Abstract: An invert emulsion fluid may include a oleaginous external phase, a nonoleaginous internal phase, wherein a ratio of the oleaginous external phase to nonoleaginous internal phase is less than 55:45, a emulsifier, a particulate weighting agent dispersed in the non-oleaginous internal phase, and a viscosifier stabilizing the dispersion of the particulate weighting agent in the non-oleaginous internal phase.

Abstract: A process for the reuse of oilfield drilling waste with an natural affinity for oil which has had at least a portion of the contaminants removed using a remediation technology. The drilling waste can be further refined to ensure the waste meets a desired particle size distribution and thereafter sent for reuse by mixing the drilling waste with hot bituminous tar and thereafter using the liquids phase in roofing materials. A method of mixing the drilling waste with conventional fillers is also described to create a blended mixture of drilling waste and conventional fillers to create a new hybrid filler which is mixed with hot bituminous tar for use in roofing materials.

Abstract: Matrix acidizing treatment are designed and performed in a manner that takes into account radial acid flow into the formation. Subterranean well characteristics are determined (e.g., mineralogical and petrophysical characteristics). One of more candidate acids is selected. A linear pore volume of acid to breakthrough (PVBT) curve is generated for each candidate acid. The linear PVBT curves are modified to account for radial acid flow. The optimal acid is selected by considering wormhole development and cost. An initial acid pumping schedule is generated for the formation to be acidized, including the optimal acid, the treatment volume and the injection rate. Computer software is used to consider the subterranean well characteristics, simulate the initial acid pumping schedule and compare results with the radial PVBT curve. The initial schedule is modified until the results are consistent with the radial PVBT curve. An acidizing treatment is then performed.

Abstract: A method, system and computer program product for determining soil properties comprising a probe including at least a liquid injection port and a pressure transducer. The probe is pushed into a soil and one or more pumping tests are carried out, wherein during a pumping test infiltration liquid is pumped through the liquid injection port of the probe. By means of the pressure transducer a pressure response in the soil resulting from the injection of liquid through the liquid injection port is measured for each of the one or more pumping tests.

Abstract: The present disclosure provides a surfactant formulation for use in treating and recovering fossil fluid from a subterranean formation. The surfactant formulation includes a nonionic surfactant, organic acid selected from citric acid, diglycolic acid, glycolic acid and a salt thereof and injection water. The surfactant formulation may be injected into one or more injection wells located within the subterranean formation and fossil fluids can then be subsequently recovered from one or more producing wells.

Abstract: A method of propping created fractures and microfractures in tight formation. The method includes injecting into a wellbore a first pad fluid stage; injecting into the wellbore a second pad fluid stage; injecting into the wellbore a diverting agent; and injecting into the wellbore a main proppant slurry stage; wherein the first pad fluid stage includes an aqueous-based fluid at a rate above the fracturing gradient to create a fracture, wherein the second pad fluid stage includes an aqueous-based fluid and a low concentration of a proppant mixture including a slurry of small proppant materials and/or a slurry of conventional proppant materials to extend the fracture and open up secondary induced fractures, and wherein the main proppant slurry stage includes an aqueous-based fluid and a proppant with a larger size than the small proppant particles in the second pad fluid stage.

Abstract: Disclosed is a fracturing device for extraction of coalbed methane in low permeability reservoir. In the disclosure, by controlling the fracturing of fracturing pipes and the sealing of a segmented sealing mechanism for fracturing using a fracturing controller, the fracturing in fracturing holes can be effectively controlled. The segmented sealing mechanism for fracturing in the disclosure can separate each of the fracturing pipes in the fracturing holes separately in a sealed manner respectively, and perform segmented fracturing operations using each of the fracturing pipes, so as to effectively improve the uniformity and thoroughness of fracturing and ensure fracturing ability. In the disclosure, when the sealing operations are performed in each segment, the sealing effect of each segment can be ensured, and the sealing efficiency can be ensured, so that the fracturing ability of each segment of fracturing is improved to ensure the fracturing effect.

Abstract: The present invention discloses an in-situ leaching method and system. The ISL mining method provided by the present invention includes: constructing a vertical guiding well into an ore body; constructing a horizontal well towards the vertical guiding well, where the horizontal well includes a vertical section and a horizontal section; one end of the horizontal section is connected to the vertical section, and the other end of the horizontal section is connected to the vertical guiding well; constructing a plurality of vertical extraction wells towards the horizontal section; and simultaneously injecting lixiviant into the vertical section and the vertical guiding well by means of pressurized injection, and extracting leachate through the vertical extraction well. The ISL mining method and system provided by the present invention accomplish the injection through a horizontal well.

