Abstract: A method for forming a well and pipeline treating fluid is provided. The method comprises combining a cross-linkable gelling polymer, a scavenging compound capable of reducing a concentration of divalent and polyvalent metal ions and salts thereof available for reaction, a hydration solvent and optionally an acid. The resulting mixture has a pH ranging from about 3 to about 7 and a first viscosity. The mixture is maintained at conditions suitable for hydration of the cross-linkable gelling polymer until the mixture has a second viscosity that is greater than the first viscosity. The mixture is combined with an aqueous based fluid and at least one cross-linking agent. The pH of the mixture is raised to a sufficient level to allow a desired degree of cross-linking to occur. Other methods, a well and pipeline treating gel and a well and pipeline treating fluid are also provided.

Abstract: An aqueous-based downhole fluid having a lubricant therein may be circulated within a subterranean reservoir wellbore where the downhole fluid may be or include a drilling fluid, a completion fluid, a fracturing fluid, a drill-in fluid, a workover fluid, and combinations thereof. The lubricant may include a clay stabilizer and a vegetable oil derivative, such as but not limited to, a sulfonated vegetable oil. The downhole fluid may include the lubricant in an effective amount for lubricating a first surface.

Abstract: An improvement over known hydraulic fracturing fluids. Boundary layer kinetic mixing material is added to components of fracturing fluid wherein kinetic mixing material is a plurality of particles wherein at least 25% of particles are several types, i.e., having surface characteristics of thin walls, three dimensional wedge-like sharp blades, points, jagged bladelike surfaces, thin blade surfaces, three-dimensional blade shapes that may have shapes similar to a “Y”, “V” or “X” shape or other geometric shape, slightly curved thin walls having a shape similar to an egg shell shape, crushed hollow spheres, sharp bladelike features, 90° corners that are well defined, conglomerated protruding arms in various shapes, such as cylinders, rectangles, Y-shaped particles, X-shaped particles, octagons, pentagon, triangles, and diamonds.

Abstract: Spray dried emulsifier compositions are described, which have desirable emulsifying and wetting characteristics. Among other advantages, the solid particulate emulsifier compositions greatly reduce transportation costs and simplify the logistics and environmental concerns associated with shipping large volumes of solvent-containing liquids. The emulsifier comprises (1) a carboxylic acid terminated fatty amine condensate or (2) a modified tall oil or (3) a blend of (1) and (2) that is converted to its alkali or alkaline earth metal salt and spray dried.

Abstract: Stimulation valves for a well tubular having a cylindrical housing adapted for assembly into a tubular for a well. The valves have ports allowing fluid communication between a central conduit and the exterior of the housing and a valve body adapted for movement from a closed position to an open position allowing fluid communication through the ports. A ball seat is mounted in the valve conduit above the ports. The ball seat has an initial ball-catch state in which a ball may be received in the ball seat to move the valve body from its closed position to its open position. The ball seat is adapted to transition to a ball-pass state and release the ball as the valve body is moved to the open position. The ball seat remains in the ball-pass state after the transition from the ball-catch state.

Abstract: Stimulation valves are provided that have a valve housing, an indexed driver, a reciprocating shifter, an actuation seat, and an isolation seat. The indexed driver is linearly actuated from an initial position through intermediate positions to a terminal position. In the driver initial and intermediate positions, the valve body shuts off fluid communication through ports provided in the housing. In the driver terminal position the valve body allows fluid communication through the ports. The reciprocating shifter indexes the indexed driver from its initial position through its intermediate positions to its terminal position. The actuation seat receives a ball for actuation of the shifter and releases the ball after actuation of the shifter. The isolation seat allows passage of the ball when the indexed driver is in its initial and intermediate positions and receives the ball when the indexed driver is in its terminal position.

Abstract: Methods and compositions are provided wherein microorganisms are used to alter the interface of hydrocarbons and hydrocarbon-coated surfaces to increase oil recovery, for improved bioremediation and/or to benefit pipeline maintenance.

