Abstract: The present invention pertains to the field of oilfield stimulation technologies for oil and gas field development, in particular to an instant soluble temperature and salt resistant polyacrylamide and the preparation method and application thereof, and the polyacrylamide is modified by adding rigid temperature and salt resistant monomer containing benzene ring and cationic fluorinated hydrophobic monomer on the basis of acrylamide monomer and sodium acrylate monomer, and then polymerized to obtain instant soluble temperature and salt resistant polyacrylamide. The temperature and salt resistant monomer containing benzene ring can improve the thermal stability and temperature and salt resistance of polyacrylamide, while the long-chain cationic fluorinated hydrophobic monomer can enhance the hydrophobicity of polymer. The comprehensive properties of polymer is improved by appropriate intermolecular association.

Abstract: A method to manufacture stable water-in-oil polymer emulsion with low viscosity by using special stabilizing surfactant package is disclosed.

Abstract: A method of recovering oil from a hydrocarbon-bearing subterranean geologic formation includes producing a first hydrocarbon composition and injecting a first injection fluid including a first viscoelastic polymer and a first brine solution. The first viscoelastic polymer has a shear viscosity from 500 to 700 cP at a shear rate of 0.5 to 2 s?1. A second hydrocarbon composition is produced and a second injection fluid including a viscous polymer and a second brine solution is injected. The viscous polymer has a shear viscosity greater than the first viscoelastic polymer. Further, a third hydrocarbon composition is produced and a third injection fluid including a second viscoelastic polymer and a third brine solution is injected. The second viscoelastic polymer has a shear viscosity less than the viscous polymer. The method further includes producing a fourth hydrocarbon composition.

Abstract: In a fracturing control apparatus, a first chemical agent storage tank is connected with a first delivery pump, and a material outlet of the first delivery pump communicates with a first position of a first fracturing fluid conveying pipeline. An outlet of the first fracturing fluid conveying pipeline communicates with an inlet of a fracturing pump, an outlet of the fracturing pump communicates with an inlet of a second fracturing fluid conveying pipeline, and a first flow detector is arranged at a second position of the second fracturing fluid conveying pipeline. The first delivery pump is connected with a first output interface of a controller, and the first flow detector is connected with a first input interface of the controller. The fracturing control apparatus and the control method of the fracturing control apparatus are used for adding chemical agents into fracturing fluids.

Abstract: This disclosure relates to thermal stimuli-responsive surfactant mixtures useful for reducing water/oil interfacial tension at high temperatures and increasing water/oil interfacial tension at low temperatures. The disclosure also relates to methods of using the surfactant mixtures for enhanced oil recovery applications.

Abstract: The effervescent tablet for enhanced oil recovery is made of multi-walled carbon nanotubes (MWCNTs), sodium dodecyl sulfate (SDS), sodium phosphate monobasic (NaH2PO4), and sodium carbonate (Na2CO3). To perform enhanced oil recovery, a suspension is first prepared by adding the effervescent tablet to water. This preparation may be performed at room temperature. Steam is then injected into the oil well, followed by flooding the oil well with the suspension. One-third of the pore volume of an oil reservoir of the oil well may be injected with the steam, and two-thirds of the pore volume of the oil reservoir may be flooded with the suspension.

Abstract: A method of enhanced oil recovery that includes injecting a composition including an hyperbranched polyglycerol into an injection well in a subterranean oil-bearing reservoir, the hyperbranched polyglycerol being a primary alcohol that is a reaction product of a C2 to C25 carbon alcohol and a plurality of glycidols; and displacing oil in the subterranean oil-bearing reservoir using the composition.