Abstract: Methods and compositions applied to proppants and/or nanites in order to reduce the microorganisms in fracking wells are disclosed.

Abstract: An embodiment in accordance with the present invention includes an EGS configured to allow the commercial production of electrical energy. One criteria of an EGS according to the present invention is that the temperature and volume of the fluids extracted are sufficiently high and large enough as to allow the commercial production of electrical energy. The system is able to operate for at least N years before the extracted fluid falls below the minimum temperature needed for energy production. Additionally, fractures are separated from each other by a sufficiently large volume of rock (Vcrit) relative to the fractures surface area such that the ratio of the rate of heat extraction to the rate of heat supply controlled by the thermal conductivity of the rock is such that the intervening rock is cooled at a rate that is sufficiently slow to be economic.

Abstract: A method for providing a well injection program in which injection testing is performed on an existing well which is intended to be an injection well in a field development. Water is injected into the well in a series of step rate tests or injection cycles, the data is modelled to determine thermal stress characteristics of the well and by reservoir modelling the optimum injection parameters are determined for the well injection program to provide for maximum recovery. The thermal stress characteristics are those that would previously have been obtained from core samples when the well was drilled. Further wells on a development can be tested and the individual thermal stress characteristics of each well combined in the reservoir model for optimized field development.

Abstract: Methods for mining soluble minerals from a subterranean deposit. A fluid is injected into a horizontal injection wellbore passing through the deposit and allowed to enter a mining/fracture plane having at least one fracture, extending from the horizontal injection wellbore, at a pressure sufficient to further fracture the deposit, maintain the mining/fracture plane or open the mining/fracture plane. The injected fluid is allowed to dissolve some of the soluble minerals from the deposit thereby forming a mineral solution which is produced from horizontal production wellbores that intersect the mining/fracture plane.

Abstract: Disclosed herein are embodiments of engineered geothermal systems (EGS). Also disclosed are methods and devices for the construction and use of planar artificial fractures in EGS wells, including wells that contain both an injection and extraction points.

Abstract: Method of arranging proppant in a fracture of a subterranean formation are disclosed. The methods can include (a) introducing a first fluid blend through a wellbore and into the fracture to form a first proppant bank in the fracture, and (b) introducing a second fluid blend through the wellbore and into the fracture to form a second proppant bank in the fracture, wherein a viscosity of the first fluid blend is less than a viscosity of the second fluid blend. The flow of the fluids can be alternated or switched between a lower viscosity fluid blend(s) and a higher viscosity fluid blend(s), without stopping a flow of fluid to the fracture.

Abstract: Surface modification agents may be included in emulsified acidic treatment fluids to leave surfaces in carbonate formations water wet after acidizing operations. A method of acidizing a subterranean formation, comprising: providing a treatment fluid in the form of an invert emulsion, wherein the treatment fluid comprises: a hydrocarbon phase comprising an oil-soluble liquid and an emulsifier; and an aqueous acidic phase comprising water, an acid, and a surface modification agent; and introducing the treatment fluid into a wellbore.

Abstract: Proppant-free channels may be formed in a proppant pack in subterranean formations by using the miscibility and immiscibility of proppant-laden and proppant-free fluids. For example, a method of forming a proppant pack may include: introducing, in alternating order, a proppant-laden fluid and a proppant-free fluid into a wellbore penetrating a subterranean formation, wherein the proppant-laden fluid comprises an oil-external emulsion and a proppant, and wherein the proppant-free fluid is immiscible with the proppant-laden fluid; and forming a proppant pack in a fracture in the subterranean formation, wherein the proppant pack comprises proppant-laden clusters and proppant-free channels.

Abstract: Methods for treating an oil or gas well having a wellbore by, for example, injecting an emulsion or microemulsion into the wellbore to increase formation crude oil or formation gas production by the well. Methods of selecting compositions for treating an oil or gas well having a wellbore to increase formation crude oil or formation gas production by the well.

Abstract: Embodiments of the present disclosure are directed to double emulsified acids, specifically water in oil in water (W/O/W) double emulsions with an acidic interior water phase. The double emulsified acid may include two or more emulsifying agents. In addition to improving the stability of the emulsions, the emulsifying agents may help slow the acid reaction rate. The first emulsifying agent may have an HLB greater than 7 and the second emulsifying agent may have an HLB less than or equal to 7. Other embodiments are directed to methods for producing a double emulsified acid and methods for acidizing a carbonate formation including a double emulsified acid.