Abstract: A method is described for the recovery of hydrocarbon from a reservoir. The method includes arranging a chamber in fluid communication with the reservoir via at least one conduit, and having the chamber comprising first and second wall parts movable relative to each other. An impact pressure is provided in the fluid to propagate to the reservoir via the conduit, where the impact pressure is generated by a collision process between an object arranged outside of the fluid and the first wall parts for the first wall part to impact on the fluid in the chamber. Further, the chamber is arranged to avoid a build-up of gas-inclusions where the first wall part impacts on the fluid. This may be obtained by arranging the conduit in or adjacent to the zone where the gas-inclusions naturally gather by influence of the gravitational forces, or by placing the first wall part impacting on the fluid away from this zone. The invention further relates to a system for the generation of impact pressure.

Abstract: The enhanced oil recovery using seawater and EDTA (ethylenediaminetetraacetic acid) is a method that uses injection of EDTA in seawater to enhance the recovery of oil from sandstone reservoirs. The EDTA may be introduced into seawater during the initial extraction of oil from the reservoir by seawater injection, or a solution of EDTA in seawater may be used to flush residual oil from the reservoir after the initial extraction by seawater injection. In either case, the EDTA is present in about 1.0 wt % to about 5.0 wt % of the seawater solution, and the solution has a pH of between 10.5 and 11.0.

Abstract: A method of extracting hydrocarbon from oil containing rocks is herein disclosed. According to one embodiment a method includes mixing oil sandstone and a phosphonium based ionic liquid and subjecting the resulting mixture to microwave radiation of 2.54 Gigahertz. Within 1 minute the trapped hydrocarbon is extracted into the ionic liquid which can be subsequently processed to remove the hydrocarbons from the ionic liquid.

Abstract: Fluids viscosified with viscoelastic surfactants (VESs) may have their fluid loss properties improved with the presence of at least one mineral oil slurried together in combination with at least one particulate fluid loss control agent that may be an alkaline earth metal oxides, alkaline earth metal hydroxides, transition metal oxides, transition metal hydroxides, and mixtures thereof. The mineral oil having the particulate fluid loss control agents slurried within it may initially be dispersed oil droplets in an internal, discontinuous phase of the fluid. In one non-limiting embodiment, the slurry is added to the fluid after it has been substantially gelled. The mineral oil/particulate slurry may enhance the ability of a particulate fluid loss control agent to reduce fluid loss. The presence of the mineral oil may also eventually reduce the viscosity of the VES-gelled aqueous fluid.

Abstract: A method for reducing sulfide in oilfield waste water includes contacting oilfield waste water with an oxidizer in the presence of an iron catalyst. The oilfield waste water includes sulfide that is oxidized to sulfate while avoiding formation of a colloidal or bulk sulfur precipitate. A method for recycling oilfield waste water includes contacting oilfield waste water with an oxidizer in the presence of an iron catalyst, the oilfield waste water comprising sulfide; oxidizing the sulfide to sulfate; avoiding formation of a colloidal sulfur precipitate, a bulk sulfur precipitate, or a combination comprising at least one of the foregoing; clarifying the oilfield waste water by contacting the oilfield waste water with a flocculant to form an aggregate precipitate; separating the aggregate precipitate from the oilfield waste water to form a recycled water; combining an additive with the recycled water; and disposing the recycled water in a downhole environment.

Abstract: In general, the current disclosure relates to multicomponent fibers that have accelerated degradation in water in low temperature conditions, and their various industrial, medical and consumer product uses. Such materials are especially useful for uses in subterranean wells in oil and gas production. In some embodiments, the compositions of materials have accelerated degradation even at Ultra Low Temperature (“ULT”) (?60° C.) in subterranean formations.

