Abstract: An apparatus and process for separating a gas mixture is disclosed. The apparatus includes a plurality of membrane separation stages comprising a first membrane stage, a second membrane stage, and a third membrane stage. Each of the first, second, and third membrane stages are designed to separate a gas stream provided to them into a permeate stream and a retentate stream. The retentate stream provided from the third membrane stage is configured to be withdrawn as a product, further processed, or discarded. The apparatus further includes a gas transport device with an inlet in communication with the gas mixture and an outlet in communication with the first membrane stage. The controller is in communication with at least one measuring device, and the controller adapts a behavior of the gas transport device in response to a measurement of the at least one measuring device.

Abstract: Described herein are methods of treating fluid comprising hydrocarbons, water, and polymer being produced from a hydrocarbon-bearing formation are provided. The method can include adding a concentration of a viscosity reducer to the fluid to degrade the polymer present in the fluid and adding a concentration of a neutralizer to the fluid to neutralize the viscosity reducer in the fluid. The viscosity reducer is buffered at a pH of 7 or less (e.g., at a pH of from 2 to 7, such as at a pH of from 3.5 to 7, or at a pH of from 5 to 7). The addition of the concentration of the viscosity reducer is in a sufficient quantity to allow for complete chemical degradation of the polymer prior to the addition of the concentration of the neutralizer in the fluid such that excess viscosity reducer is present in the fluid.

Abstract: A method, apparatus, and system according to which a discharge manifold is pressurized by at least a first fracturing pump, said discharge manifold being adapted to communicate pressurized fluid to an oil and gas wellbore.

Abstract: In an embodiment, a hydrocarbon recovery material includes an organic acid and a water material, the organic acid including a naphthenic acid, L-proline, or combinations thereof. In another embodiment, an oil recovery method includes injecting a treatment fluid into a reservoir under reservoir conditions, the reservoir containing hydrocarbons, and the treatment fluid includes an organic acid and a water material. In another embodiment, an oil recovery method includes injecting a treatment fluid into a reservoir containing hydrocarbons, the treatment fluid comprising an organic acid in one or more of an oil-in-water emulsion, a resin dispersion, or a polymer capsule.

Abstract: A method and hydraulic fracturing fluid that is a viscoelastic surfactant (VES) fracturing fluid having a surfactant and an inorganic oxidizer salt for hydraulic fracturing of a geological formation. The VES fracturing fluid is provided through a wellbore into the geological formation to hydraulically fracture the geological formation to form hydraulic fractures in the geological formation. The method includes oxidizing organic material in the hydraulic fractures with the VES fracturing fluid.

Abstract: Compositions, systems, and methods for hydraulically fracturing a hydrocarbon-bearing formation, a method including injecting into the hydrocarbon-bearing formation under increased pressure a heavy oil fracturing fluid; allowing the heavy oil fracturing fluid to remain in situ for a period of time suitable to create fractures in the hydrocarbon-bearing reservoir, the heavy oil fracturing fluid operable to undergo an at least about 70% viscosity decrease in situ; and flowing back the heavy oil fracturing fluid to the surface without damaging the hydrocarbon-bearing formation or reducing production of hydrocarbons from the hydrocarbon-bearing formation.

Abstract: An oil recovery composition of an aqueous solution of one or more salts and dilute polymer and processes for enhanced oil recovery using the oil recovery composition are provided. An oil recovery composition may include an aqueous solution of one or more salts having a salinity of about 4000 parts-per-million (ppm) total dissolved solids (TDS) to about 8000 ppm TDS and a polymer having a concentration of 250 ppm to 750 ppm. The one or more salts may include at least one of sodium chloride (NaCl), calcium chloride (CaCl2), magnesium chloride (MgCl2), sodium sulfate (Na2SO4) and magnesium sulfate (MgSO4). The polymer may include a copolymer of acrylamide and acrylamido tertiary butyl sulfonate (ATBS). The oil recovery compositions provided may be suited for enhancing oil recovery in carbonate reservoirs having in situ oil viscosities less than 3 centipoise (cP).