Abstract: Embodiments of the present disclosure are directed to double emulsified acids, specifically water in oil in water (W/O/W) double emulsions with an acidic interior water phase. The double emulsified acid may include two or more emulsifying agents. In addition to improving the stability of the emulsions, the emulsifying agents may help slow the acid reaction rate. The first emulsifying agent may have an HLB greater than 7 and the second emulsifying agent may have an HLB less than or equal to 7. Other embodiments are directed to methods for producing a double emulsified acid and methods for acidizing a carbonate formation including a double emulsified acid.

Abstract: Compositions, systems, and methods for generating heat and/or gas, for example, to create and/or enhance microfractures in low-permeability formations are provided. In certain embodiments, the methods comprise: providing a treatment fluid that comprises a base fluid and a plurality of microbubbles, wherein the microbubbles each comprise at least an outer shell and a heat- and/or gas-generating chemical within the shell, and have a diameter of about 100 microns or less; and introducing the treatment fluid into at least a portion of a subterranean formation. In some embodiments, the microbubbles may enter one or more microfractures in the subterranean formation and release the heat- and/or gas-generating chemical therein.

Abstract: A wellbore system includes a first fracture formed from a wellbore at a first location; a second fracture formed from the wellbore at a second location; a wellbore seal positioned in the wellbore between the first and second locations and configured to fluidly seal a first portion from a second portion of the wellbore; a pressure gauge positioned in the first portion; a pressure gauge positioned in or uphole of the second portion; and a control system configured to communicably couple to the pressure gauges.

Abstract: The present invention refers to the formulation of a foaming agent for extreme conditions of salinity, temperature and concentration of divalent ions, including the improvement in the performance in these conditions with respect to the patent MX2008015989 A. Also, the design is presented of the experimental equipment used to characterize and evaluate foaming agents at laboratory level and conditions of pressure, temperature and salinity, in oil fields. The formulation of the foaming agent derived from this invention is a mixture of sodium alpha olefin sulfonates, alkylamido propyl betaines and triethanolamine, capable of giving it the benefit of being stable in temperature and salinity in a wide range, diluted in synthetic and congenital brines. This formulation is applicable for the control of gas mobility and improved oil recovery processes in naturally fractured reservoirs.

Abstract: Systems and methods for optimal spacing of horizontal wells that maximizes coverage of a predetermined area within an irregular boundary by the horizontal wells.

Abstract: In some embodiments, an apparatus and a system, as well as a method and article of manufacture, may operate to determine a value of strain, such as an equivalent plastic strain, in a perforated portion of a well by applying a set of draw-down pressures to the surface of at least one perforation tunnel in the perforated portion. The perforated portion, in turn, is modeled using stress components provided by a global field model that includes the location of the well, to set boundary conditions at the surface of the well. A well drilling process and a tunnel perforating process are modeled with element removal and pressure addition for the perforated portion. Additional activity may include operating a controlled device based on the value of strain that is determined. Additional apparatus, systems, and methods are disclosed.

Abstract: A system, in certain embodiments, includes a horizontal fracturing tree. The horizontal fracturing tree includes a first hydraulic fracturing bore configured to flow a first fluid, wherein the first hydraulic fracturing bore extends along a first horizontal axis, and the first horizontal axis is generally perpendicular to a vertical axis of a wellhead.

Abstract: Transverse fractures are formed from a borehole using hydraulic fracturing fluid while maintaining the downhole pressure close to a target pressure. The target pressure is selected to be greater than the expected transverse fracture initiation pressure at predetermined weak points, such as notches, and less than the expected longitudinal fracture initiation pressure. The process can be repeated to form multiple transverse fractures by pumping diversion composition(s).

Abstract: Methods and systems for treating a subsurface hydrocarbon formation are described herein. In some embodiments, method for treating a subsurface hydrocarbon formation is provide wherein the hydrocarbon formation comprises a kerogen containing formation that is adjacent to a formation containing liquid hydrocarbons and not having a natural recharging system, the method comprising the steps of: providing heat sources in the kerogen containing formation; energizing the heat sources to heat the kerogen containing formation; heating at least a portion of the kerogen containing formation to a temperature and for a time period sufficient to pyrolyze at least some of the kerogen; limiting production of pyrolyzed hydrocarbons so that the pyrolyzed hydrocarbons increase the pressure within the formation containing liquid hydrocarbons; and producing hydrocarbons from the formation containing liquid hydrocarbons.