Abstract: Process for the removal of CO2 from a gas comprising CO2, comprising the steps of: (a) contacting the gas in an absorber (102) with an aqueous solution of one or more carbonate compounds in the presence of an accelerator, thereby reacting at least part of the CO2 to form a bicarbonate compound, under conditions such that at least a part of the bicarbonate compound formed precipitates, forming a bicarbonate slurry; (b) subjecting at least part of the bicarbonate slurry to a concentration step (105) to obtain the aqueous solution and a concentrated bicarbonate slurry, wherein the concentrated bicarbonate slurry comprises in the range of from 10 to 60 wt % of bicarbonate compounds; (c) returning at least part of the aqueous solution to the absorber; (d) transferring a first part of the concentrated bicarbonate slurry to a first heat exchanger (110a), wherein the first part of the slurry is being heated against a hot lean solvent of a regenerator (112); (e) transferring a second part of the concentrated bicarbona

Abstract: When used outside the pH range at which metal ion complexation normally occurs, aminopolycarboxylic acids can moderate the reaction rate of acids with carbonate minerals. Methods for treating a subterranean formation can comprise: providing a treatment fluid comprising an aqueous carrier fluid, an acid, and a chelating agent comprising an aminopolycarboxylic acid, the treatment fluid having a pH below that at which the carboxylic acid groups of the chelating agent are substantially protonated and the chelating agent is ineffective for complexing a metal ion; introducing the treatment fluid into a subterranean formation comprising a carbonate mineral; reacting the acid with the carbonate mineral, such that the acid at least partially spends and the pH of the treatment fluid rises; and once the pH of the treatment fluid rises above a pKa value for one or more of the carboxylic acid groups, complexing a metal ion with the chelating agent.

Abstract: A process for treating oilfield waste water includes combining oilfield waste water and a biocide comprising hydrogen peroxide, the biocide being present in an amount effective to decrease a number density of bacteria in the oilfield waste water. A process for treating oilfield waste water includes measuring an oxidation reduction potential (ORP) of oilfield waste water; combining the oilfield waste water and an oxidizer in an amount to adjust the ORP of the oilfield waste water to be greater than or equal to a first ORP value; and adding a biocide comprising hydrogen peroxide to the oilfield waste water to adjust the ORP of the oilfield waste water to be greater than or equal to a second ORP value, to treat the oilfield waste water, the second ORP value being greater than the first ORP value.

Abstract: Methods and compositions for stimulating of the production of hydrocarbons (e.g., formation crude oil and/or formation gas) from subterranean formations are provided. In some embodiments, the compositions are emulsions or microemulsions, which may include water, a solvent, and a surfactant. In some embodiments, methods of selecting a composition for treating an oil or gas well are provided.

Abstract: Various embodiments disclosed relate to acidizing compositions including an ampholyte polymer. Various embodiments provide a method of treating a subterranean formation. The method can include placing in a subterranean formation an ampholyte polymer including an ethylene repeating unit including a —C(O)NH2 group, an ethylene repeating unit including an —S(O)2OR1 group, and an ethylene repeating unit including an —N+R23X? group. At each occurrence, R1 can be independently selected from the group consisting of —H and a counterion. At each occurrence, R2 can be independently substituted or unsubstituted (C1-C20)hydrocarbyl. At each occurrence, X? can be independently a counterion.

Abstract: A wellbore fluid may include an oleaginous continuous phase, one or more magnetic carbon nanoribbons, and at least one weighting agent. A method of performing wellbore operations may include circulating a wellbore fluid comprising a magnetic carbon nanoribbon composition and a base fluid through a wellbore. A method for electrical logging of a subterranean well may include placing into the subterranean well a logging medium, wherein the logging medium comprises a non-aqueous fluid and one or more magnetic carbon nanoribbons, wherein the one or more magnetic carbon nanoribbons are present in a concentration so as to permit the electrical logging of the subterranean well; and acquiring an electrical log of the subterranean well.

Abstract: Methods and apparatus for using a fluid within a subterranean formation comprising forming a fluid comprising a fluid additive, introducing the fluid to a formation, observing a temperature, and controlling a rate of fluid introduction using the observed temperature, wherein the observed temperature is lower than if no observing and controlling occurred. A method and apparatus to deliver fluid to a subterranean formation comprising a pump configured to deliver fluid to a wellbore, a flow path configured to receive fluid from the pump, a bottom hole assembly comprising a fluid outlet and a temperature sensor and configured to receive fluid from the flow path, and a controller configured to accept information from the temperature sensor and to send a signal.

