Abstract: Methods involving the sequential application of surfactants to improve fluid recovery and control fluid loss in conjunction with subterranean fracturing treatments are provided. In one embodiment, the methods comprise: introducing a first surfactant into a portion of a subterranean formation; allowing the first surfactant to increase the oil-wettability of at least a portion of a fracture face in the portion of the subterranean formation; ceasing the introduction of the first surfactant into the portion of the subterranean formation; introducing a second surfactant into the portion of the subterranean formation; and allowing the second surfactant to increase the water-wettability of the portion of the fracture face in the portion of the subterranean formation.

Abstract: Fracturing methods include introducing a relatively high concentration of a surfactant in an initial portion of one or more fluids used in a fracturing treatment and then cutting or ramping back to a relatively low concentration of the surfactant in the remaining fluid used in the treatment. By using such a method, the volume of surfactant to provide superior treatment can be reduced significantly from the normal recommendations, leading to a high cost savings while still obtaining the desired effect upon cleanup.

Abstract: A wellbore servicing foam comprising a reducible material and a wellbore servicing material, wherein the wellbore servicing material is uniformly dispersed throughout the foam, and wherein the foam has (i) equal to or greater than 5% reticulated structure and (ii) a specific surface area of from about 0.1 m2/g to about 1000 m2/g as determined by pycnometry. A highly expanded, wellbore servicing foam comprising a reducible material and a wellbore servicing material, wherein the wellbore servicing material is uniformly dispersed throughout the foam, wherein the foam has (i) a percentage expansion of from about 5% to about 6200% when compared to the same amount of the same reducible material in the absence of expansion, (ii) a specific surface area of from about 0.1 m2/g to about 1000 m2/g as determined by pycnometry, and (iii) equal to or greater than 5% reticulated structure.

Abstract: A aqueous solution that includes water, from 100,000 to 300,000 ppm of dissolved solids, from 0.5 to 3 gallons per thousand gallons of a water-in-oil emulsion, and an inverting surfactant. The water-in oil emulsion includes an oil phase and an aqueous phase where the oil phase is a continuous phase comprising an inert hydrophobic liquid and the aqueous phase is present as dispersed distinct particles in the oil phase. The aqueous phase contains water, a water soluble polymer, and surfactants. The water soluble polymer includes 30 to 50 weight percent of a non-ionic monomer, 5 to 15 weight percent of a sulfonic acid containing monomer, and 40 to 60 weight percent of a cationic monomer. The water soluble polymer makes up from 10 to 35 weight percent of the water-in-oil emulsion.

Abstract: Ampholyte polymeric compound that comprises at least one nonionic monomer, at least one sulfonic acid-containing monomer, and at least one cationic monomer may be useful in viscosifying treatment fluids for use in subterranean operations at a concentration of about 0.5 v/v % to about 30 v/v % of the treatment fluid. Such operations may involve introducing the treatment fluid into a wellbore penetrating a subterranean formation optionally at a pressure sufficient to create or extend at least one fracture in the subterranean formation.

Abstract: Ampholyte polymeric compounds that comprise at least one nonionic monomer, at least one sulfonic acid-containing monomer, and at least one cationic monomer may be useful as friction reducing agents in treatment fluids for use in subterranean operations at a concentration of about 0.001 v/v % to about 0.5 v/v % of the treatment fluid. Such operations may involve introducing the treatment fluid into a wellbore penetrating a subterranean formation optionally at a rate and/or a pressure sufficient to create or extend at least one fracture in the subterranean formation.

Abstract: A method comprising: providing at least one encaged treatment chemical that comprises a treatment chemical and a polymer carrier; placing the encaged treatment chemical into a portion of a subterranean formation; and allowing the treatment chemical to diffuse out of the encaged treatment chemical and into a portion of the subterranean formation or an area adjacent thereto.

Abstract: Of the many methods provided herein. one method comprises: providing at least a portion of a subterranean formation that comprises a shale; providing a plasticity modification fluid that comprises an aqueous fluid and an alkaline embrittlement modification agent; placing a pack completion assembly neighboring the portion of the subterranean formation; and embrittling at least a portion of the shale to form an embrittled shale portion.

Abstract: Of the many methods provided herein, one method comprises: providing at least one fracture in a subterranean formation that comprises tight gas, a shale, a clay, and/or a coal bed; providing a plasticity modification fluid that comprises an aqueous fluid and an alkaline embrittlement modification agent; placing the plasticity modification fluid into the fracture in the subterranean formation; and embrittling at least one fracture face of the fracture to form an embrittled fracture face.

Abstract: Of the many methods provided herein, one method comprises: providing at least one fracture in a subterranean formation that comprises tight gas, a shale, a clay, and/or a coal bed; providing a plasticity modification fluid that comprises an aqueous fluid and an alkaline embrittlement modification agent; placing the plasticity modification fluid into the fracture in the subterranean formation; and embrittling at least one fracture face of the fracture to form an embrittled fracture face.

Abstract: Methods of treating subterranean formations to reduce bacteria load are provided. Some methods include the steps of providing a treatment fluid, particulates, and tri-n-butyl tetradecyl phosphonium chloride (TTPC) wherein the TTPC is in liquid form or in solution; coating the TTPC onto the particulates; combining the particulates coated with TTPC with the treatment fluid to create a suspension; and, placing the suspension into the portion of the subterranean formation. Other methods involve the use of TTPC in the form of a solid salt.

