitable cementing material for oil and gas wells.

A method and drilling fluid additive for reducing severe fluid losses in a well, comprising a combination of granular scrap tire particles and polymer adhesive molded into a cone shape. Once in the severe loss zone, a plurality of LCMs wedge into the formation fractures and seal off the severe loss zone.

Methods of reducing drag in a flowing hydrocarbon include introducing to the flowing hydrocarbon an amount of a solid drag reducing additive effective to improve the flow, the solid drag reducing additive including a polymer particle prepared from at least one polar monomer and a percent by weight (wt%) of liquid of 50 wt% or less. Methods also include producing a solid drag reducing additive that includes forming a polymer from at least one polar monomer by emulsion polymerization; and disrupting the emulsion by adding at least one demulsifier and at least one anti-blocking agent to form the solid drag reducing additive. Compositions include a solid drag reducing additive comprising a polymer prepared from at least one polar monomer and having an average particle size in a range of about 100 .Math.m to about 500 .Math.m, wherein the solid drag reducing additive comprises less than 50 wt% of liquid.

A method for modifying surface wettability of a surface of a solid substrate may include contacting the surface of the solid substrate with a brine solution containing carbon nanodots. The carbon nanodots may have carbon, oxygen, nitrogen, and hydrogen as constituent elements and may include one or more functional groups disposed at outer surfaces of the carbon nanodots. The brine solution has a salinity of greater than 30,000 TDS. A concentration of carbon nanodots in the brine solution is less than or equal to 500 ppmw. Contacting the solid substrate with the brine solution comprising the carbon nanodots is characterized by a contact duration, a contact volume, or both, that is sufficient to reduce the oil wettability of the surface of the solid substrate by at least 15%, as defined by a contact angle of a crude oil droplet contacted with the surface of the solid substrate.

Emulsions, treatment fluids and methods for treating subterranean formations are provided, wherein the emulsions comprise water, a water-immiscible liquid, one or more polymers, and an inverting surfactant composition comprising one or more surfactants selected from the group consisting of ethoxylated alcohol compounds, ethoxylated fatty acid compounds, and alkyl polyethyleneglycol ether carboxylic acid compounds, and salts or esters thereof. The emulsions are particularly suitable for use in brine.

Implementations described herein generally relate to a drag reducing agent (DRA) for improving flow of crude oils having high asphaltene content through pipelines. The DRA is a terpolymer having a glass transition temperature (T.sub.g) of 6 degrees Celsius or below. The terpolymer is formed by a first monomer, a second monomer, and a third monomer. The first and second monomers are chosen based on the glass transition temperatures of corresponding homopolymers. The glass transition temperature of the homopolymer formed with the first monomer is at least 120 degrees Celsius higher than the glass transition temperature of the homopolymer formed with the second monomer. The DRA comprised of the terpolymer formed with the second monomer produces softer solids and fewer solids due to the low glass transition temperature of the terpolymer. The softer solids are more easily handled by the pump to keep the injection system clear.