Abstract: Disclosed herein are methods for extracting a kerogen-based product from subsurface shale formations. The methods utilize in-situ reactions of kerogen involving liquid phase chemistry at formation temperatures and pressures. These methods rely on chemically modifying the shale-bound kerogen to render it mobile, using chemical oxidants. In the methods disclosed herein an oxidant is provided to the subsurface shale formation comprising kerogen in an inorganic matrix, the oxidant converting the kerogen to form organic acids, and forming a mobile kerogen-based product. The spent oxidant is regenerated in-situ to restore at least some of the original oxidation activity. At least a portion of the mobile kerogen-based product is recovered. The kerogen-derived product can be upgraded to provide commercial products.

Abstract: A process for producing methane, carbon dioxide, gaseous and liquid hydrocarbons, and other valuable products from subterranean carbon bearing formations, in-situ. The process utilizes indigenous and/or non-indigenous microbial consortia that are capable of converting a carbon-bearing material such as shale or coal to desired products. The process comprises injecting fluid into a carbon bearing deposit with at least one injection well and removing injected fluid and product from the deposit through at least one production well, and controlling fluid pressure within at least a portion of the deposit by use of the injected fluid, the pressure being controlled such that the fluid pressure within at least a portion of the deposit exceeds the fluid pressure that normally exists in that portion.

Abstract: A method for delaying the removal of a majority of an oil-based mud (OBM) filter cake from a hydrocarbon reservoir wellbore that utilizes a multiple phase composition is described. The use of the multiple phase composition allows for a microemulsion, a miniemulsion, or a nanoemulsion to form in situ downhole at a controllable time. The method includes pumping the multiple phase composition comprising an additive into the wellbore. The multiple phase composition may be broken thereby releasing the additive. The broken multiple phase composition and the additive may contact the OBM filter cake particles to form an in situ emulsion selected from the group consisting of a nanoemulsion, a miniemulsion, a microemulsion, a multiple emulsion, a water-continuous emulsion and mixtures thereof. The in situ emulsion may incorporate more of the external oil from the OBM filter cake in order to more easily remove the OBM filter cake.

Abstract: Methods and compositions for treating a formation, proximate a wellbore, prior to primary cementing, by reacting an activating agent and a silicate to provide a barrier between the wellbore and the formation to reduce the contamination of cement by ingress of formation fluids or leakage of cement from the wellbore during cement transitional phases. The activating agent may be provided while the wellbore is being drilled or may be provided subsequent to drilling or may be at least partially naturally occurring in the formation prior to drilling. The silicate may be provided during or subsequent to drilling.

Abstract: Gellable treatment fluids containing a terpolymer that comprises 2-acrylamido-2-methylpropanesulfonic acid, acrylamide, acrylic acid monomer units can be used in various subterranean operations where it is necessary for the treatment fluid to remain in a gelled state for extended periods of time at high formation temperatures. Methods for treating a subterranean formation can comprise providing a treatment fluid comprising an aqueous carrier fluid, a crosslinking agent, a gel stabilizer, and a terpolymer that comprises 2-acrylamido-2-methylpropanesulfonic acid, acrylamide, and acrylic acid monomer units, or any salt thereof; introducing the treatment fluid into a subterranean formation; allowing the treatment fluid to form a gel in the subterranean formation; and breaking the gel after it has been in the subterranean formation for at least about one day.

Abstract: A system, method and apparatus for stimulating a reservoir is disclosed. A slurry is supplied to the work string at the surface, which work string extends from the surface location to a downhole location adjacent the reservoir. A parameter of the slurry is measured at the downhole location and transmitted to the surface location. A control unit at the surface location receives the measured parameter of the slurry and estimates a fracture conductivity of the reservoir using the measured parameter of the slurry. The control unit may alter the parameter of the slurry at the surface location to obtain a selected fracture conductivity to stimulate the reservoir.

Abstract: A method of producing sulfur dioxide is provided. A feed gas stream comprising at least 5% by volume hydrogen sulfide is provided. The feed gas stream is separated into a hydrogen sulfide stream and a hydrocarbon gas stream. An oxidant stream is provided and is combusted with the hydrogen sulfide stream to produce thermal power and a combustion stream containing sulfur dioxide and steam. Sulfur dioxide is separated from the combustion stream.

