A method for stimulating production of hydrocarbons from a sandstone formation includes the steps of injecting a stimulation fluid formed from a hydrofluoric acid generating precursor and an oxidizing agent, an ammonium containing compound, and a nitrite containing compound into the sandstone formation, where one or both of the hydrofluoric acid generating precursor and the oxidizing agent comprise a degradable encapsulation. The method further includes maintaining the stimulation fluid, the ammonium containing compound, and the nitrite containing compound in the sandstone formation to initiate reaction and generate heat and nitrogen gas. Upon generation of heat and degradation of the degradable encapsulation, the hydrofluoric acid generating precursor and the oxidizing agent react to form hydrofluoric acid in-situ to dissolve silica and silicate minerals and stimulate the sandstone formation. A treatment fluid for use in stimulating sandstone formations includes the stimulation fluid, the ammonium containing compound, and the nitrite containing compound.

A method of treating a well comprising introducing a well treatment fluid into the well, and a well treatment fluid, are provided. The well treatment fluid comprises an aqueous base fluid, sepiolite clay, and a polymer component selected from the group of an acryloylmorpholine polymer, a polyvinylpyrrolidone polymer, and mixtures thereof. In one embodiment, for example, the method is a method of drilling a well. In this embodiment, the well treatment fluid is a drilling fluid.

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): ##STR00001## where Y.sub.1, Y.sub.2, Y.sub.3, Y.sub.4 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): ##STR00002## where R.sub.2 is a C.sub.15—C.sub.27 hydrocarbon group or a C.sub.15—C.sub.29 substituted hydrocarbon group, R.sub.3 is C.sub.1—C.sub.10 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.

A system for utilizing oolitic aragonite as a proppant in hydraulic fracking is provided. The system includes a proppant storage tank including a stockpile of the oolitic aragonite. The system further includes a proppant pumping unit operable to pump the oolitic aragonite from the proppant storage tank, through an underground shaft, and into an underground fracture proximate to the underground shaft.

The disclosure is directed to a process for treating a subterranean earth formation by introducing a buffered acidizing treatment fluid comprising a monovalent salt of monochloroacetic acid and at least one acid into said subterranean earth formation, wherein the pH of the buffered acidizing treatment fluid is from about 1.2 to about 5. It also pertains to a buffered acidizing treatment fluid comprising a monovalent salt of monochloroacetic acid, at least one acid and optionally an element to suppress salt precipitation.

Compositions of lost circulation materials and methods for using the same in subterranean formations can include introducing a treatment fluid into a wellbore penetrating at least a portion of a subterranean formation including a loss zone, the treatment fluid including an aqueous base fluid, at least one viscoelastic surfactant, at least one component selected from the group consisting of: a divalent salt, a metal salt, a metal oxide, and any combination thereof, and a lost circulation material; and allowing the treatment fluid to at least partially plug the loss zone.

The invention relates to a wellbore fluid, which is a monovalent brine comprising one or more alkali bromide salt(s) and one or more TCT-reducing additive(s) selected from the group consisting of alkali nitrates. A method of treating a subterranean formation, comprising placing the wellbore fluids of the invention in a wellbore in the subterranean formation is also provided.

Release of hydrochloric acid, hydrofluoric acid and fluoroboric acid into a well may be controlled by introducing into the well an aqueous fluid containing ammonium chloride, ammonium bifluoride, ammonium fluoroborate, ammonium tetrafluoroborate or a mixture thereof and a breaker. After being introduced into the well, the ammonium salt reacts with the breaker and the acid is released into the well.

Compositions and methods for use in fracturing treatments using friction reducing additives that include nanoparticles are provided. In some embodiments, the methods include: providing a treatment fluid that includes an aqueous base fluid and a friction reducing additive, the friction reducing additive including at least one polymer and a plurality of nanoparticles; and introducing the treatment fluid into a portion of a subterranean formation at or above a pressure sufficient to create or enhance at least one fracture in the subterranean formation.

Well treatment operation comprises introducing nanosized particulates into a formation. The nanosized particulates are synthesized by combining PMIDA, a calcium source, a pH adjusting agent, and an aqueous medium. This combination results in a degradable (i.e., dissolvable) solid that can be used in heterogeneous formations like shale type rock reservoirs, as well as sedimentary rock formations like clastic, siliclastic, sandstone, limestone, calcite, dolomite, and chalk formations, and formations where there is large fluid leak-off due to stimulation treatments. The disclosed particulates may also be used for acidizing treatments in mature fields and deep water formations commonly characterized by high permeability matrices. The solubility of the particulates advantageously allows the material to act as a temporary agent having a lifespan that is a function of temperature, water flux, and pH, making it adaptable to various reservoir conditions with minimal to no risk of adverse effects on the reservoir.