A method of treating a subterranean formation including combining an aqueous fluid, a biomaterial, an enzyme, and a deactivator to form a treatment fluid; and introducing the treatment fluid into the subterranean formation. A method is also disclosed for treating a subterranean formation by preparing a treatment fluid containing an aqueous fluid that contains bacterial and/or fungal cells that produce an enzyme that degrades the biomaterial, a biomaterial, and a deactivator; controlling degradation of the biomaterial by adding an effective amount of the deactivator to the aqueous fluid prior to the preparation of the treatment fluid; and introducing the treatment fluid into the subterranean formation. In the methods, the enzyme degrades the biomaterial and the deactivator is an oxygen-containing arene capable of inhibiting the enzyme from degrading the biomaterial.

Methods, compositions, and systems that use hydrogels of graft polymers for diversion of acidic treatment fluids in subterranean formations. A method for acid diversion may comprise: applying a first acidizing treatment to a first treatment zone of a subterranean formation; introducing a hydrogel to the first treatment zone, wherein the hydrogel comprises a graft polymer that is crosslinked; and applying a second acidizing treatment to the subterranean formation, wherein the hydrogel diverts the second acidizing treatment to a second treatment zone.

Methods and compositions for treatment fluids that include carbonate and bicarbonate to control pH for use in subterranean treatments are provided. In one embodiment, the methods comprise providing a treatment fluid comprising an aqueous base fluid; a crosslinkable polymer; a crosslinking agent; and an amount of carbonate and an amount of bicarbonate, wherein the molar ratio of the amount of carbonate to the amount of bicarbonate is in the range of from about 1:2.3 to about 1:2.7; and introducing the treatment fluid into a wellbore penetrating at least a portion of a subterranean formation.

Well treatments that use modified biopolymers for diversion, conformance, fluid loss control, and/or other well treatments, including a method of providing conformance, fluid loss control, or diversion in a subterranean formation, comprising: providing a treatment fluid comprising a base fluid and hydrogel particles, wherein the hydrogel particles comprise modified biopolymers that are crosslinked, the modified biopolymers comprising a biopolymer backbone and a side chains derived from synthetic monomers; and introducing the treatment fluid into a subterranean formation penetrated by a wellbore.

A hydrocarbon formation treatment micellar solution fluid and its use in treating underperforming hydrocarbon formations is described and claimed. A hydrocarbon formation treatment micellar solution fluid wherein the micellar solution fluid comprises water, a non-terpene oil-based moiety, a brine resistant aqueous colloidal silica sol; and optionally a terpene or a terpenoid, wherein the brine resistant aqueous colloidal silica sol has silica particles with a surface that is functionalized with at least one moiety selected from the group consisting of a hydrophilic organosilane, a mixture of hydrophilic and hydrophobic organosilanes, or a polysiloxane oligomer, wherein the brine resistant aqueous colloidal silica sol passes at least two of three of these brine resistant tests: API Brine Visual, 24 Hour Seawater Visual and API Turbidity Meter, and wherein, when a terpene or terpenoid is present, the ratio of total water to terpene or terpenoid is at least about 15 to 1.

A brine resistant silica sol is described and claimed. This brine resistant silica sol comprises an aqueous colloidal silica mixture that has been surface functionalized with at least one moiety selected from the group consisting of a monomeric hydrophilic organosilane, a mixture of monomeric hydrophilic organosilane(s) and monomeric hydrophobic organosilane(s), or a polysiloxane oligomer, wherein the surface functionalized brine resistant aqueous colloidal silica sol passes at least two of three of these brine resistant tests: API Brine Visual, 24 Hour Seawater Visual and API Turbidity Meter.

A liquid suspension composition for wellbore operations can include a diutan gum, a viscosifier, and a carrier fluid, wherein the diutan gum is suspended in the liquid suspension composition to form a suspended diutan gum. A wellbore servicing fluid can include the liquid suspension composition, and methods of making and using the wellbore servicing fluid.

Degradable particulates may allow for temporary redirection or occlusion of a fluid within a subterranean formation. However, many types of degradable particulates can be problematic for large-scale use, such as during subterranean treatment operations. Methods for treating a subterranean formation using degradable particulates may comprise: providing pre-coated particulates comprising a latently dissolvable core and a transient coating surrounding the latently dissolvable core, the latently dissolvable core and the transient coating comprising different materials; and introducing a treatment fluid comprising a carrier fluid and a plurality of the pre-coated particulates into a wellbore penetrating a subterranean formation in conjunction with a stimulation operation, a material comprising the latently dissolvable core being soluble in the carrier fluid or a formation fluid present within the subterranean formation.

Various embodiments disclosed related to compositions and methods of using the same for treating subterranean formations. In various embodiments, the present invention provides a method of treating a subterranean formation. The method includes placing in a subterranean formation a composition that includes a viscosifier and that also includes a hydrophobically-modified polymer including at least one nitrogen-containing repeating unit.

Wellbore servicing fluid are provided that comprise a viscosifying polymeric material, a breaking agent comprising an inorganic peroxide of a divalent metal M(II) characterized by the general formula MO.sub.2, and a break rate controlling additive comprising a M(II) soluble salt, a M(II) precipitating salt, a M(II) surface precipitating salt, a M(II) solution precipitating salt, or combinations thereof.