Abstract: Clathrate reservoirs of Class II are modified in order to improve the ability to produce hydrocarbons from them. Specifically a method for improving producibility of subsurface clathrate formation underlain by a mobile aquifer includes drilling a borehole to a depth providing access to the mobile aquifer and injecting a material into the mobile aquifer such that the material passes through pore spaces and forms a barrier underlying the clathrate formation and substantially impeding fluid flow from the mobile aquifer into contact with the clathrate formation.

Abstract: A composition is provided for lowering a pH of a drilling fluid. The composition includes HCl, urea, complex substituted keto-amine-hydrochloride, an alcohol, an ethoxylate, and a ketone. A method of using the composition includes adding the composition to a drilling fluid for a well to assist in lowering a pH thereof. Methods are also provided for performing hydraulic fracturing of an oil or a gas well, for adjusting a pH of a drilling fluid, for adjusting and maintaining a pH of a process fluid, for solubilizing calcium carbonate in an aqueous suspension or dispersion of calcium carbonate, for removing a foulant in a fluid-handling element, and for adjusting a pH and lowering a salt level of turf.

Abstract: The present invention relates to a surfactant mixture comprising at least three ionic surfactants which differ in terms of the hydrocarbyl moiety (R1)(R2)—CH—CH2— and are of the general formula (I) where R1, R2, A0, k, X, o, Y, a, b, M are each as defined in the description and the claims. The invention further relates to the use and preparation thereof, and to aqueous surfactant formulations comprising the mixtures, and to processes for producing mineral oil by means of Winsor type Ill microemulsion flooding, in which the aqueous surfactant formulation is injected into a mineral oil deposit through injection wells and crude oil is withdrawn from the deposit through production wells.

Abstract: A composition comprises: a treatment fluid comprising a lost-circulation material, wherein the lost-circulation material comprises a ceramic, and wherein the lost-circulation material has a median particle size in the range from about 0.001 millimeters to about 25.4 millimeters. According to another embodiment, a composition comprises: the treatment fluid comprising a lost-circulation material, wherein the lost-circulation material comprises a ceramic, and wherein the median particle size and the concentration of the lost-circulation material is selected such that the treatment fluid has a sealing pressure of at least 50 psi (0.3 MPa). A method of eliminating or reducing lost circulation from a well comprises: introducing the treatment fluid into at least a portion of the well.

Abstract: A composition comprises: a treatment fluid comprising a lost-circulation material, wherein the lost-circulation material comprises asphalt, and wherein the lost-circulation material has a median particle size in the range from about 0.001 millimeters to about 25.4 millimeters. According to another embodiment, the composition comprises: a treatment fluid comprising a lost-circulation material, wherein the lost-circulation material comprises asphalt, and wherein the median particle size and the concentration of the lost-circulation material is selected such that the treatment fluid has a sealing pressure of at least 30 psi (0.2 MPa). A method of eliminating or reducing lost circulation from a well comprises: introducing the treatment fluid into at least a portion of the well.

Abstract: A fluid containing a viscous hyposaline aqueous solution of first and second cationic polymers that include quatemized ammonium groups, wherein the first cationic polymer includes a hydrophilic base polymer structure and the second cationic polymer includes a lipophilic base polymer Also disclosed is a method of introducing the viscous fluid into an initial first interval of a subterranean formation, and diverting with the viscous fluid a treating fluid from the initial first interval to an initial second interval.

Abstract: Methods and processes for in-situ stimulation of hydrocarbon containing formations using energy to expand in-situ liquid hydrocarbons, thus rejuvenating naturally occurring fractures. In some embodiments, the energy is supplied as heat from injection of an oxygen containing fluid.

Abstract: A method comprises providing a treatment fluid comprising a gelling agent, an aqueous base fluid, a buffer composition comprising a plurality of salts, and a crosslinking agent; and contacting a subterranean formation with the treatment fluid. The aqueous base fluid is preferably seawater and the buffer composition includes one or more salts present in the treatment fluid from about 1 to about 1000 pounds per gallon of treatment fluid.

Abstract: Embodiments include methods for recovering petroleum products from a formation containing heavy crude oil. In one embodiment, a method includes positioning a steam generator within the petroleum-bearing formation, flowing a fuel source and an oxidizing agent into the steam generator, generating and releasing steam from the steam generator to heat the heavy crude oil, flowing a catalytic material containing a nanocatalyst into the petroleum-bearing formation, and exposing the catalytic material to the heavy crude oil. The method further provides forming lighter oil products from the heavy crude oil within the petroleum-bearing formation and extracting the lighter oil products from the petroleum-bearing formation. In some examples, the fuel source contains methane, syngas, or hydrogen gas, and the oxidizing agent contains oxygen gas, air, or oxygen enriched air. The nanocatalyst may contain cobalt, iron, nickel, molybdenum, chromium, tungsten, titanium, alloys thereof, or combinations thereof.