Abstract: In general, the current application relates to degradable composite and blend materials that have accelerated degradation in water in low temperature conditions, and their various industrial, medical and consumer product uses. In some embodiments, the degradable composite composition comprises a degradable polymer mixed with discrete particles of a filler that acts to accelerate the degradation of the degradable polymer. Such materials degrade in 60 C water in less than 30 days, <14 days, and even <7 days. Various materials are provided that can degrade equally fast at lower temperatures, such as 50 C, or even 40 C.

Abstract: A method of servicing a wellbore comprising identifying lost circulation zone within a wellbore; and placing in the wellbore a composition comprising a wax and a water-based mud wherein placement of the composition reduces or prevents a loss of fluids to the lost circulation zone. A wellbore servicing fluid comprising a water-based mud, a sized calcium carbonate particle and a wax.

Abstract: An aqueous-swellable and degradable diverting system and the use of the system in treating a subterranean formation penetrated by a wellbore. The diverting system includes a carrier fluid and a partially dehydrated or anhydrous borate source material that does not swell or does not swell substantially when placed in contact with the carrier fluid. The carrier fluid is capable of carrying and placing the borate source material into a stimulation network substantially distanced from a wellbore. Exposure of the diverting composition to a sufficient amount of aqueous fluid swells the borate source material, bridges a desired portion of the stimulation network, and then dissolves at least a portion of the diverting composition. The diverting techniques allow for treatment in a subterranean formation to be diverted to a previously untreated portion of the formation, in particular a portion of the formation that is significantly distanced from the wellbore.

Abstract: This invention is generally related to using treatment fluids having additives that modify rheological characteristics. Some embodiments of the present invention provide methods of using treatment fluids comprising an aqueous fluid and an associative polymer additive, wherein the associative polymer additive increases the PV of the treatment fluid by more than at least 50% and wherein the associative polymer additive increases the yield point by no more than about 30% of the corresponding increase in the PV relative to a treatment fluid without the associative polymer additive in a portion of a subterranean formation.

Abstract: Methods of treating a subterranean formation penetrated by a well bore, by providing a treatment fluid comprising a blend including a first amount of particulates having a first average particle size between about 3 mm and 2 cm and a second amount of particulates having a second average size between about 1.6 and 20 times smaller than the first average particle size or a second amount of flakes having a second average size up to 10 times smaller than the first average particle size; by introducing the treatment fluid into the well bore; and by creating a plug with the treatment fluid.

Abstract: A method of using a water based solution having a controllable gel time. The method includes providing a predetermined ratio of a water soluble silicate solution having at least one alkali metal, providing a predetermined ratio of a water dispersible polymer, and providing a predetermined ratio of a water soluble initiator containing a reactive carbonyl compound. One embodiment of the method also includes combining the water soluble silicate solution, the dispersible polymer, and the water soluble initiator and injecting downhole in a single stage treatment. Another embodiment of the method includes pre-mixing at least the water soluble silicate solution and the dispersible polymer into a mixture, then injecting the water soluble initiator and the mixture downhole separately for a multi-stage treatment with in situ mixing.

Abstract: A method is taught for creating a laterally-continuous, vertically-oriented dilation zone connecting the two SAGD wells. The method comprises the steps of drilling and completing the SAGD wells in a formation, conditioning said wells to create a stress condition favorable for forming a dilation zone, injecting one or both of said two wells with a stimulant at pressures greater than the in-situ minimum stress of the formation to initiate the dilation zone connecting said SAGD wells and continuing stimulant injection into a first of said two wells while maintaining a target pressure at a second of said two wells to propagate the dilation zone homogenously along the well length.

