Classifications

• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
  • C09K8/02—Well-drilling compositions
  • C09K8/32—Non-aqueous well-drilling compositions, e.g. oil-based
  • C09K8/36—Water-in-oil emulsions
• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
  • C09K8/58—Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids
  • C09K8/588—Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids characterised by the use of specific polymers
• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
  • C09K8/60—Compositions for stimulating production by acting on the underground formation
  • C09K8/62—Compositions for forming crevices or fractures
  • C09K8/64—Oil-based compositions
• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
  • C09K8/60—Compositions for stimulating production by acting on the underground formation
  • C09K8/62—Compositions for forming crevices or fractures
  • C09K8/66—Compositions based on water or polar solvents
  • C09K8/68—Compositions based on water or polar solvents containing organic compounds
• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
  • C09K8/60—Compositions for stimulating production by acting on the underground formation
  • C09K8/82—Oil-based compositions
• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
  • C09K8/60—Compositions for stimulating production by acting on the underground formation
  • C09K8/92—Compositions for stimulating production by acting on the underground formation characterised by their form or by the form of their components, e.g. encapsulated material
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
  • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
  • E21B43/25—Methods for stimulating production
  • E21B43/26—Methods for stimulating production by forming crevices or fractures
• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K2208/00—Aspects relating to compositions of drilling or well treatment fluids
  • C09K2208/28—Friction or drag reducing additives

Definitions

• compositions for treating subterranean zones include aqueous subterranean treatment fluids that contain water soluble polymers in a water-in-oil emulsion in high brine containing solutions and associated methods.
• Aqueous treatment fluids may be used in a variety of subterranean treatments. Such treatments include, but are not limited to, drilling operations, stimulation operations, and completion operations.
• treatment refers to any subterranean operation that uses a fluid in conjunction with a desired function and/or for a desired purpose.
• treatment does not imply any particular action by the fluid.
• Viscous gelled fracturing fluids are commonly utilized in the hydraulic fracturing of subterranean zones penetrated by well bores to increase the production of hydrocarbons from the subterranean zones. That is, a viscous fracturing fluid is pumped through the well bore into a subterranean zone to be stimulated at a rate and pressure such that fractures are formed and extended into the subterranean zone.
• the fracturing fluid also carries particulate proppant material, e.g., graded sand, into the formed fractures.
• the proppant material is suspended in the viscous fracturing fluid so that the proppant material is deposited in the fractures when the viscous fracturing fluid is broken and recovered.
• the proppant material functions to prevent the fractures from closing whereby conductive channels are formed through which produced fluids can flow to the well bore.
• a stimulation operation utilizing an aqueous treatment fluid is hydraulic fracturing.
• a fracturing treatment involves pumping a proppant-free, aqueous treatment fluid (known as a pad fluid) into a subterranean formation faster than the fluid can escape into the formation so that the pressure in the formation rises and the formation breaks, creating or enhancing one or more fractures.
• Enhancing a fracture includes enlarging a pre-existing fracture in the formation. Once the fracture is formed or enhanced, proppant particulates are generally placed into the fracture to form a proppant pack that may prevent the fracture from closing when the hydraulic pressure is released, forming conductive channels through which fluids may flow to the well bore.
• a considerable amount of energy may be lost due to friction between the aqueous treatment fluid in turbulent flow and the formation and/or tubular goods (e.g., pipes, coiled tubing, etc.) disposed within the well bore.
• additional horsepower may be necessary to achieve the desired treatment.
• friction reducing polymers have heretofore been included in aqueous treatment fluids. The friction reducing polymer should reduce the frictional losses due to friction between the aqueous treatment fluid in turbulent flow and the tubular goods and/or the formation.
• friction reducing polymers show a reduced performance in the presence of low molecular weight additives, such as acids, bases, and salts.
• Ionically-charged polymers are particularly susceptible.
• polymers containing acrylate-type monomers, either added as a copolymer or hydrolyzed from polyacrylamide have a reduced compatibility with high calcium brines.
• the additives screen the charges on the polymer backbone which decreases the hydrodynamic radius of the polymer. With the decrease in effective polymer length, the friction reduction also decreases.