Abstract: An existing well has zones that respectively produce water and desired fluids. Existing production tubing is in the well to a location uphole of the producing zones and preferably in a lateral portion on the borehole. The water producing zone is between the surface and the productive zone. A coiled tubing string with a straddle assembly of inflatable isolation packers is run through the production string. An optional milling out of the lower end of the production string can take place first. The inflatable straddle assembly is run past the end of the production string for placement to straddle the water zone while allowing production from the productive zone. The coiled tubing serves as the new production tubing for the productive zone. One or more zones can be isolated or aligned for flow from productive zones.

Abstract: A variable strength proppant pack may be useful in maintaining a higher porosity and conductivity of the proppant pack over time. Forming a variable strength proppant pack may involve introducing a fluid having a composition into a subterranean formation having a fracture network therein, wherein the fluid composition changes between a plurality of compositions that comprise: a first proppant-laden fluid comprising first proppant particles, and a second proppant-laden fluid comprising second proppant particles having a crush strength greater than a crush strength of the first proppant particles; and forming a proppant pack in at least a portion of the fracture network, the proppant pack having first proppant portions comprising the first proppant particles and second proppant portions comprising the second proppant particles.

Abstract: A method for optimized matrix acidizing, including a method for determining fracture pressure of a formation as a function of bottom hole temperature. First and second cycles of a step up rate test may be performed on the formation to be acidized at first and second test temperatures, respectively. From the first and second cycles, a mathematical relationship for fracture pressure of the formation as a function of bottom hole temperature may be formulated and integrated into a fluid placement simulator. A design matrix acidizing treatment plan accounting for an effect of bottom hole temperature on fracture gradient may simulated, and matrix acidizing treatment thereafter performed according to the design plan, thereby resulting in more accurate matrix acidizing treatment and minimization of inefficient fluid placement by adherence to actual formation fracture pressure limits.

Abstract: Methods including introducing a first particulate-free treatment fluid (first PFTF) into a subterranean formation above the fracture gradient. Alternatingly introducing a first particulate-laden treatment fluid (first PLTF) and a second particulate-laden treatment fluid (second PLTF) into the subterranean formation, wherein the first PLTF comprises nano-particles and degradable particles and the second PLTF comprises proppant particulates, and wherein the alternating introduction causes the proppant particulates in the second PLTF to agglomerate into proppant aggregates being surrounded by the first PLTF. Placing the proppant aggregates into at least one fracture, removing the hydraulic pressure to close the at least one fracture, and degrading the degradable particulates to form at least one channel between adjacent proppant aggregates.

Abstract: A phase-change hydraulic fracturing process, including the following steps: (1) injecting clean water or conventional fracturing fluid to a formation, so that the formation fractures; (2) placing non-phase-change liquid and phase-change liquid in different liquid mixing tanks and injecting into a shaft at the same time, an injection volume ratio of the non-phase-change liquid to the phase-change liquid is (0-0.7):(0.3-1); (3) injecting a displacement fluid into the shaft, so that the non-phase-change liquid and the phase-change liquid in the shaft completely enter a reservoir; (4) performing well shut-in and pressure-out for 30-200 min, so that solid-phase matters generated by the phase-change liquid are laid in the fracture; and (5) relieving pressure to finish the construction.

Abstract: Methods including creating or extending a first main fracture with a pad fluid into a subterranean formation, wherein the pad fluid is a high-viscosity fluid; alternatingly introducing a micro-proppant fluid with the pad fluid, wherein the micro-proppant fluid is a low-viscosity fluid comprising micro-sized proppant particulates; creating or extending a first branch fracture extending from the first main fracture with the alternatingly introduced micro-proppant fluid, whereby at least a portion of the micro-sized proppant particulates enter into the first branch fracture and form at least a partial monolayer of micro-sized proppant particulates therein; and introducing a macro-proppant fluid through the first opening at a second flow rate, wherein the macro-proppant fluid is a low-viscosity fluid comprising macro-sized proppant particulates, and whereby at least a portion of the macro-sized proppant particulates enter into the first main fracture and form a proppant pack therein.

Abstract: The present invention relates to the field of marine hydrate reserve recovery technology, and discloses a homocentric squares-shaped well structure for marine hydrate reserve recovery utilizing geothermal heat and a method thereof. The present invention employs a homocentric squares-shaped well structure and utilizes heat-carrying fluid to transfer the energy in a geothermal reservoir to a hydrate reservoir to promote dissociation of natural gas hydrates. The homocentric squares-shaped well structure can realize cyclic utilization of the heat-carrying fluid while improving heat conduction efficiency, and has advantages including high recovery rate, low recovery cost, low energy loss, and high heat utilization efficiency, etc.