Abstract: Various embodiments disclosed relate to a composition including a crosslinkable ampholyte polymer or a crosslinked product of the same, methods of making and using the composition, and systems including the composition. In various embodiments, the present invention provides a method of treating a subterranean formation. The method can include obtaining or providing a composition including a crosslinkable ampholyte polymer. The crosslinkable ampholyte polymer can include an ethylene repeating unit including a —C(O)NH2 group, an ethylene repeating unit including a —S(O)2OR1 group, and an ethylene repeating unit comprising an —N+R23X? group. At each occurrence, R1 can be independently selected from the group consisting of —H and a counterion. At each occurrence, R2 can be independently substituted or unsubstituted (C1-C20)hydrocarbyl. At each occurrence, X? can be independently a counterion. The composition can also include at least one crosslinker.

Abstract: The present invention provides a method for treating a formation containing crude oil hydrocarbons, comprising injecting an aqueous composition comprising an internal olefin sulfonate with a nominal carbon chain length between 24 to 44 into said formation and displacing said crude oil hydrocarbons toward one or more production wells. The invention further provides a method for treating a formation containing crude oil hydrocarbons, a method for improving the wettability of a subsurface surface in an subsurface formation containing crude oil hydrocarbons, and a method for separating crude oil hydrocarbons from crude oil hydrocarbons compositions.

Abstract: Described are methods of distributing a viscosity reducing solvent to a set of wells terminating in an underground oil reservoir where the variation in the net solvent injection rate is minimized. The net solvent injection rate is the difference between the total solvent injection rate and the total solvent production rate from the set of wells, for example on an instantaneous or daily rate basis. Minimizing this variation can reduce costs associated with surface solvent storage, subsurface solvent storage, and solvent supply, since solvent supply often is least expensive when supplied at near a fixed rate. One option is to operate well pairs and to inject solvent into one well of the pair while producing oil and solvent from the other well of the pair. These methods are particularly useful in solvent-dominated, cyclic or non-cyclic, viscous oil recovery processes.

Abstract: A method for drilling through a producing zone in a subterranean formation or for completing a wellbore in a subterranean formation, using a drill-in and completion fluid comprising a blend of a phosphate brine and water.

Abstract: A method of inhibiting the deposition of asphaltene in a mixture comprising hydrocarbons, the method comprising contacting the mixture with a composition which comprises at least one poly(hydroxycarboxylic acid) amide salt derivative.

Abstract: The method of maintaining oil reservoir pressure involves injecting seawater having a concentration of about 1 wt % of a polyamino carboxylic acid or salt thereof as a chelating agent into the water zone of an oil reservoir, which reduces the formation of scale, thereby maintaining oil reservoir pressure. The polyamino carboxylic acid may be ethylenediaminetetraacetic acid (EDTA), acid (HEDTA), or hydroxyethyliminodiacetic acid (HEIDA). When used in larger concentrations, e.g., between 5 to 10 wt %, flooding the core with seawater containing the polyamino carboxylic acids not only prevents scale formation, but also improves core permeability. Instead of seawater, low salinity water may be used for the latter purpose.

Abstract: The invention discloses a method of for changing the water permeability of a subterranean formation of a well, the method comprising: providing a fluid comprising a liquid carrier and a viscoelastic surfactant; introducing the fluid into the well; and contacting the fluid and the subterranean formation wherein the action of the liquid carrier and the viscoelastic surfactant is able to change the water permeability of the subterranean formation. The fluid may further comprise methanol, or a salt which can be embodied within the carrier fluid. Advantageously, no further RPM polymer is used. In a first aspect the method is used for reducing the amount of water produced, in as second aspect for improving the oil recovery.

Abstract: Methods and systems for completing a well including injecting a stimulation fluid to stimulate a first interval in the reservoir. The stimulation fluid is at a pressure sufficient to open a number of check valves in the first interval, allowing stimulation fluid to flow into the first interval. A number of ball sealers configured to block flow through the check valves are dropped into the well to stop the flow of the stimulation fluid into the first interval and begin treatment of a second interval. The stimulation fluid is injected to stimulate a subsequent interval with pressure sufficient to open a number of check valves in the subsequent interval, allowing stimulation fluid to flow into the subsequent interval. The dropping of ball sealers is repeated until all intervals are treated.