• Hydraulic fracturing has been a boon to the oil and gas industry. Many oil and gas wells have been made more productive due to the procedure. However, the hydraulic fracturing business is now facing increasing scrutiny and government regulation. In addition, large volumes of water are required for hydraulic fracturing operations. Fresh water may be a limiting factor in some areas.
• a treatment solution that can use a variety of water sources, such as produced water from the formation or flowback water after a well treatment, could significantly enhance the field applicability.
• the relatively high polymer usage in subterranean treatment methods can result in significant formation damage. Further, when the treatment fluid is recycled above ground, the high levels of high molecular weight polymers in the fluid can lead to flocculation in above ground fluid recycle operations such as terminal upsets.
• the present disclosure provides a friction reducing treatment solution that includes water, from 100, in many cases from 10,000 to 300,000, in some cases up to about 500,000 ppm of total dissolved solids, and from 0.5 to 3 gallons per thousand gallons of a water-in-oil emulsion containing a water soluble polymer.
• the total dissolved solids include at least 10 weight percent of a multivalent cation.
• the water-in-oil emulsion includes an oil phase (O) and an aqueous phase (A) at an O/A ratio of from about 1:8 to about 10:1, where the oil phase is a continuous phase containing an inert hydrophobic liquid and the aqueous phase is present as dispersed distinct particles in the oil phase and contains water, the water soluble polymer, and surfactants and an inverting surfactant.
• the water soluble polymer is made up of 20 to 80 weight percent of a non-ionic monomer, 0.5 to 35 weight percent of a carboxylic acid containing monomer, and 5 to 70 weight percent of a cationic monomer.
• the water soluble polymer comprises from 5 to 40 weight percent of the water-in-oil emulsion.
• the present disclosure also provides a method of treating at least a portion of a subterranean formation that includes introducing the friction reducing treatment solution into the portion of the subterranean formation.
• any numerical range recited herein is intended to include all sub-ranges subsumed therein.
• a range of “1 to 10” is intended to include all sub-ranges between and including the recited minimum value of 1 and the recited maximum value of 10; that is, having a minimum value equal to or greater than 1 and a maximum value of equal to or less than 10. Because the disclosed numerical ranges are continuous, they include every value between the minimum and maximum values. Unless expressly indicated otherwise, the various numerical ranges specified in this application are approximations.
• (meth)acrylic and (meth)acrylate are meant to include both acrylic and methacrylic acid derivatives, such as the corresponding alkyl esters often referred to as acrylates and (meth)acrylates, which the term “(meth)acrylate” is meant to encompass.
• polymer is meant to encompass oligomer, and includes, without limitation, both homopolymers and copolymers.
• copolymer is not limited to polymers containing two types of monomeric units, but includes any combination of polymers, e.g., terpolymers, tetrapolymers, and the like.
• flowback water refers to fluids that flow back to the surface after treatment fluids are injected down hole.
• total dissolved solids refers to a measure of the combined content of all inorganic and organic substances contained in water including ionized solids in the water.
• the term “brine” refers to water containing dissolved salt and at least 10,000 ppm TDS. In an embodiment, the term “brine” refers to water containing dissolved salt and greater than 30,000 ppm TDS.
• the present disclosure provides a friction reducing treatment solution that includes water, from 100, in many cases from 10,000 to 300,000, in some cases up to about 500,000 ppm of total dissolved solids, and from 0.5 to 3 gallons per thousand gallons of a water-in-oil emulsion containing a water soluble polymer.
• the total dissolved solids include at least 10 weight percent of a multivalent cation.
• the water-in-oil emulsion includes an oil phase (O) and an aqueous phase (A) at an O/A ratio of from about 1:8 to about 10:1, where the oil phase is a continuous phase containing an inert hydrophobic liquid and the aqueous phase is present as dispersed distinct particles in the oil phase and contains water, the water soluble polymer, and surfactants and an inverting surfactant.
• the water soluble polymer is made up of 20 to 80 weight percent of a non-ionic monomer, 0.5 to 35 weight percent of a carboxylic acid containing monomer, and 5 to 70 weight percent of a cationic monomer.
• the water soluble polymer comprises from 5 to 40 weight percent of the water-in-oil emulsion.
• the present disclosure provides a method of treating a portion of a subterranean formation that includes introducing the friction reducing treatment solution into the portion of the subterranean formation.
• the aqueous friction reducing treatment solutions of the present disclosure generally include water, and a friction reducing copolymer.