Abstract: The present invention provides a method and system for providing on-site electrical power to a fracturing operation, and an electrically powered fracturing system. Natural gas can be used to drive a turbine generator in the production of electrical power. A scalable, electrically powered fracturing fleet is provided to pump fluids for the fracturing operation, obviating the need for a constant supply of diesel fuel to the site and reducing the site footprint and infrastructure required for the fracturing operation, when compared with conventional systems. The treatmenr fluid can comprise a water-based fracturing fluid or a waterless liquified petroleum gas (LPG) fracturing fluid.

Abstract: Y-Grade NGL fracturing systems and methods of using Y-Grade NGL stimulation fluids.

Abstract: A downhole fluid comprises a base fluid, for example a hydrocarbon base fluid, and a pyromellitamide gelling agent. The pyromellitamide gelling agent may have the general formula of: with R1, R2, R3, R4, R5, R6, R7, and R8 each being a hydrogen or an organic group. R1, R2, R3 and R4 may each be hexyl groups or may each be octyl groups. A composition for gelling a downhole fluid, the composition comprising a pyromellitamide gelling agent and a wetting agent.

Abstract: A method for determining a first concentration of a first component in an aqueous solution, the surface tension of which is altered by the presence of the first component. The method can include identifying a second concentration of at least one second component in the aqueous solution. The at least one second component can also alter the surface tension of the aqueous solution. The method can further include comparing a plurality of dynamic surface tension measurements of each of a plurality of aqueous test solutions with at least one dynamic surface tension measurement of the aqueous solution to determine the first concentration. The plurality of aqueous test solutions can include the first component at a plurality of concentrations and the at least one second component at the second concentration.

Abstract: Disclosed are systems and methods utilizing multiple parallel pumps to deliver a mixture of the proppant and clean fluid via a manifold trailer. One method of providing a step-change in proppant concentration includes selecting a first flow rate for a first pump connected between a first input node and first output node, calculating a first transit time for a flow of a fluid at the first flow rate through a first flow path extending from the first inlet node, through the first pump, and to the first outlet node, and calculating a second flow rate for a second pump connected between the first input node and the first output node such that a second transit time for a flow of the fluid through a second flow path extending from the first inlet node, through the second pump, and to the first outlet node is equal to the first transit time.

Abstract: Systems for preparing emulsions can include a first fluid tank, a second fluid tank, and a circulation loop comprising a buffer tank and a pump, in some arrangements. The first fluid tank and the second fluid tank can be in fluid communication with the circulation loop via a first fluid inlet pipe and a second fluid inlet pipe, respectively. An outlet pipe can be in fluid communication with the circulation loop.

Abstract: Methods of providing fluid loss control in a portion of a subterranean formation comprising: providing a treatment fluid comprising a base fluid and a plurality of seeds; introducing the treatment fluid into a portion of a subterranean formation penetrated by a well bore such that the seeds block openings in the subterranean formation to provide fluid loss control; and degrading the seeds over time within the subterranean formation. In some methods, the seeds are present in the treatment fluid in an amount of at least about 5 pounds per barrel. In addition, in some methods the seeds are preferably degradable.

Abstract: A method of treating a subterranean formation penetrated by a wellbore is carried out by preparing a treatment fluid at a surface location based upon an initial model of fluid properties for the treatment fluid. The treatment fluid is formed from a first fluid stream and at least one additive fluid stream that are combined to form a treatment fluid stream that is introduced into the wellbore in a substantially continuous process. A fluid property of at least one of the streams is monitored while forming the treatment fluid to provide at least one monitored fluid property of the at least one of the streams. The model is updated based upon the at least one monitored fluid property during the substantially continuous process. Optionally, at least one of the first fluid stream and the at least one additive stream is adjusted as necessary based upon the updated model.

Abstract: The invention provides formulations for facilitating the removal of oil from a surface using a chisel composition, wherein the chisel composition includes a polymer having one or more binding points with a high affinity for the surface, and one or more hydrophilic segments that form a hydrophilic coating on the surface, rendering the surface water-wet and thereby facilitating the removal of oil from the surface. The invention also provides for methods of use of such formulations.