Abstract: Carbonates, such as chalk and limestone, are rather soft minerals and may lose at least some mechanical integrity after undergoing stimulation. For instance, carbonate minerals may experience proppant embedment or asperity weakening after fracturing or matrix acidizing. Methods for hardening a carbonate mineral may comprise: introducing an aqueous carrier fluid comprising an ammonium phosphate salt into a subterranean formation comprising a carbonate mineral, and interacting the carbonate mineral with the ammonium phosphate salt to convert at least a portion of the carbonate mineral into a hydroxyapatite mineral. The subterranean formation may exhibit an increased hardness after forming the hydroxyapatite mineral. The ammonium phosphate salt may be diammonium hydrogen phosphate in some examples.

Abstract: A method for mitigating gas override in an hydrocarbon reservoir by increasing sweep efficiency and consequently improving incremental oil recovery is provided with at least one injection well, at least one production well, and an hydrocarbon reservoir. The injection well and the production well are in fluid communication with the hydrocarbon reservoir. An injection blend produced by mixing a displacement fluid with an organic solvent is transferred into the hydrocarbon reservoir through the injection well. Preferably, the displacement fluid is supercritical carbon dioxide and the organic solvent is triethyl citrate. The higher density and the viscosity of the injection blend are vital in reducing gravity override and improving sweep efficiency. A resulting injection blend is extracted from the production well and the organic solvent is separated. Since the organic solvent can be reused, the method of mitigating gas override can be financially and operationally beneficial.

Abstract: Provided are methods of increasing the production of a hydrocarbon from a subterranean formation by waterflooding with injection solutions containing dihydrogen phosphate ions.

Abstract: Liquid polymer and inverse emulsion compositions comprising: one or more hydrophobic liquids having a boiling point at least about 100° C.; one or more acrylamide-(co)polymers; one or more emulsifier surfactants; one or more inverting surfactants; and one or more poly(alkyl)acrylate compounds. When the composition is inverted in an aqueous solution, it provides an inverted solution having a filter ratio using a 1.2 micron filter (FR1.2) of about 1.5 or less.

Abstract: The subject matter of this specification can be embodied in, among other things, a method for treating a geologic formation that includes providing a hydraulic fracture model, providing a first value representative of a volume of kerogen breaker in a fracturing fluid, determining a discrete fracture network (DFN) based on the hydraulic fracture model and the first value, determining a geomechanical model based on the DFN and a reservoir model based on the DFN, determining a hydrocarbon production volume based on the geomechanical model and the reservoir model, adjusting the first value based on the hydrocarbon production volume, and adjusting a volume of kerogen breaker in the fracturing fluid to a hydrocarbon reservoir based on the adjusted first value.

Abstract: Surfactants for use in formulations and processes suitable for hydrocarbon recovery. These formulations, include formulations suitable for fracking, enhancing oil and or gas recovery, and the recovery and/or production of bio-based oils.

Abstract: The systems and method described in this specification relate to at least partially restoring porosity and brine permeability of carbonate core samples. The systems and methods include extracting a carbonate core sample from a subterranean formation. The extracted carbonate core sample is inserted into a core flooding test machine. A first porosity and a first brine permeability of the extracted carbonate core sample is measured. A fluid is pumped through the extracted carbonate core sample to flood the carbonate core sample. The fluid includes at least one of a high-molecular weight polymer solution and a gel particle solution. The systems and methods include at least partially restoring the porosity and the brine permeability of the carbonate core sample by pumping an oxidizing solution through the flooded carbonate core sample and heating the carbonate core sample to a temperature of at least 60° C. after pumping the oxidizing solution through the carbonate core sample.

Abstract: Disclosed herein are methods for treating hydrocarbon-bearing formations previously subjected to hydraulic fracturing, in which at least some of the methods include pumping into a wellbore a treatment composition comprising LPG combined with one or more surfactants each of which is fully or partially dissolved into the LPG, causing the treatment composition to make contact with water residing in the formation such that at least a portion of the one or more surfactants dissolves into the water, and recovering a composition that includes residual hydrocarbons and at least some of the LPG and water that resided in the formation and at least some of the one or more surfactants that were pumped into the wellbore.