Abstract: A process for sealing off one or more segments of a gravel packed well to reduce the production of undesirable fluids. The process includes the installation of a removable plug and the installation of a removable sealant at a location in the gravel packing to separate portions of the formation that produce desirable products from portions that produce less desirable products. A flow poison is then squeezed into the portion of the formation that produces less desirable products. With wireline or other low-cost wellbore workover systems, access is re-engaged with the preferred formation including removal of plugs and sealants without mechanical drilling. The process allows increased production of preferred fluids by preventing less or non preferred fluids from displacing the preferred fluids and also reduces lifting costs that would otherwise be expended for lifting and expenses related to separating and disposing of non preferred fluids.

Abstract: A fracturing fluid, gravel pack fluid and/or frac pack fluid containing particles such as proppants, gravel and/.or sand, may contain an effective amount of a nano-sized particulate additive to fixate or reduce fines migration, where the particulate additive is an alkaline earth metal oxide, alkaline earth metal hydroxide, alkali metal oxides, alkali metal hydroxides transition metal oxides, transition metal hydroxides, post-transition metal oxides, post-transition metal hydroxides piezoelectric crystals and pyroelectric crystals. The nano-sized particulate additive is optionally bound to the particles with a coating agent such as an oil, alcohol, glycol, glycol ethers, ketones, terpenes, etc. The particle size of the magnesium oxide or other agent may be nanometer scale but may be a larger scale than nanometer but still relatively small, which scale may provide unique particle charges that help fixate the formation fines.

Abstract: Methods are provided for treating production fluid in an oil reservoir to reduce the amount of sulfide in the production fluid. The production fluid is treated with nitrate and/or nitrite ions in an aqueous solution that is added to an injection well that is in contact with the production well.

Abstract: A method of treating a subterranean formation may include placing a first treatment fluid into a subterranean formation through an access conduit connecting the subterranean formation to a wellbore at a pressure sufficient to form at least a portion of a fracture network; pumping a second treatment fluid comprising a propping agent into the fracture network such that the propping agent forms a proppant pack in at least a portion of the fracture network; placing a third treatment fluid comprising a secondary diverting agent into the fracture network so as to substantially inhibit fluid flow through at least a portion of the fracture network without substantially inhibiting fluid flow through the access conduit; and placing a fourth treatment fluid comprising a primary diverting agent into the wellbore such that the primary diverting agent substantially inhibits fluid flow through the access conduit.

Abstract: The instant disclosure is directed to a method of enhancing adsorption of a salt inhibitor onto a wellbore region, wherein the method comprises preconditioning the wellbore region, emplacing the salt inhibitor into the wellbore region, and shutting in the wellbore region for a period of time to at least initiate adsorption of the salt inhibitor onto the wellbore region. The salt inhibitor comprises an at least partially water soluble compound comprising a Group 3 to Group 15 metal and/or an at least partially water soluble compound having any one of the formulae: wherein X is O or S; and R1, R2, R3, R4, and when present, R5 and/or R6 each independently comprise an organic or an inorganic functional group.

Abstract: In or near real-time monitoring of fluids can take place using an opticoanalytical device that is configured for monitoring the fluid. Fluids can be monitored prior to or during their introduction into a subterranean formation using the opticoanalytical devices. Produced fluids from a subterranean formation can be monitored in a like manner. The methods can comprise providing an acidizing fluid comprising a base fluid and at least one acid; introducing the acidizing fluid into a subterranean formation; allowing the acidizing fluid to perform an acidizing operation in the subterranean formation; and monitoring a characteristic of the acidizing fluid or a formation fluid using at least a first opticoanalytical device within the subterranean formation, during a flow back of the acidizing fluid produced from the subterranean formation, or both.

Abstract: In or near real-time monitoring of fluids can take place using an opticoanalytical device that is configured for monitoring the fluid. Fluids can be monitored prior to or during their introduction into a subterranean formation using the opticoanalytical devices. Produced fluids from a subterranean formation can be monitored in a like manner. The methods can comprise providing a treatment fluid comprising a base fluid and at least one additional component; introducing the treatment fluid into a subterranean formation; allowing the treatment fluid to perform a treatment operation in the subterranean formation; and monitoring a characteristic of the treatment fluid or a formation fluid using at least a first opticoanalytical device within the subterranean formation, during a flow back of the treatment fluid produced from the subterranean formation, or both.

