Abstract: An emulsion for hydraulic fracturing to provide a one-step delivery of a fracturing fluid and a breaker for hydraulic fracturing of a hydrocarbon-bearing formation is provided. The emulsion for hydraulic fracturing is a water-in-oil-in-water emulsion having an internal aqueous phase that includes a breaker, an external aqueous phase that includes a fracturing fluid and a proppant, and an intermediate hydrocarbon phase separating the internal aqueous phase and external aqueous phase. The emulsion may include nanometer-sized or micrometer-sized particles to form a Pickering emulsion.

Abstract: A drilling fluid composition that contains micronized barite particles with a particle size in the range of 1 to 5 ?m, and also a method of fracturing a subterranean formation using the drilling fluid composition. Various embodiments of the micronized barite particles and the method of making thereof, the drilling fluid composition, and the method of fracturing a subterranean formation are also provided.

Abstract: Methods and systems for facilitating extraction of subterranean hydrocarbons from a geologic structure. The present methods include causing corrosion of a base metal within a geologic structure to produce a gaseous product to increase pressure and form fractures in the geologic structure. Some embodiments of the present methods include injecting a fluid composition comprising the base metal into a wellbore (e.g., into a geologic structure via the wellbore).

Abstract: An emulsion for hydraulic fracturing to provide a one-step delivery of a fracturing fluid and a breaker for hydraulic fracturing of a hydrocarbon-bearing formation is provided. The emulsion for hydraulic fracturing is a water-in-oil-in-water emulsion having an internal aqueous phase that includes a breaker, an external aqueous phase that includes a fracturing fluid and a proppant, and an intermediate hydrocarbon phase separating the internal aqueous phase and external aqueous phase. The emulsion may include nanometer-sized or micrometer-sized particles to form a Pickering emulsion.

Abstract: Systems and methods for treating subterranean formations including quantifying additive concentrations. Certain of those methods include; introducing a fluid including an aqueous base fluid and a friction reducer into a wellbore penetrating of a subterranean formation at a pressure sufficient to create or enhance one or more fractures within the subterranean formation; recovering a portion of the fluid from the wellbore; adding a reactive agent to a sample of the portion of the fluid that has been recovered from the wellbore, where the reactive agent reacts with the friction reducer to form a photo-detectable compound in the sample; measuring a light absorbance of the sample at a selected wavelength of light; and using the measured absorbance and a calibration curve for the selected wavelength of light to determine the concentration of the friction reducer in the fluid that has been recovered from the wellbore.

Abstract: An acid-generating fluid comprising a thermally activated strong acid precursor is provided in the method of the present invention. The thermally activated strong acid precursor comprises sulfur dioxide or a first precursor of a compound adapted to react to liberate sulfur dioxide, and an aldehyde and/or a ketone or a second precursor of a compound adapted to react to liberate an aldehyde and/or ketone. The acid-generating fluid is placed into a subterranean formation, where the first precursor and/or the second precursor are thermally activated, thereby liberating sulfur dioxide and the aldehyde and/or ketone. The sulfur dioxide and the aldehyde and/or ketone are reacted to form a thermally activated strong acid.

Abstract: A comprehensive enhanced oil recovery system that combines a plurality of different implementations of several enhanced oil recovery methods in an integrated system. The enhanced oil recovery system includes heating an underground reservoir having a heat transfer matrix to increase the temperature of the reservoir around a production well. The heat transfer matrix includes thermal injection wells, production wells and heat delivery wells.

Abstract: Gel breaking systems comprise a source of hydrogen peroxide and an activator selected from the group consisting of triazine-based activators, phthalimide-based activators and mixtures thereof. Also, methods use the gel breaking system to break the gelled component of a treatment fluid used in a gravel packing operation for a well.

Abstract: Multi-stage treatment methods for the treatment or removal of iron sulfide scales in subterranean operations and operations involving the production and/or transportation of oil and gas. In one embodiment, the methods include identifying one or more types of iron sulfide scale present in a portion of a subterranean formation; introducing a first treatment composition comprising an acid into at least a portion of the subterranean formation to partially dissolve the iron sulfide scale therein; and introducing a second treatment composition into the portion of the subterranean formation after the first treatment composition, the second treatment composition comprising an iron sulfide treating additive selected based at least in part on a type of iron sulfide scale identified in the subterranean formation.

Abstract: Methods including isolating a first treatment zone comprising an opening into a subterranean formation. A high-viscosity treatment fluid (HVTF) is introduced through the opening and incrementally increased fracturing rate steps (IIFRSs) are applied to create or enhance a dominate fracture, wherein between each IIFRS a downhole pressure slope over time will increase, decline, or stabilize at a measured pressure slope. The measured pressure slope is evaluated to determine whether an increasing pressure slope, a stabilizing pressure slope, or a declining pressure slope exists to determine whether and when to apply a subsequent IIFRS. The result is increasing a volume of the dominate fracture due to efficient dominate fracturing with generated back pressure until a first maximum fracturing rate is reached.