Abstract: Novel completion fluid compositions for fluid loss control during completion and workover operations conducted on a wellbore penetrating a subterranean formation are disclosed. In particular, the composition is a weighted brine fluid having a polymetaphosphate composition, a biopolymer suspension agent, and a fluid loss control additive. These novel compositions provide a means to temporarily seal a wellbore communicating with a subterranean formation to enable completion or workover operations to be performed, after which the composition can be removed by contact with an acidic composition.

Abstract: The disclosure is directed to methods and compositions delaying the gelation of polymers in water flooding by sequentially or co-injecting a carboxylate-containing polymer solution, a gel-delaying polymer, and gelation agent into a hydrocarbon reservoir. Delays of weeks are observed.

Abstract: Embodiments of the disclosure include compositions and methods that stabilize a injection fluid when exposed to reservoir conditions, reducing formation damage and increasing the amount of hydrocarbon recovered. Specifically, the formulation is a single-phase liquid surfactant package which comprises a surfactant and optionally one or more secondary surfactants. Also provided are methods of using the stabilized injection fluids in stimulation operations.

Abstract: A surfactant composition is provided. The composition includes chemical structure represented by Formula (1): where R1 represents a hydrocarbon group, a substituted hydrocarbon group, an alkyl ester group, or an alkyl amine having from 4 to 28 carbon atoms, and R2 and R3 represent hydrocarbon groups having from 1 to 5 carbon atoms. Also provided is a composition including a brine comprising a total salinity of at least 20,000 mg/L and the chemical structure shown in Formula (1). Methods of making a composition including the chemical structure represented by Formula (1) are also provided.

Abstract: Embodiments of the disclosure include compositions and methods that stabilize a injection fluid when exposed to reservoir conditions, reducing formation damage and increasing the amount of hydrocarbon recovered. Specifically, the formulation is a single-phase liquid surfactant package which comprises a non-ionic surfactant and optionally one or more secondary surfactants.

Abstract: A downhole system includes a packer sealing an annular space around a downhole tubing and an insulating packer fluid positioned within the annular space and adjacent to the packer. The insulating packer fluid includes a sodium bicarbonate activator and an acidic nanosilica dispersion having silica nanoparticles and a stabilizer, wherein the pH of the acidic nanosilica dispersion ranges from 2 to 5, and the silica nanoparticles form at least 20 percent by weight of the acidic nanosilica dispersion.

Abstract: This disclosure describes the composition and methods of use for a novel delayed polymer gelation system. This polymer gelation system includes a polymer of acrylamide, AMPS and 100-2,000 ppm polyethylene glycol diacrylate in inverse emulsion form, and a polyethyleneimine (PEI) with Mw of 5,000-100,000 Dalton as the crosslinking agent.

Abstract: Described herein are compositions and methods that stabilize an injection fluid when exposed to reservoir conditions, reducing formation damage and increasing the amount of hydrocarbon recovered. Specifically, the formulation is a single-phase liquid surfactant package which comprises an anionic surfactant including a hydrophobic tail comprising from 6 to 60 carbon atoms and optionally one or more secondary surfactants.

Abstract: A system includes a casing, a tubing within the casing, a packer, and a colloidal silica gel. The casing inner surface and the tubing outer surface define an annular space, and the packer is within the annular space. The colloidal silica gel which seals a gap. The gap can be a gap between the inner surface of the casing and a surface of the packer, a gap between the outer surface of the tubing and a surface of the packer, and/or a gap extending through the packer. A well can include such a system. A method of sealing a leak in or near a packer present in an annular space between a production casing inner surface and a tubing outer surface includes disposing a composition within the annular space, the composition comprising colloidal silica, water, and an activator.

Abstract: The present disclosure provides a bis-quaternary ammonium salt of Formula I wherein A is selected from O, NH, S, C(O), C(NH) or C(S); R1 and R2 are independently selected from C1-3 alkyl or H; R3 is C1-16 alkyl, C13-20 aralkyl or C2-16 allyl; X? is selected from chloro, bromo, iodo, hydroxide, nitrate or sulphate; and n and m are independently 1 to 6. Furthermore, a corrosion inhibition formulation comprising said bis-quaternary ammonium salt is revealed. Also, convenient processes for the preparation of the salt of Formula I and the formulation are provided.