Abstract: A method of treating a very high salinity high temperature hydrocarbon containing formation is described. The method includes (a) providing a hydrocarbon recovery composition to at least a portion of a hydrocarbon containing formation having a brine salinity of above about 13 wt % and a temperature of above about 7° C., wherein the composition comprises a C15-18 internal olefin sulfonate; and (b) allowing the composition to interact with hydrocarbons in the hydrocarbon containing formation.

Abstract: The invention relates to subterranean treatment fluids, and more particularly for hydraulic fracturing formulations, comprising a low viscosity hydrocarbon fluid having low pour point and low or no BTEX content combined with suitable additives, in particular with a thickening agent additive.

Abstract: A high carrying capacity temperature-stable breakable gel of selectable viscosity with exceptional lubricity and high-temperature stability for varied use as a carrier of solids and particulate matter, as well as semi-solids and liquids in water and petroleum well drilling, completion and production such as gravel pack fluid, drilling fluid, fracturing fluid, pigging fluid, sweep for coiled tubing, and other uses. A preferred formulation comprises a formulated “Base Concentrate” which is added to water or drilling fluids to be viscosified and an “Activator” which is added in amounts to develop the desired gel consistency. When breaking of the gel is desired a “Breaker” composition containing multivalent ions collapses the gel into a free-flowing liquid.

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: 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: Production-treating chemicals, such as paraffin inhibitors, corrosion inhibitors and scale inhibitors are provided along with water-soluble polymers in a base oil phase to be used in a well treatment. The mixture may be provided as a separate product or mixed at a well site when performing a well treatment, such as hydraulic fracturing, acidizing or gravel packing.

Abstract: A method of treating a portion of a subterranean formation that includes: providing a water-in-oil emulsion, inverting the water-in-oil emulsion to form a friction reducing treatment solution, and introducing the treatment solution into the portion of the subterranean formation. The water-in-oil emulsion has an oil phase, an aqueous phase and surfactants. The oil phase (O) and an aqueous phase (A) are present at an O/A ratio of from about 1:8 to about 10:1. The oil phase is present as a continuous phase and contains an inert hydrophobic liquid. The aqueous phase is present as a dispersed phase of distinct particles in the oil phase and includes water and a water soluble polymer. The water soluble polymer makes up from 10 to 25 weight percent of the water-in-oil emulsion. The water-in-oil emulsion is inverted by adding it to water to form a friction reducing treatment solution.

Abstract: Methods relating to servicing fluids that comprise gelled liquefied petroleum gas or servicing fluids that comprise a conventional gelled hydrocarbon fluid with liquefied petroleum gas are provided. In one embodiment, the methods of the present invention comprise providing a LPG servicing fluid comprising LPG and a gelling agent; pressurizing the LPG servicing fluid with one or more high-pressure pumps; introducing proppant particulates into at least a portion of the LPG servicing fluid using one or more high pressure pumps; and introducing the LPG servicing fluid comprising proppant particulates into at least a portion of a subterranean formation at a rate and pressure sufficient to create or enhance at least one or more fractures therein. In one embodiment, a gelling agent may be metered into the LPG on-the-fly.

Abstract: A method of servicing a wellbore in a subterranean formation comprising preparing an invert emulsion comprising an aqueous fluid, an oleaginous fluid, and an emulsifier composition (EC), wherein the emulsifier composition comprises an emulsifier, a diluent, and a thinner, wherein the thinner comprises an alcohol, a fatty acid amide, or combinations thereof; and placing the invert emulsion in the wellbore. A method of servicing a wellbore in a subterranean formation comprising flowing a wellbore serving fluid comprising an emulsifier composition (EC) through a portion of a subterranean formation, wherein the EC comprises an emulsifier, a diluent and a thinner and wherein the thinner comprises 2-methyl-1-propanol, 2-methyl-2-butanol, a fatty acid amide, or combinations thereof; contacting the EC with oil in situ within the formation to form an emulsion; and reducing the water-oil interfacial tension and altering the wettability to provide enhanced oil recovery from the formation.