Abstract: A method of extracting hydrocarbons from a subterranean formation comprises introducing a solution comprising a silicon-containing compound into the subterranean formation. The silicon-containing compound may comprise a terminal group comprising one of an alkanoate group, a fluoroalkanoate group, and a perfluoroalkanoate group, and one or more of an alkoxy group and a chlorine atom bonded to a silicon atom. The method comprises attaching the silicon-containing compound to one or more of formation surfaces of the subterranean formation to form an oleophilic surface on the one or more of the formation surfaces and the surfaces of proppant particles.

Abstract: The purpose of the present invention is to provide an artificial ground freezing method having good coolant thermal efficiency without a gas-phase coolant being released into the ground or into the air.

Abstract: Systems for heating a body of crushed hydrocarbonaceous material to produce hydrocarbons therefrom can involve heating multiple zones of the body of material sequentially. An exemplary system can include a body of crushed hydrocarbonaceous material having a lower zone and an upper zone. A lower heating conduit can be embedded in the lower zone, while an upper heating conduit is embedded in the upper zone. A collection conduit is embedded in the upper zone at a location above the upper heating conduit. A lower heating valve is also operatively associated with the lower heating conduit and is capable of switchably flowing a heat transfer fluid through the lower heating conduit. An upper heating valve is operatively associated with the upper heating conduit and capable of switchably flowing the heat transfer fluid through the upper heating conduit.

Abstract: Methods and compositions applied to proppants and/or nanites in order to reduce the microorganisms in fracking wells are disclosed.

Abstract: Systems and methods for extracting minerals from an underground mineralization zone located below the surface at an oil and gas drilling site. The system includes a vertical drilling means for drilling a vertical bore extending from the surface at the oil and gas drilling site into the mineralization zone, a second horizontal drilling means for drilling at least one horizontal production bore into the mineralization zone. The first horizontal drilling means and the second horizontal drilling means are configured to return material from the mineralization zone to the surface where the mineral content of the material is analyzed and a separator separates minerals, waste and drilling mud from the material. The method includes steps of drilling a horizontal assessment bore, analyzing assessment material for a desired mineral, drilling a horizontal production bore, producing production material containing the desired mineral, and separating the desired material from waste and drilling mud.

Abstract: Viscosifying proppants including proppant particles coated with a CO2-philic coating in which the CO2-philic coating has a solvable portion that viscosifies a CO2-based fluid when the viscosifying proppant is added to the CO2-based fluid are provided. Methods of making viscosifying proppants are also provided that include coating proppant particles with a precursor material of a CO2-philic material, and polymerizing the precursor material to form a viscosifying proppant. Viscous hydraulic fracturing fluids include a CO2-based fluid and the viscosifying proppants and methods of treating subterranean formations that include contacting a subterranean formation with a viscous hydraulic fracturing fluid and propagating at least one subterranean fracture are also provided.

Abstract: A process for the recovery of hydrocarbon such as bitumen/EHO from a hydrocarbon bearing formation in which are situated an upper injection well and a lower production well, the method comprising the steps: preheating an area around and between the wells by circulating hot solvent through the completed interval of each of the wells until sufficient hydraulic communication between both wells is achieved; injecting one or more hydrocarbon solvents into the upper injection well at or above critical temperature of the solvent or solvent mixture, thereby causing a mixture of hydrocarbon and solvent to flow by gravity drainage to the lower production well; and producing the hydrocarbon to the surface through the lower production well. A non-condensable gas may be injected into the solvent chamber created by the hydrocarbon solvent.

Abstract: Generally, methods for propping complex fracture networks in tight subterranean formations may involve introducing a first treatment fluid comprising a first base fluid and a first propping agent having a mean particulate size distribution ranging from about 0.5 microns to about 20 microns into a fracture network in a subterranean formation; and then introducing a second treatment fluid comprising a second base fluid and a second propping agent having a mean particulate size distribution greater than about 35 microns into the fracture network.

Abstract: Methods of introducing into a subterranean formation a series of treatment fluids comprising one of micro-proppant particulates, micro-degradable particulates, branch-proppant particulates, branch-degradable particulates, main-proppant particulates, and main-degradable particulates and placing the particulates into portions of microfracture(s), branch fracture(s), and main fracture(s) to increase fracture complexity of a fracture network in the subterranean formation.