Abstract: Embodiments described herein provide methods and systems for generating a CO2 product stream. A method described includes generating a liquid acid gas stream including H2S and CO2. The liquid acid gas stream is flashed to form a first vapor stream and a bottom stream. The bottom stream is fractionated to form a second vapor stream and a liquid acid waste stream. The first vapor stream and the second vapor stream are combined to form a combined vapor stream. The combined vapor stream is treated in an absorption column to remove excess H2S, forming the CO2 product stream.

Abstract: A treatment fluid for treating a portion of a subterranean formation comprises: a base fluid, wherein the base fluid comprises a hydrocarbon liquid; and a gellant, wherein the gellant: is a polymer; and is activated at an activation temperature, wherein the thermal activation of the gellant causes the treatment fluid to become a gel. A method of treating a portion of a subterranean formation includes introducing the treatment fluid into the portion of the subterranean formation, wherein the subterranean formation is penetrated by a well, wherein at least a portion of the well has a bottomhole temperature greater than or equal to the activation temperature, and wherein the step of introducing comprises introducing the treatment fluid into the portion of the well.

Abstract: A treatment fluid comprising: water; a formate; and a corrosion inhibitor, wherein the corrosion inhibitor is capable of providing: (A) a pH of at least 10; and (B) a corrosion rate equal to or less than 4 mils per year wherein carbon dioxide accounts for at least 100 psi (0.7 MPa) of the total pressure, for a test fluid consisting essentially of: the water; the formate; and the corrosion inhibitor, and in the same proportions as in the treatment fluid, whereas a substantially identical test fluid without the corrosion inhibitor has a pH of less than 10 and a corrosion rate of greater than 4 mils per year under the testing conditions. The treatment fluid can further comprise a scale inhibitor. A method of treating a portion of a well comprises: forming the treatment fluid; and introducing the treatment fluid into the well.

Abstract: Inhibiting gas hydrate formation while transporting hydrocarbon fluids may include providing a kinetic gas hydrate inhibitor, adding the kinetic gas hydrate inhibitor to a fluid capable of producing gas hydrates, and transporting the fluid that comprises the kinetic gas hydrate inhibitor. Generally a kinetic gas hydrate inhibitor may include a heterocyclic compound comprising nitrogen, e.g., poly(vinyl pyrrolidone).

Abstract: Embodiments disclosed herein relate to methods for stabilizing shales while drilling a wellbore into an earthen formation comprising circulating an aqueous based wellbore fluid in the wellbore while drilling through shales; wherein the aqueous-based wellbore fluid comprises a copolymer of acrylamide-type comonomers and at least one cationic comonomer.

Abstract: Methods of treating a subterranean formation including providing a treatment fluid comprising an oil-based fluid component and an oil-soluble weighting agent that comprises a metal, wherein the oil-soluble weighting agent has a density in the range of from about 1.1 g/cm3 to about 22 g/cm3; solubilizing the oil-soluble weighting agent in the oil-based fluid component of the treatment fluid, wherein the oil-soluble weighting agent increases the density of the oil-based fluid component of the treatment fluid; introducing the oil-based treatment fluid into a wellbore in a subterranean formation.

Abstract: The present invention relates to a method for the assisted recovery of crude oil from an underground formation, comprising: a) injecting, via at least one injection means in contact with the underground formation containing the crude oil, a liquid containing a mixture of at least: i) a salty aqueous medium, ii) a mixture of two zwitterionic viscosising surfactants or a mixture of two populations of said surfactants having a bimodal characteristic of the narrow distribution of Ri groups as defined below, in a weight content of between 1 and 0.05 wt %, preferably between 0.5 and 0.1 wt %, and more preferably between 0.4 and 0.15 wt %, such that the liquid has an oil/water interface tension of about 10 mN/m (milinewton per meter) or less as measured at room temperature (25° C.) and a viscosity of about 3 cPs or more as measured at a temperature of 80° C.