Abstract: A method of servicing a wellbore in a subterranean formation comprising placing a wellbore servicing fluid comprising a resin-loaded expanded material into a wellbore wherein a resin is released from the resin-loaded expanded material in situ within the wellbore or subterranean formation. A wellbore treatment composition comprising a resin-loaded expanded material wherein the expanded material comprises polylactide and the resin material comprises a high-temperature epoxy-based resin.

Abstract: A substantially liquid gellant formed as one or more reaction products of a metal carboxylate or metal carboxylate amine salt, one or more organic acids, an ester which drives the reaction so that the reaction products are asymmetrical in structure, and a rheology modifier which preferentially interacts between the reaction products for prevent solidifying of the gellant reaction products until such time as the gellant is mixed with the fracturing fluid containing an activator after which the reaction products preferentially interact with the activator to gel the fracturing fluid. The resulting gellant is capable of gelling a hydrocarbon base fluid in less than about 30 seconds.

Abstract: This invention relates to compositions and methods of removing an organic deposit including introducing a fluid, wherein the fluid comprises at least two non-polar organic solvents and at least two polar organic solvents; allowing the fluid to dissolve at least a portion of the organic deposit; and removing at least a portion of the fluid. This invention relates to compositions and methods of removing an organic deposit including introducing a fluid, wherein the fluid comprises at least two non-polar organic solvents and at least two polar organic solvents, wherein the non-polar organic solvents comprise aromatic naphtha, terpenes, kerosene, and combination thereof, and wherein the polar solvents comprise heavy aromatic naphtha, cyclohexanone, N-2-methyl pyrrolidone, N-ethyl-2-pyrrolidone, and combination thereof, allowing the fluid to dissolve at least a portion of the organic deposit, and removing at least a portion of the fluid.

Abstract: A silicate gel composition that is useful for sealing the face of a fracture of a formation. A method of sealing a face of a fracture of a formation with the silicate gel composition and diverting an acid treatment fluid.

Abstract: The present invention generally relates to a viscoelastic fluids, thickened acid compositions and the like and to methods of using said gelled compositions. The thickened compositions of the present invention can usefully be employed in methods of stimulating and/or modifying the permeability of underground formations, in drilling fluids, completion fluids, workover fluids, acidizing fluids, fracturing, gravel packing and the like.

Abstract: A method for fraccing oil or gas wells to recover natural gas. Liquefied natural gas is vaporized to form a foam or dense fluid. The foam or dense fluid is compressed to high pressures. The high pressure natural gas foam or dense fluid is fed into the oil or gas well and once the well is pressurized to a pre-determined pressure and fracturing has begun, the flow of the foam or dense fluid is stopped. After a suitable period for fracturing to occur, the flow is reversed and the natural gas from the well and the foam or dense fluid fracturing fluid is recovered. The recovered and produced natural gas can be treated and made ready for use in other applications.

Abstract: The present disclosure is directed to a method of servicing a well. The method comprises providing a well servicing fluid. The well servicing fluid is formulated with the following components comprising, at least one friction reducer chosen from polychloroprenes, vinyl acetate polymers, polyalkylene oxides polyalphaolefins; and a nonaqueous carrier fluid. The well servicing fluid is introduced into the well.

Abstract: The invention describes improved fracturing compositions, methods of preparing fracturing compositions and methods of use. Importantly, the subject invention overcomes problems in the use of mists as an effective fracturing composition particularly having regard to the ability of a mist to transport an effective volume of proppant into a formation. As a result, the subject technologies provide an effective economic solution to using high ratio gas fracturing compositions that can be produced in a continuous (i.e. non-batch) process without the attendant capital and operating costs of current pure gas fracturing equipment.

Abstract: Disclosed herein are an acid emulsion fluid for use in sealing target portions of a hydrocarbon producing formation penetrated by a wellbore and the method of use thereof for fluid loss control.