Abstract: The subject invention provides multi-functional biochemical compositions, as well as their use in enhancing oil recovery from an oil-bearing subterranean formation. Advantageously, the compositions and methods of the subject invention are operationally-friendly, cost-effective, and environmentally-friendly. More specifically, in preferred embodiments, the subject invention provides a multi-functional composition for enhanced oil recovery (EOR) comprising one or more surfactants, one or more chelating agents, and one or more solvents.

Abstract: Mobility control polymers can be used to increase recovery of crude oil from a subterranean hydrocarbon-containing formation. A flooding fluid comprising the polymer are injected into a well that is in contact with the subterranean hydrocarbon-containing formation. The polymers are derived from reacting a crosslinking agent with a polymer and the crosslinking agent comprises a polyvalent metal ion having a weight/weight ratio of polymer to crosslinking agent of at least 60:1. These flooding fluids have improved injectivity into the well; the improved injectivity can be measured in terms of the flooding fluid's filter ratio, flow rate, and viscosity.

Abstract: Microemulsions comprising an alkyl propoxylated sulfate surfactant and related methods, including methods of use in the treatment of subterranean formations, such as oil and condensate wells, are provided. In some embodiments, the microemulsions and/or methods of use achieve ultra-low interfacial tensions (i.e. less than or equal to 0.01 mN/m) between a wide variety of crude oils and well treatment fluids at various reservoir conditions. In some embodiments, the microemulsion comprises water, an anionic alkyl propoxylated sulfate surfactant, a solvent (e.g., a terpene solvent), and a co-solvent. In some embodiments, the microemulsion further comprises a second and/or third surfactant (e.g., a nonionic and/or an anionic surfactant).

Abstract: Polymeric systems useful for maintaining particle dispersions for extended periods of time.

Abstract: Methods for treating a subterranean formation. An example method includes introducing a treatment fluid into a wellbore penetrating the subterranean formation. The treatment fluid includes an aqueous base fluid, a cationic or amphoteric friction reducer, and a substituted alkanolamine scale inhibitor. The method further includes contacting scale deposits on a surface in fluid communication with the wellbore and/or subterranean formation with the treatment fluid.

Abstract: The present invention discloses an in-situ emulsification and viscosity increase system with a high phase change point. The system consists of the following components in percentage by weight: 0.2˜0.5% of water-soluble surfactant, 0.2˜1.5% of oil-soluble surfactant, 0.02˜0.5% of lipophilic colloidal particles, 0.02˜0.2% of carrying agent and the balance of mineralized water.

Abstract: A method comprises: deriving fluid properties that provide for suspension of particulate diverting agents using a 3-dimensional flow model and based on a downhole temperature and at least one size characteristic of the particulate diverting agents; identifying a treatment fluid composition that comprises a nanoparticulate suspending agent and achieves the fluid properties using a relationship between the treatment fluid composition and the fluid properties; and preparing a treatment fluid or a treatment fluid additive based on the treatment fluid composition.

Abstract: Compositions and methods for treating a subterranean formation. The compositions can include positively and negatively charged divalent ions and a total dissolved solids concentration between 2000 and 3000 ppm. In some implementations, the composition includes calcium and magnesium ions. In some implementations, the composition includes sodium, chloride, and bicarbonate ions. In some implementations, the composition includes iodide, phosphate, or borate ions, or any combination thereof. Methods for treating the subterranean formation can include flowing a first aqueous solution that includes sodium ions into the subterranean formation and flowing a second aqueous solution that has a lower salinity than the first aqueous solution into the subterranean formation, where the second aqueous solution includes positively charged divalent ions, negatively charged divalent ions, and a total dissolved solids concentration between 2000 and 30000 ppm.