Abstract: A method of servicing a subterranean formation comprising providing a wellbore penetrating the subterranean formation and having a casing string disposed therein, the casing string comprising a plurality of points of entry, wherein each of the plurality of points of entry provides a route a fluid communication from the casing string to the subterranean formation, introducing a treatment fluid into the subterranean formation via a first flowpath, and diverting the treatment fluid from the first flowpath into the formation to a second flowpath into the formation.

Abstract: Systems and methods for separating CO2 and H2S from a natural gas stream are provided herein. The system includes a first loop of co-current contacting systems configured to remove H2S and CO2 from a natural gas stream and a second loop of co-current contacting systems configured to remove the H2S from the CO2.

Abstract: Compositions and methods relating to treatment fluids that comprise entangled equilibrium polymer networks in subterranean applications. Such methods include providing a treatment fluid comprising at least one entangled equilibrium polymer network, and placing the treatment fluid in a subterranean formation. Other methods include providing a treatment fluid having a first viscosity comprising an aqueous base fluid and at least one entangled equilibrium polymer network; placing the treatment fluid in a subterranean formation; contacting the treatment fluid with a hydrocarbon; and allowing the viscosity of the treatment fluid to decrease to a second viscosity that is lower than the first viscosity.

Abstract: A method for the treatment of a subterranean formation which contains sand particles, said method comprising contacting said formation with a positively charged polymer capable of increasing the residual matrix strength of said sand particles whereby to reduce or prevent their migration while minimizing any decrease in the permeability of said formation. Polymer materials suitable for use in the method of the invention include polyaminoacids, poly (diallyl ammonium salts) and mixtures thereof.

Abstract: A well that has a plurality of sliding sleeves used to originally fracture multiple zones with balls of increasing size dropped on balls seats to sequentially open ports for fracturing in a direction toward the well surface is refractured. The method involves using a bottom hole assembly (BHA) that has a fluid motor driven mill that mills out ball seats and has with it a ported sub and a resettable packer. Once the lowermost ball seat is milled out a ball is dropped into the BHA to isolate the fluid motor and open a ported sub below a resettable packer. The dropped ball also enables a collet to latch an open sleeve to give a surface signal that the BHA is located properly for packer deployment so that the refracturing can begin through the coiled tubing string that can support the BHA or in a surrounding annular space.

Abstract: Process for the enhanced recovery of oil comprising introducing into the injection fluid at least one linear or structured water-soluble copolymer obtained by polymerization of: 2-acrylamido-2-methylpropane sulfonic acid monomer in free acid and/or salified form, acrylamide derivative monomers of formule (I): in which: R?H or CH3 or CH2COOR?, wherein R? is an alkyl containing not more than 3 carbon atoms, A is selected from the group consisting of 2-pyrrolidone, pyrrolidine and 4-morpholine.

Abstract: A composition, treatment fluid and method using hydrolyzable fines. A treatment fluid, which may optionally include a high solids content fluid (HSCF) and/or an Apollonianistic solids mixture, includes a fluid loss control agent comprising a dispersion of hydrolyzable fines, optionally with one or more of a surfactant, plasticizer, dispersant, degradable particles, reactive particles and/or submicron particles selected from silicates, ?-alumina, MgO, ?-Fe2O3, TiO2, and combinations thereof.

Abstract: Process for enhanced oil recovery employing an aqueous solution comprising at least one linear or structured water-soluble copolymer obtained by polymerization: of at least 10 mol % of 2-acrylamido-2-methylpropanesulfonic acid monomer in the free acid and/or salified form, of at least 10 mol % of at least one comonomer chosen from the group consisting of acrylamide, N-vinylpyrrolidone (NVP) and acrylamide-derived monomers of formula (I): in which: R=H or CH3 or CH2COOR?, where R? is an alkyl comprising at most 3 carbon atoms, A is an N heterocycle comprising, in its ring, from 4 to 6 carbon atoms and optionally an ether functional group or a ketone functional group.