Methods and compositions for dissolving a filter cake. An example method introduces a treatment fluid into an annulus of a wellbore penetrating a subterranean formation. The treatment fluid includes an aqueous fluid and a phosphate. The wellbore has a wall that is at least partially coated with a filter cake. The method further removes at least a portion of the filter cake from the wall.

Methods and compositions for dissolving a filter cake. An example method introduces a treatment fluid into an annulus of a wellbore penetrating a subterranean formation. The treatment fluid includes an aqueous fluid and a phosphate. The wellbore has a wall that is at least partially coated with a filter cake. The method further removes at least a portion of the filter cake from the wall.

A breaker composition comprising: (i) an acid precursor, (ii) a delaying agent and (iii) an aqueous fluid wherein the breaker composition has an effective operating temperature range of from about 25° C. to about 180° C. A wellbore servicing system comprising (a) an aqueous-based drilling fluid, wherein the aqueous-based drilling fluid forms water-wet solids in the wellbore; and (b) a breaker composition comprising (i) an acid precursor, (ii) a delaying agent and (iii) an aqueous fluid. A method of dissolving a filtercake comprising contacting the filtercake with a breaker solution comprising (i) an acid precursor, (ii) a delaying agent and (iii) an aqueous fluid wherein the filtercake comprises calcium carbonate.

Methods and systems for the treatment of wells are disclosed. A method for treating a well comprises providing a treatment fluid comprising calcium-aluminate cement, water, and a cement set retarder; and introducing the treatment fluid into a wellbore. A system for treating a well comprises a treatment fluid comprising calcium-aluminate cement, water, and a cement set retarder; a vessel to contain the treatment fluid; a pumping system coupled to the vessel to pump the treatment fluid; and a conduit coupled to the pumping system.

Methods and systems for the treatment of wells are disclosed. A method for treating a well comprises providing a treatment fluid comprising calcium-aluminate cement, water, and a cement set retarder; and introducing the treatment fluid into a wellbore. A system for treating a well comprises a treatment fluid comprising calcium-aluminate cement, water, and a cement set retarder; a vessel to contain the treatment fluid; a pumping system coupled to the vessel to pump the treatment fluid; and a conduit coupled to the pumping system.

A method to produce a brine from mixed alum salts, the method comprising the steps of: (i) Dissolving or pulping alum salts (1) containing rubidium alum, cesium alum and/or potassium alum in water or a recycled liquor and adding a neutralising agent to precipitate (20) aluminium as aluminium hydroxide and some sulfate; (ii) Passing the product of step (i) to a solid liquid separation stage (21) to remove precipitated solids (5) from step (i); (iii) A decant or filtrate (6) from step (ii) is passed to a solvent extraction stage (24-27) whereby any contained cesium and rubidium is selectively extracted into the organic phase to form a loaded organic solution (16); (iv) Contacting the loaded organic solution (16) of step (iii) with a scrub solution (17), which is at a pH lower than the extraction pH, to effectively scrub co-loaded potassium from the organic phase; (v) Contacting the scrubbed organic (19) of step (iv) with formic acid (20) to strip cesium and rubidium from the organic, the stripped cesium and rubidium forming a cesium and/or rubidium sulfate brine (21); and (vi) Recycling the stripped organic (22) of step (v) to the extraction stage (24-27).

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 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.

Producing proppants with nanoparticle proppant coatings includes reacting nanoparticles with at least one of an alkoxysilane solution or a halosilane solution to form functionalized nanoparticles and coating proppant particles with unfunctionalized organic resin, a strengthening agent, and the functionalized nanoparticles to produce the nanoparticle coated proppant. The functionalized nanoparticles include nanoparticles having at least one attached omniphobic moiety including at least a fluoroalkyl-containing group including 1H, 1H, 2H, 2H-perfluorooctylsilane. The strengthening agent comprises at least one of carbon nanotubes, silica, alumina, mica, nanoclay, graphene, boron nitride nanotubes, vanadium pentoxide, zinc oxide, calcium carbonate, or zirconium oxide. Additionally, increasing a rate of hydrocarbon production from a subsurface formation through the use of the nanoparticle coated proppant includes producing a first rate of production of hydrocarbons from the subsurface formation, introducing a hydraulic fracturing fluid into the subsurface formation, and increasing hydrocarbon production by producing a second rate of production of hydrocarbons.

Disclosed is a method for modifying bentonite to allow the bentonite to be useful in drilling mud applications. The method includes the steps of: preparing bentonite local to Saudi Arabia using raw water to remove contaminants from the bentonite; grinding the bentonite to a fine powder; sieving the fine powder to be between about 50 μm and about 150 μm in particle size to produce a sieved fine powder; mixing the sieved fine powder with polyanionic cellulose polymer to produce a modified bentonite composition; adding the modified bentonite composition to water until a homogeneous solution of modified bentonite in water is formed; and allowing the homogeneous solution of modified bentonite in water to rest for about 16 hours to form a composition useful in drilling mud applications.