Abstract: A method for manipulating hydraulic fracture geometry. In one embodiment, the method comprises injecting a fracturing fluid into a well to generate one or more hydraulic fractures in a subsurface rock formation and then substantially draining any fluids from the one or more hydraulic fractures. The method may further comprise injecting a hydrophilic polymer and one or more crosslinking agents into the well to subsequently form low-density hydrogels which may then screen out only each tip of the one or more hydraulic fractures. A working fluid may then be injected into the well to increase fracture width of the one or more hydraulic fractures without substantially increasing fracture length. In an alternative embodiment, the hydrophilic polymer may be fully crosslinked by the one or more crosslinking agents and injected as pre-formed particle gels (PPGs) which may also screen out only each tip of the one or more hydraulic fractures.

Abstract: A method of formulating an oil-based wellbore fluid, the method comprising adding at least a plurality of conductive carbon black agglomerates or pellets having an average size of at least 500 ?m to an oleaginous base fluid, and applying energy to the oil-based wellbore fluid to disperse the plurality of conductive carbon black agglomerates or pellets into the oleaginous base fluid as finer particles than the agglomerates or pellets.

Abstract: The present invention relates to the use of a block polymer as fluid loss control agent in a fluid injected under pressure into an oil-bearing rock, where: the fluid comprises solid particles and/or is brought into contact with solid particles within the oil-bearing rock subsequent to its injection, the polymer comprises: a first block which is adsorbed on at least a portion of the particles; and a second block with a composition distinct from that of the first and with a weight-average molecular weight of greater than 10 000 g/mol, for example of greater than 100 000 g/mol, and which is soluble in the fluid.

Abstract: The invention is directed to polymers that self-crosslink at acidic pH or can be crosslinked by phenolic agents in brine. Such polymers have lower viscosity and can be pumped deep into reservoirs, where they will cross link in situ, thus increasing their viscosity and/or form a gel and blocking thief zones. Methods of making and using such polymers are also provided.

Abstract: Disclosed here compositions and methods suitable for injection of a nanosurfactant composition into a hydrocarbon-bearing formation for enhanced recovery operations. The nanosurfactant composition includes nanoassemblies that contain a petroleum sulfonate surfactant, mineral oil, a zwitterionic co-surfactant, and a cationic co-surfactant.

Abstract: Embodiments of the disclosure provide compositions and methods suitable for injection of a nanosurfactant-based foam composition into a hydrocarbon-bearing formation for enhanced recovery operations. The nanosurfactant-based foam composition includes a gaseous component and nanoassemblies. The nanoassemblies contain a petroleum sulfonate surfactant, mineral oil, and a zwitterionic co-surfactant.

Abstract: Embodiments of the disclosure provide compositions and methods suitable for injection of a nanosurfactant-based foam composition into a hydrocarbon-bearing formation for hydraulic fracturing operations. The nanosurfactant-based foam composition includes a gaseous component and nanoassemblies that contain a petroleum sulfonate surfactant, mineral oil, and a zwitterionic co-surfactant.

Abstract: A composition for use in a wellbore activity, the composition comprising a stabilized divalent iodide brine, the stabilized divalent iodide brine comprises a divalent salt system, where the divalent salt system comprises a divalent iodide, an primary iodide stabilizer, the primary iodide stabilizer operable to remove free iodine, prevent the formation of free iodine, and suppress TCT, and an aqueous fluid, where the stabilized divalent iodide brine has a density greater than 11 lb/gal, where the stabilized divalent iodide brines has a TCT of less than or equal to 70 deg F.

Abstract: Presented herein are methods and systems for mitigating condensate banking for example, by altering the wettability of a rock formation in the vicinity of a wellbore for a gas condensate reservoir.

Abstract: Disclosed here compositions and methods suitable for injection of a nanosurfactant-containing fluid into a hydrocarbon-bearing formation for enhanced recovery operations. Embodiments of the composition contain a petroleum sulfonate surfactant, mineral oil, and a zwitterionic co-surfactant.