• the water-in-oil emulsion includes an oil phase, an aqueous phase and surfactants.
• the oil phase (O) and the aqueous phase (A) can be present at an O/A ratio, based on the volume of each phase of from at least about 1:8, in some cases at least about 1:6 and in other cases at least about 1:4 and can be up to about 10:1, in some cases up to about 8:1 and in other cases up to about 6:1.
• the O/A ratio is too oil heavy, the polymer may be too concentrated in the aqueous phase.
• the O/A ratio is too water heavy, the emulsion may become unstable and prone to separate.
• the O/A ratio can be any ratio or range between any of the ratios recited above.
• the oil phase is present as a continuous phase and includes an inert hydrophobic liquid.
• the inert hydrophobic liquid can include, as non-limiting examples, paraffinic hydrocarbons, napthenic hydrocarbons, aromatic hydrocarbons, benzene, xylene, toluene, mineral oils, kerosenes, naphthas, petrolatums, branch-chain isoparaffinic solvents, branch-chain hydrocarbons, saturated, linear, and/or branched paraffin hydrocarbons and combinations thereof.
• Particular non-limiting examples include natural, modified or synthetic oils such as the branch-chain isoparaffinic solvent available as ISOPAR® M and EXXATE® available from ExxonMobil Corporation, Irving Tex., a narrow fraction of a branch-chain hydrocarbon available as KENSOL® 61 from Witco Chemical Company, New York, N.Y., mineral oil, available commercially as BLANDOL® from Witco, CALUMETTM LVP-100 available from Calumet Specialty Products, Burnham, Ill., DRAKEOL® from Penreco Partnership, Houston, Tex., MAGIESOL® from Magie Bros., Oil City, Pa. and vegetable oils such as canola oil, coconut oil, rapeseed oil and the like.
• branch-chain isoparaffinic solvent available as ISOPAR® M and EXXATE® available from ExxonMobil Corporation, Irving Tex.
• KENSOL® 61 from Witco Chemical Company, New York, N.Y.
• mineral oil available commercially as B
• the inert hydrophobic liquid is present in the water-in-oil emulsion in an amount sufficient to form a stable emulsion.
• the inert hydrophobic liquid can be present in the water-in-oil emulsions in an amount in the range of from about 15% to about 80% by weight.
• the inert hydrophobic liquid is present in the water-in-oil emulsion at a level of at least about 15, in some cases at least about 17.5, in other cases at least about 20, and in some instances at least about 22.5 weight percent based on the weight of the water-in-oil emulsion and can be present at up to about 40, in some cases up to about 35, in other cases up to about 32.5 and in some instances up to about 30 weight percent based on the weight of the water-in-oil emulsion.
• the total amount of inert hydrophobic liquid in the water-in-oil emulsion can be any value or can range between any of the values recited above.
• any suitable water-in-oil emulsifier can be used as the one or more surfactants used to make the water soluble polymer containing water-in-oil emulsion used in the present method.
• the surfactants include those having an HLB (hydrophilic-lipophilic balance) value between 2 and 10 in some cases between 3 and 9 and in other cases between 3 and 7.
• HLB is calculated using the art known method of calculating a value based on the chemical groups of the molecule.
• Non-limiting examples of suitable surfactants include:
• the surfactants can include ethoxylated nonionic surfactants, guerbet alcohol ethoxylate, and mixtures thereof.
• ethoxylated nonionic surfactants include, but are not limited to tall oil fatty acid diethanolamine, such as those available as AMADOL® 511, from Akzo Nobel Surface Chemistry, Chicago, Ill.; polyoxyethylene (5) sorbitan monoleate, available as TWEEN® 81, from Uniqema, New Castle, Del.; sorbinate monoleate, available as SPAN® 80 from Uniquena, and ALKAMULS® SMO, from Rhone Poulenc, Inc., Paris, France.
• tall oil fatty acid diethanolamine such as those available as AMADOL® 511, from Akzo Nobel Surface Chemistry, Chicago, Ill.
• polyoxyethylene (5) sorbitan monoleate available as TWEEN® 81, from Uniqema, New Castle, Del.
• sorbinate monoleate available as SPAN® 80 from Unique
• the surfactants can be present at a level of at least about 0.1, in some instances at least about 0.25, in other instances at least about 0.5, in some cases at least about 0.75 and in other cases at least about 1 weight percent of the water-in-oil emulsion.