Abstract: Pumping a pre-flush composition into a subterranean reservoir may contact at least a portion of non-polar material within a reservoir path. The pre-flush composition may have or include a polar fluid and at least one surfactant. The pre-flush composition may in situ form an in situ fluid in the reservoir path. The in situ formed fluid may include a portion of the non-polar material from the reservoir path, a polar phase from the polar fluid, and at least one surfactant. Pre-flushing the reservoir path may allow for greater hydrocarbon recovery when performing a subsequent operation as compared to an otherwise identical operation absent the pre-flushing the reservoir.

Abstract: Methods and systems of heating a body of crushed hydrocarbonaceous material to produce hydrocarbons therefrom can involve heating multiple zones of the body of material sequentially. An exemplary method can include forming a body of crushed hydrocarbonaceous material having a first zone and a second zone. The first zone can be heated in a first heating stage to form a dynamic high temperature production region in the first zone. A cooling fluid can then be injected into the first zone after the high temperature production region forms. The high temperature production region can move into the second zone in a second heating stage. Hydrocarbons can be collected from the body of crushed hydrocarbonaceous material during both the first and second heating stages.

Abstract: A method for in situ solution mining of a mineral from an underground evaporite stratum using a set of wells in fluid communication with at least one mineral cavity with some wells operated in solvent injection mode and other wells operated in brine production mode and optionally with some inactive wells, comprising switching the operation mode of one or more wells. The evaporite mineral preferably comprises trona. The at least one cavity may be formed by directionally drilled uncased boreholes or by lithological displacement of the evaporite stratum at a weak interface with an underlying insoluble stratum by application of a lifting hydraulic pressure to create an interfacial gap. The extracted brine can be processed to make valuable products such as soda ash and/or any derivatives thereof.

Abstract: A method of producing purified water in a subsurface environment is provided in which ambient subsurface source water is introduced into and through one or more ultrafiltration membrane units of a subsurface water treatment system and producing thereby an ultrafiltrate substantially free of solid particulates having a largest dimension greater than 0.1 microns. An electrochemical unit in fluid communication with at least one ultrafiltration membrane unit provides an antifoulant solution. An ultrafiltrate-rich backwash fluid and at least a portion of the antifoulant solution are delivered to at least one non-producing ultrafiltration membrane unit during a backwash cycle. A flux of source fluid through each of the ultrafiltration membrane units of less than thirty gallons per square foot per day limits the need for backwash cycles. A reduction in the number of backwash cycles enhances system autonomy and useful life, and limits the need for intervention for maintenance and component replacement.

Abstract: A method of injecting well treatment fluid including proppant and proppant-spacing filler material through a wellbore into the fracture, heterogeneously placing the proppant in the fracture in a plurality of proppant clusters or islands spaced apart by the material, and removing the filler material to form open channels around the pillars for fluid flow from the formation through the fracture toward the wellbore. The proppant and channelant can be segregated within the well treatment fluid, or segregated during placement in the fracture. The filler material can be dissolvable particles, initially acting as a filler material during placement of the proppant in the fracture, and later dissolving to leave the flow channels between the proppant pillars. The well treatment fluid can include extrametrical materials to provide reinforcement and consolidation of the proppant and/or to inhibit settling of the proppant.

Abstract: Generally, methods for propping complex fracture networks in tight subterranean formations may involve introducing a first treatment fluid comprising a first base fluid and a first propping agent having a mean particulate size distribution ranging from about 0.5 microns to about 20 microns into a fracture network in a subterranean formation; and then introducing a second treatment fluid comprising a second base fluid and a second propping agent having a mean particulate size distribution greater than about 35 microns into the fracture network.

Abstract: A hydraulic fracturing composition includes: a superabsorbent polymer in an expanded state; a plurality of proppant particles disposed in the superabsorbent polymer; an additive comprising a surfactant, a viscose polymer, or a combination thereof, and a fluid to expand the superabsorbent polymer into the expanded state. A process for disposing a plurality of proppant particles in a fracture comprises: disposing a hydraulic fracturing composition in a downhole environment; forming a fracture; disposing the hydraulic fracturing composition in the fracture; breaking the superabsorbent polymer after forming the fracture; and releasing the plurality of proppant particles from superabsorbent polymer. The process also comprises injecting a proppant-free fluid and a proppant-containing fluid in an alternating order into a subterranean formation.