Abstract: Methods of treating a subterranean formation include providing a treatment fluid including a composition of a borate salt, an amine, and an organosilane; introducing the treatment fluid into the formation; and curing the composition to at least partially consolidate unconsolidated particulates in the formation.

Abstract: Hydraulic fracturing a subterranean formation including to count the number and types of fractures created in real time. The hydraulic fracturing involves injecting a frac slurry having frac fluid and proppant through a wellbore into the subterranean formation, hydraulic fracturing the subterranean formation with the frac slurry, and observing change in fracture counts with changes in proppant size and proppant concentration in the frac slurry. The hydraulic fracturing includes shear fracturing the rock in the subterranean formation. Operating parameters of the hydraulic fracturing may be adjusted in real time to increase the amount of shear fracturing occurring per unit time. Such adjusting may be based on resonant frequency at which the rock fractures with destruction as super shearing.

Abstract: Compositions and methods of using such compositions to treat subterranean formations are provided. In one embodiment, the methods include providing a drilling fluid including an aqueous base fluid and a low molecular mass organic gelator; and using the drilling fluid to drill at least a portion of a wellbore that penetrates at least a portion of a subterranean formation. In certain embodiments, the methods include providing a drilling fluid including an aqueous base fluid and a low molecular mass organic gelator; and using the drilling fluid to drill at least a portion of a wellbore that penetrates at least a portion of a subterranean formation.

Abstract: A method of delivering a treatment fluid into a subterranean formation and system therefor are provided herein. The treatment fluid is delivered using a pumping assembly, which comprises a clean side and a slurry side. The method includes determining a downhole rate of the additive in the treatment fluid, injecting the additive into the slurry side at a first slurry side location, injecting the additive into at least one of the slurry side at a second slurry side location or the clean side, combining the additive from the first slurry side location with any additive from the second slurry side location or the clean side to form the treatment fluid with the downhole rate of the additive, and delivering the treatment fluid into the subterranean formation.

Abstract: Methods and systems for treating wellbores. An example method includes introducing an acidic treatment fluid into the well; wherein the acidic treatment fluid comprises an acid and a first aqueous base fluid. The method further includes introducing an enzymatic treatment fluid into the well; wherein the enzymatic treatment fluid comprises an enzyme and a second aqueous base fluid. The method additionally includes contacting the filter cake with the acidic treatment fluid and contacting the filter cake with the enzymatic treatment fluid after the filter cake was contacted with the acidic treatment fluid.

Abstract: An oil well cement slurry high-temperature suspension stabilizer prepared from oil-based shale drilling cuttings is provided. The high-temperature suspension stabilizer is reasonable in principle, inexpensive and easily available in raw materials, high in product uniformity and good in chemical stability. Meanwhile, waste is changed into wealth. Therefore, the high-temperature suspension stabilizer is environment-friendly and has a broad industrial application prospect.

Abstract: A method of producing subterranean fractures in geologic formations having a significant amount of water present (a wet well) for the extraction of hydrocarbons therefrom includes flowing an explosive hydrophobic emulsion mixture to protect the air and fuel mixture subsequently flowed into a well hole. The well hole may then be sealed with a packer plug creating a compression chamber with the air and fuel mixture. A liquid, such as water, may be pumped into the well hole to create pressure in the compression chamber. The build-up of pressure eventually causes auto-ignition of the air and fuel mixture which fractures the formation. The water may then rush into the compression chamber which thermally shocks the area causing additional fractures. The water may vaporize to steam and thoroughly disinfect the well hole eliminating the need for added biocides.

Abstract: A system for supporting a borehole junction includes a device configured to deploy a material in a solid state to a downhole location proximate to the borehole junction, and a heat source configured to apply heat to the material to a temperature sufficient to liquefy the material. The liquified material is configured to flow into a formation region adjacent to the borehole junction and consolidate the formation region.

Abstract: Compositions and methods involving polyvalent cation reactive polymers for use as lost circulation materials in subterranean treatment operations are provided. In some embodiments, the methods include forming a treatment fluid including a base fluid, a source of a polyvalent cation, a polyvalent cation reactive polymer, and an acid precursor; introducing the treatment fluid into a wellbore penetrating at least a portion of a subterranean formation; and allowing the treatment fluid to at least partially set.

Abstract: Unconventional hydrocarbon source rock reservoirs can contain the organic material kerogen, intertwined with the rock matrix. The kerogen can alter the tensile strength of the rock and contribute to higher fracture energy needs. To degrade kerogen and other organic materials, oxidizing gasses are dissolved in carbon dioxide (CO2) which is then used as part of a fracturing fluid. The oxidizing gasses can be dissolved directly in the CO2 or generated in situ using precursors.

Abstract: Provided are methods and system for propping a fracture. An example method includes introducing a first fracturing fluid into the fracture; wherein the first fracturing fluid comprises a first amount of high crush strength proppant and a first aqueous base fluid; wherein the high crush strength proppant has a crush strength equal to or exceeding 4000 psi. The method further includes introducing a second fracturing fluid into the fracture; wherein the second fracturing fluid comprises a first amount of low crush strength proppant and a second aqueous base fluid; wherein the low crush strength proppant has a crush strength less than 4000 psi. The method also includes introducing a third fracturing fluid into the fracture; wherein the third fracturing fluid comprises a second amount of high crush strength proppant and a third aqueous base fluid.