• the amount of surfactants can be up to about 7, in some cases up to about 5, and in other cases up to about 2.5 weight percent of the water-in-oil emulsion.
• the amount of surfactants in the water-in-oil emulsion can be any value or can range between any of the values recited above.
• the aqueous phase is a dispersed phase of distinct particles in the oil phase and includes water and a water soluble polymer.
• the aqueous phase in total can be present in the present water-in-oil emulsion polymer composition at a level of at least about 60, in some instances at least about 65, in some cases at least about 67.5, and in other cases at least about 70 weight percent based on the weight of the water-in-oil emulsion and can be present at up to about 85, in some cases up to about 82.5, in other cases up to about 80 and in some instances up to about 77.5 weight percent based on the weight of the water-in-oil emulsion.
• the total amount of aqueous phase in the water-in-oil emulsion can be any value or can range between any of the values recited above.
• the water soluble polymer is present at a level of at least about 5, in some instances 10, in some cases at least about 15, and in other cases at least about 20 weight percent based on the weight of the water-in-oil emulsion and can be present at up to about 33, in some cases up to about 35, in other cases up to about 37 and in some instances up to about 40 weight percent based on the weight of the water-in-oil emulsion.
• the amount of water soluble polymer is too low, the use of the water-in-oil emulsion in the present method of treating a portion of a subterranean formation may be uneconomical.
• the performance of the water soluble polymer in the present method of treating a portion of a subterranean formation may be less than optimal.
• the amount of water soluble polymer in the aqueous phase of the water-in-oil emulsion can be any value or can range between any of the values recited above.
• the water soluble polymer in the water-in-oil emulsion is prepared by polymerizing a monomer solution that includes non-ionic monomers, cationic monomers, and carboxylic acid containing monomers included at a level that provides the desired amount of water soluble polymer.
• the amount of non-ionic monomer can be at least about 20, in some cases at least about 33, and in other cases at least about 35 weight percent based on the weight of the monomer mixture. When the amount of non-ionic monomer is too low, the molecular weight of the resulting water soluble polymer may be lower than desired. Also, the amount of non-ionic monomer in the monomer mixture can be up to about 80, in some case up to about 57.5, and in other cases up to about 55 weight percent based on the weight of the monomer mixture. When the amount of non-ionic monomer is too high, the water soluble polymer may not carry enough ionic charge to optimally function as a friction reducing polymer. The amount of non-ionic monomer in the monomer mixture can be any value or range between any of the values recited above.
• the monomer mixture typically includes (meth)acrylamide as a non-ionic monomer.
• the water soluble polymer can include other non-ionic monomers to provide desirable properties to the polymer.
• suitable other non-ionic monomers that can be included in the monomer mixture, and ultimately the resulting water soluble polymer include N,N-dimethyl(meth)acrylamide (DMF), N-vinyl acetamide, N-vinyl formamide, acrylonitrile (including hydrolyzed products of acrylonitrile residues), acrylonitrile-dimethyl amine reaction products, and and/or corresponding salts, non-limiting examples being sodium, potassium and/or ammonium and mixtures thereof.
• the monomer mixture includes a carboxylic acid containing monomer or its corresponding salts, non-limiting examples being sodium, potassium and ammonium.
• carboxylic acid containing monomers include, but are not limited to (meth)acrylic acid, maleic acid, itaconic acid, N-(meth)acrylamidopropyl, N,N-dimethyl,amino acetic acid, N-(meth)acryloyloxyethyl, N,N-dimethyl,amino acetic acid, N-(meth)acryloyloxyethyl, N,N-dimethyl,amino acetic acid, crotonic acid, (meth)acrylamidoglycolic acid, and 2-(meth)acrylamido-2-methylbutanoic acid.
• the amount of carboxylic acid containing monomer can be at least about 0.5, in some cases at least about 1, and in other cases at least about 2 weight percent based on the weight of the monomer mixture.
• the amount of carboxylic acid containing monomer in the monomer mixture can be up to about 35, in some case up to about 20, and in other cases up to about 15 weight percent based on the weight of the monomer mixture.
• the amount of carboxylic acid containing monomer is too high, the water soluble polymer may have undesirable flocculation properties when used in the present method.