Abstract: A method of fracturing a subterranean formation comprising at least in part shale formation, comprises providing a carrier fluid; providing a particulate blend including a first amount of particulates having a first average particle size between about 100 and 2000 microns and a second amount of particulates having a second average particle size between about three and twenty times smaller than the first average particle size, such that a packed volume fraction of the particulate blend exceeds 0.75; combining the carrier fluid and the particulate blend into a fracturing slurry; fracturing the formation with the fracturing slurry to create at least a fracture; and removing the second amount of particulates from the fracture.

Abstract: A composition and method are disclosed. The composition includes a carrier fluid and a solids mixture combined to form a slurry, wherein the solids mixture comprises a plurality of volume-averaged particle size distribution (PSD) modes, wherein a first PSD mode comprises solids having a volume-average median size at least three times larger than the volume-average median size of a second PSD mode such that a packed volume fraction of the solids mixture exceeds 0.75, and wherein the solids mixture comprises a degradable material and includes a reactive solid. The method includes circulating the slurry through a wellbore to form a pack in a fracture and/or a screen-wellbore annulus; degrading the degradable material to increase porosity and permeability of the pack; and producing a reservoir fluid through the permeable pack.

Abstract: A fracturing system for a well, in which a stream of LPG, a mixture of propane and butane, is injected into the well at frac pressure. Proppant is supplied into the LPG stream, and carried by the LPG mix into the formation. Inert gas such as nitrogen is used for purging system components of LPG, and to help protect against risk of explosion. Nitrogen may also be added to the LPG mix during a frac of shale gas or coal gas formations.

Abstract: Methods for treating a subterranean formation can comprise introducing a treatment fluid comprising dicarboxymethyl glutamic acid (GLDA) or a salt thereof into a subterranean formation, and at least partially removing an iron-containing material in the subterranean formation using the GLDA. Treatment fluids used in the methods may have a pH equal to or greater than about 2.

Abstract: Methods and systems of fracturing subterranean formations to are provided comprising pumping metacritical phase natural gas into a subterranean formation to create or extend one or more fissures in the formation. Methods and systems may further comprise maintaining or increasing pressure of the metacritical phase natural gas in the formation by pumping more metacritical phase natural gas into the fissures to hold the fissures open. Methods and systems may further comprise delivering a proppant into the subterranean formation. Disclosed methods and systems may be used to extract hydrocarbons from subterranean formations without the use of liquids.

Abstract: A process for concentrating and diluting a treatment substance to provide a diluted treatment for introduction to a wellbore is disclosed. In one embodiment, the process includes measuring a treatment fluid flow rate. The process also includes blending the treatment fluid with a treatment substance to produce a concentrated treatment fluid. The process further includes measuring a flow rate of the concentrated treatment fluid. Moreover, the process includes determining a difference between the treatment fluid flow rate and the flow rate of the concentrated treatment fluid. In addition, the process includes comparing the difference to a target difference. The process additionally includes adjusting the difference to be within a desired range of the target difference and diluting the concentrated treatment fluid to provide the diluted treatment fluid.

Abstract: A packer or annular fluid includes a hydrocarbon fluid; and a gelling agent; wherein the packer fluid is a yield power law fluid. A method for preparing a packer fluid includes preparing a mixture of a hydrocarbon fluid, and a gelling agent; heating the mixture to a selected temperature; and shearing the mixture. A method for emplacing a packer fluid into an annulus includes preparing the packer fluid that includes a hydrocarbon fluid and a gelling agent, wherein the packer fluid is a yield power law fluid; and pumping the packer fluid into the annulus.

Abstract: The invention describes improved fracturing compositions, methods of preparing fracturing compositions and methods of use. Importantly, the subject invention overcomes problems in the use of mists as an effective fracturing composition particularly having regard to the ability of a mist to transport an effective volume of proppant into a formation. As a result, the subject technologies provide an effective economic solution to using high ratio gas fracturing compositions that can be produced in a continuous (i.e. non-batch) process without the attendant capital and operating costs of current pure gas fracturing equipment.

Abstract: Method of treating a subterranean formation using a hydrocarbon treatment fluid using a phosphor-based hydrocarbon gelling agent that is capable of both increasing the viscosity of the hydrocarbon treatment fluid and remaining in the subterranean formation after the viscosity of the gel is broken such that it can act as a scale inhibitor. Phosphor-based hydrocarbon gelling agents may be formed from a polyvalent metal salt of an organophosphonic acid ester or from a polyvalent metal salt of an organophosphinic acid.