Abstract: A method for carrying out in-situ bitumen extraction can include a step of forming one or more vertical freeze walls within or around a deposit of bituminous material and establishing a laterally confined deposit of bituminous material; a step of injecting a solvent within the laterally confined deposit of bituminous material; a step of withdrawing a mixture of dissolved bitumen and solvent from within the laterally confined deposit of bituminous material; a step of injecting water within the laterally confined deposit of bituminous material; and a step of withdrawing a mixture of solvent and water from within the laterally confined deposit of bituminous material.

Abstract: Composite particulates for use in high permeability subterranean formations may contain, at least, a gel particulate having a solid particulate incorporated. Some methods of using the diverting agent may include introducing a treatment fluid comprising a base fluid and a diverting agent into at least a portion of a subterranean formation and allowing the diverting agent to bridge fractures, provide fluid loss control, seal the rock surfaces for fluid diversion, or plug an area along the annulus of a wellbore.

Abstract: A method and apparatus for treating a subterranean formation with a fluid, including forming a fluid including a organosilane and a particulate and introducing the fluid into a subterranean formation with exposed surfaces, wherein the organosilane modifies the particulate or surfaces or both. Also, a method and apparatus for treating a subterranean formation with a fluid, including forming a fluid including an organosilane and introducing the fluid into a subterranean formation with exposed surfaces, wherein the organosilane modifies the surfaces with a first functional group.

Abstract: An invert emulsion treatment fluid comprises: (A) an external phase, wherein the external phase comprises a hydrocarbon liquid; (B) an internal phase, wherein the internal phase comprises a hygroscopic liquid; (C) a suspending agent, wherein the suspending agent is a polymer, and wherein the polymer comprises urea linkages; and (D) a particulate, wherein the particulate has a density less than 3.5 g/cm3, wherein a test fluid consisting essentially of the external phase, the internal phase, the suspending agent, and the particulate, and in the same proportions as the treatment fluid, and after static aging for 2 months at a temperature of 200° F. (93.3 ° C.), has a 10 minute gel strength of at least 30 lb/100 ft2 (1,436 Pa) at a temperature of 120° F. (48.9° C.). A method of using the invert emulsion treatment fluid comprises: introducing the treatment fluid into a portion of a subterranean formation.

Abstract: A flooding fluid for use in petroleum recovery from a petroleum-bearing formation is prepared by mixing an oxygen scavenger consisting essentially of an alkaline aqueous solution of at least one water-soluble borohydride with an aqueous or nonaqueous input fluid having oxygen dissolved therein to reduce the level of dissolved oxygen.

Abstract: Methods and fluids are provided for the placement of a water-swellable polymer into a subterranean formation. The methods and fluids include a placement fluid that has an acidic aqueous phase. The water-swellable polymer does not substantially swell in the acidic aqueous phase. The acid is allowed or caused to be spent downhole, whereby the water-swellable polymer can then swell in the formation. In an embodiment, an oil-external emulsion having an internal acidic water phase is provided for placement of a water-swellable polymer into a subterranean formation. Preferably, the oil-external emulsion is adapted to break as the acid contained in the internal water phase is allowed or caused to be spent downhole.

Abstract: An effective hydrogen sulfide scavenger that produces little corrosion may be prepared by reacting glyoxal with a compound having at least two primary or secondary amine groups. The subject hydrogen sulfide scavengers may be used with both the production of crude oil and natural gas, and the refining of same.

Abstract: A subterranean formation penetrated by a wellbore is treated by introducing into the wellbore an encapsulated material comprising an encapsulating component formed from a regenerated ionic-liquid-dissolved compound and an active component that is encapsulated by the encapsulating component. The encapsulating material is then allowed to release the active component into the formation. In another treatment method, an encapsulated material comprising an encapsulating component and an active component that is encapsulated by the encapsulating component are introduced into the wellbore. The encapsulating component is degradable when subjected to electromagnetic radiation having a frequency of from about 300 MHz to about 300. The encapsulated material is then subjected to electromagnetic energy in the frequency range of from about 300 MHz to about 300 GHz to degrade the encapsulating component and facilitate the release the active component into the formation.