• the amount of carboxylic acid containing monomer in the monomer mixture can be any value or range between any of the values recited above.
• the carboxylic acid containing monomers can also be referred to as anionic monomers.
• the monomer mixture and/or water soluble polymer does not include (meth)acrylic acid.
• the monomer mixture typically includes a cationic monomer or its corresponding salts, non-limiting examples being chloride and methylsulfate.
• cationic monomers include, but are not limited to (meth)acrylamidopropyltrimethyl ammonium halides, (meth)acryloyloxyethyltrimethyl ammonium halides, N,N-Dimethylaminoethyl(meth)acrylate, (meth)acryloyloxyethyltrimethyl ammonium methyl sulfate, and diallyl dimethyl ammonium halides.
• the cationic monomer can be a monomer that contains an amine group (“amine containing monomer”) that takes on a positive charge at pH levels less than 7, in some cases less than 6 and in other cases less than 5.
• amine containing monomers that can be used as cationic monomers in the present disclosure include diallylamine (DAA), methyldiallylamine (MDAA), dimethylaminoethylmethacrylate (DMAEM), and dimethylaminopropylmethacrylamide (DMAPMA).
• the amount of cationic monomer can be at least about 5, in some cases at least about 15, and in other cases at least about 20 weight percent based on the weight of the monomer mixture. When the amount of cationic monomer is too low, the water soluble polymer may not carry enough cationic charge to optimally function as a friction reducing polymer in high brine solutions. Also, the amount of cationic monomer in the monomer mixture can be up to about 70, in some case up to about 50, in other cases up to about 40, in some instances up to about 30, and in other instances up to about 25 weight percent based on the weight of the monomer mixture. When the amount of cationic monomer is too high, the water soluble polymer may have undesirable flocculation properties when used in the present method. The amount of cationic monomer in the monomer mixture can be any value or range between any of the values recited above.
• composition of the water soluble polymer will be the same or about the same as the composition of the monomer mixture.
• the water soluble polymers of the present disclosure do not decrease their hydrodynamic volume due to the presence of ions in the treatment solution as is the case with prior art water soluble polymers. Because the present water soluble polymers contain anionic groups from the anionic monomers and cationic groups from the cationic monomers, they tend to have a somewhat smaller hydrodynamic volume when no salt ions are present in the treatment fluid. When salt ions are present, they tend to associate with the anionic and cationic groups in the present water soluble polymers causing the hydrodynamic volume of the present water soluble polymers to become larger, which results in more viscosity build and more of a friction reducing effect.
• the viscosity build and friction reducing effect is increased when the molar ratio of cationic monomer to anionic monomer is at least 1.5:1, in some cases at least 1.75:1 and in other cases at least 2:1.
• the viscosity build and friction reducing effect is increased when the molar ratio of cationic monomer to anionic monomer is not more than 1:1.5, in some cases not more than 1:1.75 and in other cases not more than 1:2.
• the water-in-oil emulsion of the present disclosure can be made down into a 2 wt % aqueous solution of the inverted water-in-oil emulsion.
• the bulk viscosity of the solution can be measured at 25° C. using a Brookfield RV instrument equipped with an appropriate spindle at 10 rpm at 25° C. (Brookfield Engineering Laboratories, Inc., Middleboro, Mass.).
• the water soluble polymers in the dispersed aqueous phase particles of the present water-in-oil emulsion are able to provide a greater friction reducing effect by reducing the energy losses due to friction in brine containing aqueous treatment fluids of the present disclosure.
• the water soluble polymers of the present disclosure can reduce energy losses during introduction of the aqueous treatment fluid into a well bore due to friction between the aqueous treatment fluid in turbulent flow and the formation and/or tubular good(s) (e.g., a pipe, coiled tubing, etc.) disposed in the well bore.
• the water-in-oil emulsion containing the water soluble polymer of the present method is prepared using water-in-oil emulsion polymerization techniques. Suitable methods to effect such polymerizations are known in the art, non-limiting examples of such being disclosed in U.S. Pat. Nos. 3,284,393; 4,024,097; 4,059,552; 4,419,344; 4,713,431; 4,772,659; 4,672,090; 5,292,800; and 6,825,301, the relevant disclosures of which are incorporated herein by reference.