Abstract: A composition comprising a nonionic fluorinated polymeric surfactant having a weight average molecular weight of least 100,000 grams per mole, the nonionic fluorinated polymeric surfactant comprising: divalent units independently represented by formula (I): in a range from 30% to 65% by weight, based on the total weight of the nonionic fluorinated polymeric surfactant; and divalent units independently represented by formula (II): in a range from 70% to 35% by weight, based on the total weight of the nonionic fluorinated polymeric surfactant. Rf is a perfluoroalkyl group having from 3 to 4 carbon atoms; R and R2 are each independently hydrogen or alkyl of 1 to 4 carbon atoms; R1 is alkyl of 16 to 24 carbon atoms; and n is an integer from 2 to 11. Foams comprising the nonionic fluorinated polymeric surfactant and a liquid hydrocarbon and methods of making and using the foams are also disclosed.

Abstract: Among other things, methods of treating a subterranean formation with gelled hydrocarbon fluids are provided. In certain embodiments, these methods comprise the steps of providing a gelled liquid hydrocarbon treatment fluid comprising a liquid hydrocarbon and a gelling agent that comprises a polyvalent metal salt of an organophosphonic acid ester or a polyvalent metal salt of an organophosphinic acid, and treating the subterranean formation with the gelled liquid hydrocarbon treatment fluid. The gelled liquid hydrocarbon treatment fluids of the present invention are suitable for use in subterranean treatment operations, such as subterranean stimulation and sand control treatments like fracturing and gravel packing, that may be carried out in subterranean formations for the production of hydrocarbons.

Abstract: A process is disclosed for treating an underground formation, which process comprises: (a) introducing into the underground formation a micellar dispersion comprising water, one or more organic acid precursors, one or more surfactants and, optionally, one or more salts, co-surfactants and/or organic liquids that are not organic acid precursors; and (b) allowing (i) the micellar dispersion to solubilize hydrocarbons, emulsions or water blocks present in the underground formation, and (ii) at least a portion of the organic acid precursor to hydrolyze in-situ to produce sufficient organic acid to substantively dissolve acid soluble material present in or adjacent to filter cakes or other damage in the underground formation.

Abstract: A method of treating a hydrocarbon reservoir that is penetrated by a well is disclosed, the method comprising injecting into the well a water transfer system comprising liquefied petroleum gas (LPG) and an alcohol that is at least partially water and liquefied petroleum gas soluble. Further, a method of treating a hydrocarbon reservoir is disclosed, the method comprising introducing into the hydrocarbon reservoir a combination of LPG and a solvent system that is at least partially liquefied petroleum gas and water soluble.

Abstract: A substantially liquid gellant formed as one or more reaction products of a metal carboxylate or metal carboxylate amine salt, one or more organic acids, an ester which drives the reaction so that the reaction products are asymmetrical in structure, and a rheology modifier which preferentially interacts between the reaction products for prevent solidifying of the gellant reaction products until such time as the gellant is mixed with the fracturing fluid containing an activator after which the reaction products preferentially interact with the activator to gel the fracturing fluid. The resulting gellant is capable of gelling a hydrocarbon base fluid in less than about 30 seconds.

Abstract: A packer or annular fluid includes a hydrocarbon fluid; and a gelling agent; wherein the packer fluid is a yield power law fluid. A method for preparing a packer fluid includes preparing a mixture of a hydrocarbon fluid, and a gelling agent; heating the mixture to a selected temperature; and shearing the mixture. A method for emplacing a packer fluid into an annulus includes preparing the packer fluid that includes a hydrocarbon fluid and a gelling agent, wherein the packer fluid is a yield power law fluid; and pumping the packer fluid into the annulus.

Abstract: The present invention includes composition having a nonionic, fluorinated polymeric surfactant, water and solvent. Embodiments of compositions according to the present invention are useful, for example, for recovering hydrocarbons from subterranean clastic formations.