Abstract: A process for fracturing a subterraneous formation in the production of an oil well is described. The process steps include injecting an initial charge of a mixture, the mixture being formed from at least a water-insoluble adsorbent and at least one well treatment agent, into a well bore formed in the subterraneous formation so as to form a downhole matrix within the formation; injecting a solution comprised of an additional amount of the well treatment agent into the formation after the initial charge of the at least one well treatment agent has been substantially depleted; and then pressurizing the well bore for a time and under conditions sufficient to reactivate the downhole matrix in the formation, so that the treatment agent activity of the matrix is increased relative to the treatment agent activity of the matrix just prior to injecting the solution.

Abstract: One or more compositions and methods for inhibiting the formation of hydrate agglomerates in a fluid that contain a specified generic formula are disclosed. The fluid can be contained in an oil or gas pipeline or refinery.

Abstract: A well treatment composition is formed from a fluid mixture of a viscoelastic surfactant and a liquid carrier fluid. The fluid mixture has rheological properties wherein the mixture exhibits shear-thickening behavior when the shear rate is increased from a first shear rate to a second higher shear rate. The fluid mixture may further include a shear activation additive that interacts with the viscoelastic surfactant to facilitate the shear-thickening behavior. The method is accomplished by introducing the fluid mixture into a wellbore formed in a subterranean formation. In certain applications, the fluid mixture may be recycled by bringing the fluid mixture to the surface and reintroducing the fluid into the same or a different wellbore.

Abstract: A method of treating a subterranean formation of a well bore comprises providing a treatment fluid comprising a carrier fluid, a particulate material, a viscosifying agent and fumed silica, wherein fumed silica is in such concentration to reduce the settling rate of the particulate material in the treatment fluid; and introducing the treatment fluid into the wellbore.

Abstract: According to one embodiment, a treatment fluid for a well includes: (a) a water-soluble polymer, wherein the water-soluble polymer comprises a polymer of at least one non-acidic ethylenically unsaturated polar monomer; (b) an organic crosslinker comprising amine groups, wherein the organic crosslinker is capable of crosslinking the water-soluble polymer; (c) a Lewis acid; and (d) water; wherein the treatment fluid is a crosslinkable polymer composition.

Abstract: A method of servicing a wellbore in a subterranean formation comprising placing a first stream comprising a dilute solution of a metal acrylate into a lost circulation zone in the subterranean formation; placing a second stream comprising an activator into the lost circulation zone; and forming a lost circulation material upon contacting of the metal acrylate and the activator, wherein the lost circulation material forms in from about 0 to about 60 minutes. A method of servicing a wellbore in a subterranean formation comprising placing a composition comprising a dilute solution of a cross-linkable material and an encapsulated activator into a lost circulation zone in the subterranean formation; and allowing the composition to set.

Abstract: Exemplary embodiments provide methods of treating a subterranean formation to improve gas production therefrom. Exemplary embodiments of the methods comprise introducing a cationic polyorganosiloxane into the subterranean formation, wherein the cationic polyorganosiloxane comprises at least two quaternary ammonium groups.

Abstract: A method for minimizing the amount of metal crosslinked viscosifier necessary for treating a wellbore with proppant or gravel is given. The method includes using fibers to aid in transporting, suspending and placing proppant or gravel in viscous carrier fluids otherwise having insufficient viscosity to prevent particulate settling. Fibers are given that have properties optimized for proppant transport but degrade after the treatment into degradation products that do not precipitate in the presence of ions in the water such as calcium and magnesium. Crosslinked polymer carrier fluids are identified that are not damaged by contaminants present in the fibers or by degradation products released by premature degradation of the fibers.

Abstract: A treating fluid may contain an effective amount of a particulate additive to fixate or reduce fines migration, where the particulate additive is an alkaline earth metal oxide alkaline earth metal hydroxide, alkali metal oxides, alkali metal hydroxides transition metal oxides, transition metal hydroxides, post-transition metal oxides, post-transition metal hydroxides piezoelectric crystals and pyroelectric crystals. The particle size of the magnesium oxide or other agent may be nanometer scale, which scale may provide unique particle charges that help fixate the formation fines. These treating fluids may be used as treatment fluids for subterranean hydrocarbon formations, such as in hydraulic fracturing, completion fluids, gravel packing fluids and fluid loss pills. The carrier fluid used in the treating fluid may be aqueous, brine, alcoholic or hydrocarbon-based.

