A hydrated inorganic oxide material capable of elongating from a planar shape to a fiber shape along a thickness direction of the planar shape, wherein the fiber shape is at least about 25 times greater in the thickness direction than the planar shape, and wherein during elongating a radial dimension of the hydrated inorganic oxide material changes by less than about 10% may be useful in a plurality of wellbore operations. For example, a method may include introducing a wellbore fluid comprising an aqueous base fluid and a hydrated inorganic oxide material into a wellbore penetrating a subterranean formation; and swelling the hydrated inorganic oxide material by contacting the hydrated inorganic oxide material with a polar amine compound such that the hydrated inorganic oxide material elongates from a planar shape to a fiber shape along a thickness direction of the planar shape.

A wellbore fluid comprising a first aqueous base fluid and a plurality of silica nanoparticles suspended in the first aqueous base fluid. The nanoparticles are present in the fluid in an amount to have an effect of decreasing a crystallization temperature by at least 4 to 55° F. as compared to a second aqueous base fluid without the silica nanoparticles.

A polymer gel may comprise a polymer gel base material and superparamagnetic nanoparticles. At least 25 wt. % of the superparamagnetic nanoparticles may have diameters in a first size range between a first diameter and a second diameter. At least 25 wt. % of the superparamagnetic nanoparticles may have diameters in a second size range between a third diameter and a fourth diameter. The Brownian relaxation time of the portion of the superparamagnetic nanoparticles in the first size range may be at least 5 times the Neel relaxation time of the portion of the superparamagnetic nanoparticles in the first size range. The Neel relaxation time of the portion of the superparamagnetic nanoparticles in the second size range may be at least 5 times the Brownian relaxation time of the portion of the superparamagnetic nanoparticles in the second size range. Methods for monitoring gel integrity in a wellbore are further included.

A method for the fracking or stimulation of a hydrocarbon-bearing formation, said method comprising the steps of: providing a wellbore in need of stimulation; inserting a plug in the wellbore at a predetermined location; inserting a perforating tool and a spearhead or breakdown acid into the wellbore; positioning the tool at said predetermined location; perforating the wellbore with the tool thereby creating a perforated area; allowing the spearhead acid to come into contact with the perforated area for a predetermined period of time sufficient to prepare the formation for fracking or stimulation; removing the tool form the wellbore; and initiating the fracking of the perforated area using a fracking fluid.

Also disclosed is a corrosion inhibiting composition for us with the acid composition.

A hydrocarbon-based or ester-based drilling fluid or mud is described wherein the drilling fluid contains cesium phosphate. The hydrocarbon-based or ester-based drilling fluid or mud can have, for example, an external phase that contains hydrocarbon fluid and an internal phase that contains cesium phosphate. The hydrocarbon-based drilling fluid or mud can further contain at least one emulsifier or surfactant, and optionally other ingredients. The present invention can permit hydrocarbon-based drilling fluids to be essentially solids-free and may be used without corrosion and/or formation damage problems, for example, due to the use of the cesium phosphate in an internal phase of the hydrocarbon-based or ester-based drilling fluid. The present invention also relates to hydrocarbon-based or ester-based fluids for completion, workover, suspension and packer operations which contain cesium phosphate.

Provided is an injection fluid that may include a nanoemulsion having an oil phase dispersed in an aqueous phase, and non-superparamagnetic magnetic nanoparticles that are present in the dispersed oil phase. Further provided is a method for preparing an injection fluid that may include preparing a nanoemulsion from an aqueous phase and an oil phase having non-superparamagnetic magnetic nanoparticles therein, and may be used to form nanodroplets of the non-superparamagnetic magnetic nanoparticles. Further provided is a method for tracking movement of an injection fluid. The method may include introducing a tagged injection fluid into a hydrocarbon-containing reservoir, the tagged injection fluid may be a nanoemulsion that includes: an aqueous phase, an oil phase dispersed in the aqueous phase, and non-superparamagnetic nanoparticles that are present in the dispersed oil phase; and tracking the movement of the tagged injection fluid.

Mineral particles may provide for wellbore fluids with tailorable properties and capabilities. In some instances, a dry wellbore additive may comprise a plurality of first mineral particles having a specific gravity of about 2.6 to about 20; a plurality of second mineral particles having a specific gravity of about 5.5 to about 20; a plurality of lubricant particles having a specific gravity of about 2.6 to about 20; wherein the first mineral particles, the second mineral particles, and the lubricant particles are different; and wherein the first mineral particles, the second mineral particles, and the lubricant particles have a multiparticle specific gravity of about 3 to about 20.

According to one or more embodiments of the present disclosure, a drilling fluid may comprise one or more deep eutectic solvents in an amount greater than or equal to 70 wt. % based on the total weight of the drilling fluid. Each deep eutectic solvent may comprise at least one hydrogen bond acceptor compound and at least one hydrogen bond donor compound. A molar ratio of the total moles of the hydrogen bond donor compounds to the total moles of the hydrogen bond acceptor compounds in each deep eutectic solvent may be from 0.1 to 1.0. The drilling fluid may have a density greater than or equal to 200 kg/m.sup.3. The drilling fluid may have a viscosity greater than or equal to 0.5 Pa.Math.s when measured at 25° C. Methods for drilling wells in subterranean formations using the drilling fluid are also disclosed.

Pressure buildup can be extremely problematic during subterranean operations when there is no effective way to vent or otherwise access one or more sealed annuli within a wellbore. This condition can compromise casing integrity and ultimately lead to failure of a well. Methods for mitigating annular pressure buildup can comprise: providing a wellbore containing an annular space having one or more annuli therein; selecting a pressure-mitigating material based upon one or more conditions present within the annular space, the pressure-mitigating material having a negative coefficient of thermal expansion; introducing the pressure-mitigating material into the annular space of the wellbore; sealing at least a portion of the annular space after introducing the pressure-mitigating material thereto; and subjecting the pressure-mitigating material to a temperature increase in the sealed portion of the annular space to decrease a volume occupied therein by the pressure-mitigating material.

Embodiments of the present disclosure are directed to methods of producing charged composite materials. The method may include synthesizing a composite material and charging the composite material to produce a charged composite material. The composite material may include an inorganic composite component and an organic component. The organic component may include one or more primary or secondary amines. The organic component may be covalently bonded to the inorganic composite component. The charged composite material may be positively charged.