Abstract: Methods including introducing a first high-viscosity treatment fluid (HVTF) into a subterranean formation through an opening and applying incrementally increased fracturing rate steps (IIFRSs) to the first HVTF to create or enhance a dominate fracture, wherein between each IIFRS applied to the first HVTF a downhole pressure slope over time will increase, decline, or stabilize at a first HVTF measured pressure slope. Evaluating the first HVTF measured pressure slope prior to applying a subsequent IIFRS to the first HVTF. Introducing a first low-viscosity treatment fluid (LVTF) through the opening to create or enhance a secondary azimuth fracture extending from the dominate fracture, and introducing a low-viscosity diversion fluid pill (LVDF) pill through the opening to create a fluidic seal therein.

Abstract: Methods of preparing a viscosified treatment fluid comprising a base fluid, a gelling agent, and breaker coated particulates (“BCPs”). The BCPs comprise particulates at least partially coated with a first layer of a stabilization agent followed by a second layer of a breaker. The viscosified treatment fluid may be introduced into a subterranean formation, the breaker activated to reduce a viscosity thereof, and a particulate pack formed in the subterranean formation with the BCPs.

Abstract: This method is designed to facilitate the well treatment with the possibilities for non-uniform/heterogeneous proppant placement in the extended and branched fractures produced by hydraulic fracturing. The essence of the method is to inject a proppant-bearing gel into the wellbore drilled into a productive formation. The low-viscosity fracturing fluid is injected into the wellbore together with the gel fluid (simultaneously or in turns). The method also provides for the injection of gas into the proppant-bearing gel and/or the low-viscosity fluid. The gas can be injected upstream of the junction point, at the junction point, or downstream of the junction point of the flows of the proppant-bearing gel and the low-viscosity fluid. The method further provides for the division of the gel fluid into the separate agglomerates with their subsequent injection into the fractures in the subterranean formation to form the proppant structures in the fracture.

Abstract: Methods for treating a subterranean formation include providing a first treatment fluid comprising a plurality of degradable diverting agents, introducing the first treatment fluid into the subterranean formation via a wellbore, and allowing a portion of the plurality of degradable diverting agents to divert a flow of at least a portion of the first treatment fluid or a portion of a second treatment fluid from a first location within the wellbore to a second location within the wellbore. The plurality of degradable diverting agents includes a blend of polylactic acid (PLA) and an acid-soluble hard particulate. Compositions for treating a subterranean formation include the plurality of degradable diverting agents.

Abstract: An encapsulated scale inhibitor comprises: at least one scale inhibitor, wherein the at least one scale inhibitor is in the form of particulates; and an encapsulating material, wherein the encapsulating material at least partially encapsulates the at least one scale inhibitor, wherein the encapsulated scale inhibitor is capable of complete degradation. In one embodiment, a method comprises: providing a treatment fluid comprising a plurality of scale inhibitor particulates that comprise at least one scale inhibitor and a self-degrading encapsulating material that at least partially encapsulates the scale inhibitor; and introducing the treatment fluid into a well bore penetrating at least a portion of the subterranean formation.

Abstract: A well treatment composition for use in a hydrocarbon-bearing reservoir comprising a reversible aminal gel composition is disclosed. The reversible aminal gel composition includes a liquid precursor composition. The liquid precursor composition is operable to remain in a liquid state at about room temperature. The liquid precursor composition comprises an organic amine composition; an aldehyde composition; a polar aprotic organic solvent; and a metal salt composition with valence 3, 4, or 5. The liquid precursor composition transitions from the liquid state to a gel state responsive to an increase in temperature in the hydrocarbon-bearing reservoir.

Abstract: A method of increasing oil recovery form a carbonate oil reservoir by determining the presence of microorganisms, determining a specific nutrient package to stimulate the microorganisms, delivering the nutrient package to the carbonate oil reservoir, and allowing the stimulated microorganisms to change the adhesion tension between the carbonate oil rock formation and the oil and the water.

Abstract: A method for obtaining a fluid sample downhole that has at least a target fluid and an undesirable fluid may include receiving the fluid sample into a sample tank positioned that has a main chamber and isolating at least a portion of the undesirable fluid from the target fluid in the main chamber. A related apparatus may include a conveyance device configured to be conveyed along a borehole and a fluid sampling tool positioned along the conveyance device. The conveyance device may include a probe receiving the fluid sample from a formation; a pump drawing the fluid sample through the probe; and at least one sample tank receiving the fluid sample from the pump. The sample tank may include a main chamber receiving the fluid sample and an isolation volume isolating at least a portion of the undesirable fluid from the target fluid in the main chamber.

Abstract: In one or more embodiments, a method includes positioning an actuator in a wellbore and transmitting, from the actuator, an actuation signal to a sensor coupled to a casing in the wellbore. The method further includes detecting the actuation signal at the sensor and placing the sensor in a different mode of operation in response to detecting the actuation signal.

Abstract: A wellbore tool includes a rotatable elongate pipe that includes a first elongate portion extending along a longitudinal axis of the elongate pipe. A first bending portion with a first end attaches to a downhole end of the first elongate portion. The first bending portion deviates from a longitudinal axis of the first elongate portion in a first direction. A second bending portion has a first end attached to a second end of the first bending portion. The second bending portion is positioned downhole of the first bending portion. The second bending portion deviates towards the longitudinal axis in a second direction different from the first direction. The first bending portion and the second bending are eccentric relative to the first elongate portion. The wellbore tool is rotated a set amount and stabbed in a downhole direction until the wellbore tool enters the parted casing.