Abstract: A method of heterogeneous proppant placement in a subterranean fracture is disclosed. The method comprises injecting well treatment fluid including proppant and a channelant 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 channelant, and removing the channelant 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 channelant can be dissolvable particles, initially acting as a filler material during placement of the proppant, and later dissolving to leave the flow channels between the proppant pillars. The well treatment fluid can include fibers to provide reinforcement and consolidation of the proppant and/or to inhibit settling of the proppant in the treatment fluid.

Abstract: The application relates to a sustainable and green remedial approach for in situ remediation. The system and method use directionally drilled horizontal wells filled with granular reactive media generally installed in the direction of groundwater flow for groundwater remediation. “Flow-focusing” behavior is leveraged to capture and passively treat proportionally large volumes of groundwater in situ. The system and method perform well in low hydraulic conductivity environments where the success of other in situ remediation methods is controlled by aquifer injectability. Reactive media are selected according to the contaminants to be treated and site characteristics. Energy conservation and other considerations result in considerable cost savings compared to current in situ remediation systems.

Abstract: Compositions and methods pertaining to the ultrafine grinding of soft materials are disclosed. In one embodiment, a method comprises the step of mixing a soft material with an additive to form a mixture. The method further comprises raising the temperature of the mixture to at least the glass transition temperature of the soft material. The method further comprises cooling the temperature of the mixture. The method further comprises grinding the mixture to form ultrafine particles that comprise at least a portion of the soft material.

Abstract: Fluid compositions and methods of making and using same are described, one composition comprising a well treatment fluid and an additive combined with the well treatment fluid, wherein the additive is selected from solids, liquids and combinations thereof, the additive having a surface shape, at least one property of the surface shape enabling it to change under influence of a controllable parameter after the composition is deployed into a hydraulic fracture or gravel pack. In methods of the disclosure, the additive exists initially in a first state, and then is changed to a second state. The first state may increase proppant flowback efficiency, while the second state may increase hydraulic conductivity. In certain embodiments, the additive may change back to its first state.

Abstract: Microbial biomass from oleaginous microbes provides a cost-efficient, biodegradable additive for use in well-related fluids. The biomass is useful as a fluid loss control agent, viscosity modifier, emulsifier, lubricant, or density modifier.

Abstract: Water flood materials may contain an effective amount of a nano-sized particulate additive to inhibit or control the movement of fines within a subterranean formation during a water flood secondary recovery operation. The particulate additive may be an alkaline earth metal oxide, alkaline earth metal hydroxide, alkali metal oxide, alkali metal hydroxide, transition metal oxide, transition metal hydroxide, post-transition metal oxide, post-transition metal hydroxide, piezoelectric crystal, and/or pyroelectric crystal. The particle size of the magnesium oxide or other agent may be nanometer scale, which scale may provide unique particle charges that help control and stabilize the fines, e.g. clays.

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: Methods of using relative permeability modifiers for the diversion of aqueous fluids during subterranean operations are provided. An embodiment of the present invention provides a method of diverting fluids in a subterranean formation that may comprise providing a treatment fluid comprising an aqueous fluid and a relative permeability modifier that comprises water-soluble polymer with hydrophobic or hydrophilic modification; introducing the treatment fluid into a well bore that penetrates the subterranean formation; and at least a first portion of the treatment fluid to penetrate into a portion of the subterranean formation so as to substantially divert a second portion of the treatment fluid or another aqueous treatment fluid to another portion of the subterranean.

Abstract: Methods for treating clastic formations bearing brine and at least one of black oil or volatile oil using a composition containing a nonionic polymer and solvent. The solvent at least one of solubilizes or displaces at least one of brine or oil in the clastic formation. Methods for treating a formation having at least one fracture using a composition containing a nonionic polymer and solvent. Methods for making a composition for treating a clastic formation bearing brine and at least one of black oil or volatile oil.

Abstract: Disclosed embodiments relate to well treatment fluids and methods that utilize nano-particles. Exemplary nano-particles are selected from the group consisting of particulate nano-silica, nano-alumina, nano-zinc oxide, nano-boron, nano-iron oxide, and combinations thereof. Embodiments also relate to methods of cementing that include the use of nano-particles. An exemplary method of cementing comprises introducing a cement composition into a subterranean formation, wherein the cement composition comprises cement, water and a particulate nano-silica. Embodiments also relate to use of nano-particles in drilling fluids, completion fluids, simulation fluids, and well clean-up fluids.