Abstract: Systems and methods for treating aqueous fluids and their associated methods of use are disclosed. In one embodiment, a system for treating an untreated aqueous fluid with a first concentration of a contaminant to produce a treated water with a second concentration of the contaminant, is provided, wherein the system comprises a chemical treatment subsystem comprising a chemical agent, wherein the chemical treatment subsystem precipitates at least a portion of the contaminant from the aqueous fluid; and a mechanical treatment subsystem comprising a centrifugal separator, wherein the mechanical treatment subsystem removes at least a portion of the precipitated contaminant from the aqueous fluid.

Abstract: Methods of treating subterranean formations to reduce bacteria load are provided. Some methods include the steps of providing a treatment fluid, particulates, and tri-n-butyl tetradecyl phosphonium chloride (TTPC) wherein the TTPC is in liquid form or in solution; coating the TTPC onto the particulates; combining the particulates coated with TTPC with the treatment fluid to create a suspension; and, placing the suspension into the portion of the subterranean formation. Other methods involve the use of TTPC in the form of a solid salt.

Abstract: Among other things, methods of treating a subterranean formation with gelled hydrocarbon fluids are provided. In certain embodiments, these methods comprise the steps of providing a gelled liquid hydrocarbon treatment fluid comprising a liquid hydrocarbon and a gelling agent that comprises a polyvalent metal salt of an organophosphonic acid ester or a polyvalent metal salt of an organophosphinic acid, and treating the subterranean formation with the gelled liquid hydrocarbon treatment fluid. The gelled liquid hydrocarbon treatment fluids of the present invention are suitable for use in subterranean treatment operations, such as subterranean stimulation and sand control treatments like fracturing and gravel packing, that may be carried out in subterranean formations for the production of hydrocarbons.

Abstract: A method is provided for swelling hydrocarbon-swellable elements located in a portion of a well. The method comprises the steps of: (A) introducing a water-in-oil emulsion into the portion of the well, wherein the water-in-oil emulsion comprises: (i) a hydrocarbon liquid, wherein the hydrocarbon liquid is the external phase of the water-in-oil emulsion; (ii) an aqueous liquid, wherein the aqueous liquid is an internal phase of the water-in-oil emulsion and wherein the aqueous liquid is adjacent to the external phase of the water-in-oil emulsion; and (iii) a surfactant; and (B) allowing the water-in-oil emulsion to contact the hydrocarbon-swellable element for a sufficient length of time to cause the thickness of the hydrocarbon-swellable element to expand by a desired percentage, wherein the desired percentage is at least 5%.

Abstract: A method is provided for swelling water-swellable elements located in a portion of a well. The method comprises the steps of: (A) introducing an oil-in-water emulsion into the portion of the well, wherein the oil-in-water emulsion comprises: (i) an aqueous liquid, wherein the aqueous liquid is the external phase of the oil-in-water emulsion; (ii) a hydrocarbon liquid, wherein the hydrocarbon liquid is an internal phase of the oil-in-water emulsion, and wherein the hydrocarbon liquid is adjacent to the external phase of the oil-in-water emulsion; and (iii) a surfactant; and (B) allowing the oil-in-water emulsion to contact the water-swellable element for a sufficient length of time to cause the thickness of the water-swellable element to expand by a desired percentage, wherein the desired percentage is at least 5%.

Abstract: Of the many methods provided herein, one method comprises: providing at least one fracture in a subterranean formation that comprises tight gas, a shale, a clay, and/or a coal bed; providing a plasticity modification fluid that comprises an aqueous fluid and an alkaline embrittlement modification agent; placing the plasticity modification fluid into the fracture in the subterranean formation; and embrittling at least one fracture face of the fracture to form an embrittled fracture face.

Abstract: Of the many methods provided herein, one method comprises: providing at least one fracture in a subterranean formation that comprises tight gas, a shale, a clay, and/or a coal bed; providing a plasticity modification fluid that comprises an aqueous fluid and an alkaline embrittlement modification agent; placing the plasticity modification fluid into the fracture in the subterranean formation; and embrittling at least one fracture face of the fracture to form an embrittled fracture face.

Abstract: Of the many methods provided herein. one method comprises: providing at least a portion of a subterranean formation that comprises a shale; providing a plasticity modification fluid that comprises an aqueous fluid and an alkaline embrittlement modification agent; placing a pack completion assembly neighboring the portion of the subterranean formation; and embrittling at least a portion of the shale to form an embrittled shale portion.

Abstract: A method is provided for swelling hydrocarbon-swellable elements located in a portion of a well. The method comprises the steps of: (A) introducing a water-in-oil emulsion into the portion of the well, wherein the water-in-oil emulsion comprises: (i) a hydrocarbon liquid, wherein the hydrocarbon liquid is the external phase of the water-in-oil emulsion; (ii) an aqueous liquid, wherein the aqueous liquid is an internal phase of the water-in-oil emulsion and wherein the aqueous liquid is adjacent to the external phase of the water-in-oil emulsion; and (iii) a surfactant; and (B) allowing the water-in-oil emulsion to contact the hydrocarbon-swellable element for a sufficient length of time to cause the thickness of the hydrocarbon-swellable element to expand by a desired percentage, wherein the desired percentage is at least 5%.