Abstract: Disclosed are water treatment apparatus and processes for the generation of injection water from seawater and produced water. The first water treatment apparatus includes a reverse osmosis (RO) unit that treats the seawater, a pretreatment unit that pretreats the produced water, and a carrier gas extraction (CGE) unit or dynamic vapor recompression (DyVaR) that treats the pretreated produced water and generates fresh water. The fresh water and the RO permeate are mixed with a portion of the seawater to generate the injection water. A second water treatment apparatus includes a reverse osmosis (RO) unit and a nanofiltration (NF) that treats the seawater in parallel, a pretreatment unit that pretreats the produced water, and a CGE unit or DyVaR unit that treats the pretreated produced water and generates fresh water. The fresh water and the RO permeate are mixed with the NF reject to generate injection water.

Abstract: A method for producing hydrocarbons within a reservoir includes (a) injecting an aqueous solution into the reservoir. The aqueous solution includes water and a thermally activated chemical species. The thermally activated chemical species is urea, a urea derivative, or a carbamate. The thermally activated chemical agent is thermally activated at or above a threshold temperature less than 200° C. In addition, the method includes (b) thermally activating the thermally activated chemical species in the aqueous solution during or after (a) at a temperature equal to or greater than the threshold temperature to produce carbon-dioxide and at least one of ammonia, amine, and alkanolamine within the reservoir. Further, the method includes (c) increasing the water wettability of the subterranean formation in response to the thermally activation in (b). Still further, the method includes (d) waterflooding the reservoir with water after (a), (b) and (c).

Abstract: Provided herein are compounds, compositions, and methods having application in the field of enhanced oil recovery (EOR). In particular, provided herein are co-solvents, as well as aqueous compositions comprising these co-solvents, that can be used for the recovery of a large range of crude oil compositions from reservoirs.

Abstract: Viscous aqueous injections fluids including polymers having hydrophilic moieties and hydrophobic groups and at least one of crude oil emulsions and amphiphilic diblock copolymers are provided herein. Methods of making the aqueous injection fluids, and methods of using the aqueous injection fluids for oil recovery are also provided.

Abstract: Provided herein is a method of establishing a plug in a hydrocarbon reservoir, the method comprising introducing into the reservoir a formulation comprising solid particles and a viscosifier and then reducing the viscosity of said viscosifier, thereby causing said solid particles to form a plug within said hydrocarbon reservoir. Also provided is a method of establishing a plug in a hydrocarbon reservoir, the method comprising introducing into the reservoir a formulation comprising: (a) microorganisms or cell-free enzymes; (b) solid particles; and (c) a viscosifier which is a substrate for the microorganisms or cell-free enzymes of (a). Also provided is a formulation comprising: (a) microorganisms or cell-free enzymes; (b) solid particles made from wood or a wood derived product; and (c) a viscosifier which is a substrate for the microorganisms or cell-free enzymes of (a).

Abstract: The subject matter of this specification can be embodied in, among other things, a method for treating a geologic formation that includes providing a hydraulic fracture model, providing a first value representative of a volume of kerogen breaker in a fracturing fluid, determining a discrete fracture network (DFN) based on the hydraulic fracture model and the first value, determining a geomechanical model based on the DFN and a reservoir model based on the DFN, determining a hydrocarbon production volume based on the geomechanical model and the reservoir model, adjusting the first value based on the hydrocarbon production volume, and adjusting a volume of kerogen breaker in the fracturing fluid to a hydrocarbon reservoir based on the adjusted first value.

Abstract: A method of acidizing a subterranean geological formation by injecting an emulsified acid into a wellbore, wherein the emulsified acid includes at least an aqueous phase comprising a hydrochloric acid solution, an oil phase comprising waste oil, and an emulsifier, and wherein the waste oil contains 45-75% by weight of aromatic compounds and preferably contains less than 0.5% by weight of non-hydrocarbon compounds. Various embodiments, and combinations of embodiments, of the emulsified acid and the method of acidizing are provided.