Abstract: Friction reducers can be used in fluids for oil and gas operations. Friction reducers can be water-hydratable and can decrease the friction within wellbore components after fully hydrating. The friction reducer can be pre-hydrated at the well site. The friction reducer and water can be combined into a static mixer of a pre-hydration apparatus that forms a mixed fluid. The friction reducer can be retained in the pre-hydration apparatus for a sufficient period of time to allow the friction reducer to hydrate. The mixed fluid containing the pre-hydrated friction reducer can then be added to a base fluid to form a treatment fluid. The treatment fluid can be a fracturing fluid. The pre-hydrated friction reducer can provide an immediate reduction in friction to the treatment fluid as the treatment fluid is being pumped into the wellbore.

Abstract: A method for injecting non-condensable gas or application of in-situ combustion to recover remaining oil in a heavy oil reservoir with bottom water includes: drilling a new horizontal well in an oil layer between the existing horizontal production well location and the bottom water layer; preheating the new horizontal well; after the horizontal section of the horizontal well is in thermal communication with the upper steam/gas chamber, performing gas injection in existing wells to maintain pressure slightly higher or similar to the pressure of the bottom water layer, and converting the horizontal well into a continuous production well; drilling a vertical well in the unswept reservoir area; establishing a fluid communication in the oil layer between the vertical well and the horizontal well, injecting air or oxygen into the vertical well; and in the later stage of the horizontal well, stopping gas injection and gradually reducing the pressure in the steam/gas chamber.

Abstract: Compositions of nanoparticle-based stimulation fluids and methods of use for acid diversion from high permeability zones into low permeability zones to achieve deep penetration of wormholes in subterranean formations, such as carbonate formations. Certain embodiments include a gel precursor composition comprising metal oxide nanoparticles, such as silicon dioxide nanoparticles as a gelling agent, and magnesium chloride.

Abstract: Fluids injected into a carbonate reservoir formation during Enhanced Oil Recovery (EOR) may include a foaming mixture that includes a zwitterionic surfactant, an omega-3-acid ethyl ester, and aqueous salt solution. The omega-3-acid ethyl ester may include eicosapentaenoic acid ethyl ester, docosahexaenoic acid ethyl ester, or combinations thereof. The foaming mixtures may be incorporated into methods for enhancing hydrocarbon recovery in a carbonate reservoir formation. The methods may include introducing the foaming mixture to the carbonate reservoir formation such that any hydrocarbon present in the carbonate reservoir formation is displaced by the foaming mixture and is recoverable from the carbonate reservoir formation.

Abstract: Methods for fracturing a subterranean formation penetrated by a well bore are provided, the method comprising the step of injecting a well treatment fluid into the well bore at a pressure and flow rate sufficient to fracture the subterranean formation, wherein the well treatment fluid comprises one or more iron-containing compounds and one or more booster compounds. The methods can be used to reduce viscosity and to facilitate the decomposition of acrylamide-containing polymers.

Abstract: Compositions and methods for use in subterranean treatment fluids involving thermoassociative polymers are provided. In some embodiments, the methods include providing a treatment fluid that includes an aqueous base fluid, one or more thermoassociative polymers that include a water soluble polymeric backbone having one or more hydrophobic moieties attached to the polymer backbone, wherein the thermoassociative polymer exhibits thermoassociation at a first temperature Tassoc, and one or more tuning additives that changes the temperature at which at least one of the thermoassociative polymers exhibits thermoassociation from Tassoc to a second temperature Tassoc?; and introducing the treatment fluid into a portion of a subterranean formation.

Abstract: A method of formulating an oil-based wellbore fluid, the method comprising adding at least a plurality of conductive carbon black agglomerates or pellets having an average size of at least 500 ?m to an oleaginous base fluid, and applying energy to the oil-based wellbore fluid to disperse the plurality of conductive carbon black agglomerates or pellets into the oleaginous base fluid as finer particles than the agglomerates or pellets.

Abstract: A method of cementing a wellbore includes injecting into the wellbore a non-aqueous fluid; injecting into the wellbore a cement slurry and a non-ionic surfactant composition after injecting the non-aqueous fluid; and allowing the cement slurry to set, wherein the non-ionic surfactant composition comprises an alkyl end-capped ethoxylated fatty alcohol, a chain extended non-ionic surfactant, or a combination comprising at least one of the foregoing.

Abstract: Methods for separating fluids with a barrier pill within a downhole environment are provided. The method includes introducing a barrier pill fluid into the wellbore containing a first fluid to form the barrier pill on top of the first fluid in the wellbore and introducing a second fluid into the wellbore. The barrier pill separates the first fluid and the second fluid. The barrier pill includes a viscoelastic surfactant and an aqueous fluid, such as a brine containing water and about 5 wt % to about 50 wt % of a salt.