There is provided a process for the production of low temperature curable proppant particles. The process includes: heating particles; adding a resin to coat the particles with the resin; partially curing the resin; and adding 0.1-2.0 parts of surfactant per 100 parts of the particles.

There is provided a process for the production of low temperature curable proppant particles. The process includes: heating particles; adding a resin to coat the particles with the resin; partially curing the resin; and adding 0.1-2.0 parts of surfactant per 100 parts of the particles.

The present disclosure relates to material for use in oil and gas well completion activities. More particularly, the present disclosure relates to diversion particles, along with methods for making and using the diversion particles. In an embodiment, a composite diversion material includes a non-degradable component comprising two or more non-degradable particulates, wherein the non-degradable particulates have a long term permeability at 7,500 psi of at least about 20 D. The composite diversion material includes a degradable component surrounding at least a portion of the non-degradable component. In another embodiment, a method of making a composite diversion material includes mixing non-degradable proppant particles with an aqueous solution containing a first degradable material to provide a mixture having a proppant concentration of at least about 20 volume percent. The method includes drying the mixture at a temperature of from about 25° C. to about 200° C. to provide the composite diversion material.

A composition for use as a pressure-tolerant dual-crosslinker gel in a fracturing fluid that comprises polymer, the polymer operable to increase the viscosity of a fluid; boron-containing crosslinker, the boron-containing crosslinker operable to crosslink the polymer; and a transition metal oxide additive, the transition metal oxide additive operable to crosslink the polymer.

A scale inhibitor fluid includes 0.001 ppm to 100 ppm of a phosphonate compound, 20 ppm to 400 ppm of a cation-containing surfactant, and an aqueous fluid. The cation-containing surfactant includes at least one of a single positively charged cation-containing surfactant, a double positively charged cation-containing surfactant and a zwitterionic cation-containing surfactant. A method for inhibiting scale formation in a wellbore includes introducing a phosphonate compound, a cation-containing surfactant and an aqueous fluid to the wellbore to produce a scale inhibitor fluid.

A scale inhibitor fluid includes 0.001 ppm to 100 ppm of a phosphonate compound, 20 ppm to 400 ppm of a cation-containing surfactant, and an aqueous fluid. The cation-containing surfactant includes at least one of a single positively charged cation-containing surfactant, a double positively charged cation-containing surfactant and a zwitterionic cation-containing surfactant. A method for inhibiting scale formation in a wellbore includes introducing a phosphonate compound, a cation-containing surfactant and an aqueous fluid to the wellbore to produce a scale inhibitor fluid.

Drilling fluid compositions may include a weighting agent, a nitrite-containing compound, and an ammonium-containing compound, where the nitrite-containing compound and the ammonium-containing compound may be encapsulated together in copolymer micro-particles forming encapsulated thermochemical compounds, and where at least one property selected from the group consisting of the density, the plastic viscosity, the yield point, the gel strength, and the pH, of the drilling fluid composition may be substantially similar to the at least one property of a comparable drilling fluid composition devoid of the encapsulated thermochemical compounds. Methods for reducing a filter cake from a wellbore surface in a subterranean formation are also provided. The methods may include introducing into the wellbore the drilling fluid compositions, allowing the drilling fluid composition to reach a temperature in the wellbore sufficient for the encapsulated thermochemical compounds to react, where the reaction of the encapsulated thermochemical compounds generates heat and nitrogen gas.

Drilling fluid compositions may include a weighting agent, a nitrite-containing compound, and an ammonium-containing compound, where the nitrite-containing compound and the ammonium-containing compound may be encapsulated together in copolymer micro-particles forming encapsulated thermochemical compounds, and where at least one property selected from the group consisting of the density, the plastic viscosity, the yield point, the gel strength, and the pH, of the drilling fluid composition may be substantially similar to the at least one property of a comparable drilling fluid composition devoid of the encapsulated thermochemical compounds. Methods for reducing a filter cake from a wellbore surface in a subterranean formation are also provided. The methods may include introducing into the wellbore the drilling fluid compositions, allowing the drilling fluid composition to reach a temperature in the wellbore sufficient for the encapsulated thermochemical compounds to react, where the reaction of the encapsulated thermochemical compounds generates heat and nitrogen gas.

A system includes a well cellar, a wellhead and a colloidal silica gel. The well cellar includes a base and sidewalls extending from the base. The wellhead includes an aboveground region extending above the well cellar and a belowground region in the well cellar. The belowground region of the wellhead includes a wellhead component having an exterior surface. The colloidal silica gel occupies a volume extending from the base and sidewalls of the well cellar to the exterior surface of the wellhead component. The colloidal silica gel covers the exterior surface of the wellhead component.

A well system is provided that includes an injection wellbore having a configuration that traverses an injection formation and has a horizontal configuration. The injection wellbore also has a configuration such that a treatment fluid and a CO2 fluid may be introduced into the injection wellbore and also selectively introduced into a treatment zone. The treatment fluid comprises water and basalt nanoparticles. The injection wellbore has a configuration such that the treatment zone is positioned in a horizontal portion of the injection wellbore. Each treatment zone includes a treatment unit. The treatment unit is configured to selectively introduce a fluid into the treatment zone. The treatment zone is in fluid communication with the injection formation. A method for treating an injection formation includes introducing a treatment fluid into a well system as previously described, selectively introducing the treatment fluid into a treatment zone, and monitoring the injection formation.