• the water-in-oil polymerization is carried out by mixing the surfactants with the oil phase, which contains the inert hydrophobic liquid.
• the aqueous phase is then prepared combining a monomer mixture with water in the desired concentration.
• a chelant such as a sodium salt of EDTA can optionally be added to the aqueous phase and the pH of the aqueous phase can be adjusted to 3.0 to 10.0, depending on the particular monomer(s) in the monomer mixture.
• the aqueous phase is then added to the mixture of oil phase and surfactants.
• the surfactants enable the aqueous phase, which contains the monomer mixture, to be emulsified into and form discrete particles in the oil phase.
• Polymerization is then carried out in the presence of a free radical generating initiator.
• Any suitable initiator can be used.
• suitable initiators include diethyl 2,2′-azobisisobutyrate, dimethyl 2,2′-azobisisobutyrate, 2-methyl 2′-ethyl azobisisobutyrate, benzoyl peroxide, lauroyl peroxide, sodium persulfate, potassium persulfate, tert-butyl hydroperoxide, dimethane sulfonyl peroxide, ammonium persulfate, azobisisobutylronitrile, dimethyl 2,2′-azobis(isobutyrate) and combinations thereof.
• the amount of initiator can be from about 0.01 to 1% by weight of the monomer mixture, in some cases from 0.02% to 0.5% by weight of the monomer mixture.
• the polymerization technique may have an initiation temperature of about 25° C. and proceed approximately adiabatically. In other embodiments of the disclosure, the polymerization can be carried out isothermally at a temperature of about from 37° C. to about 50° C.
• the oil-in-water emulsion can include a salt.
• the salt can be present to add stability to the emulsion and/or reduced viscosity of the emulsion.
• suitable salts include, but are not limited to, ammonium chloride, potassium chloride, sodium chloride, ammonium sulfate, and mixtures thereof.
• the salt can be present in emulsions in an amount in the range of from about 0.5% to about 2.5% by weight of the emulsion.
• the oil-in-water emulsions can include an inhibitor.
• the inhibitor can be included to prevent premature polymerization of the monomers prior to initiation of the emulsion polymerization reaction.
• the water soluble polymer may have been synthesized using an emulsion polymerization technique wherein the inhibitor acted to prevent premature polymerization.
• suitable inhibitors include, but are not limited to, quinones.
• An example of a suitable inhibitor comprises a 4-methoxyphenol (MEHQ).
• MEHQ 4-methoxyphenol
• the inhibitor should be present in an amount sufficient to provide the desired prevention of premature polymerization.
• the inhibitor may be present in an amount in the range of from about 0.001% to about 0.1% by weight of the emulsion.
• the water soluble polymers of the disclosed subject matter typically have a molecular weight sufficient to provide a desired level of friction reduction.
• friction reducing polymers have a higher molecular weight in order to provide a desirable level of friction reduction.
• the weight average molecular weight of the friction reducing copolymers may be in the range of from about 2,000,000 to about 20,000,000, in some cases up to about 30,000,000, as determined using intrinsic viscosities.
• friction reducing copolymers having molecular weights outside the listed range may still provide some degree of friction reduction in an aqueous treatment fluid.
• intrinsic viscosity is determined using a Ubbelhhde Capillary Viscometer and solutions of the water soluble polymer in 1M NaCl solution, at 30° C., and pH 7 at 0.05 wt. %, 0.025 wt. % and 0.01 wt. % and extrapolating the measured values to zero concentration to determine the intrinsic viscosity.
• the molecular weight of the water soluble polymer is then determined using the Mark-Houwink equation as is known in the art.
• the reduced viscosity of the water soluble polymer at 0.05 wt. % concentration is used to measure molecular size.
• the water soluble polymer has a reduced viscosity, as determined in a Ubbelhhde Capillary Viscometer at 0.05% by weight concentration of the polymer in 1M NaCl solution, at 30° C., pH 7, of from about 10 to about 40 dl/g, in some cases from 15 to about 35 dl/g, and in other cases 15 to about 30 dl/g.
• Suitable water soluble polymers of the disclosure can be in an acid form or in a salt form.
• a variety of salts can be made by neutralizing the carboxylic acid containing monomer with a base, such as sodium hydroxide, potassium hydroxide, ammonium hydroxide or the like.
• a base such as sodium hydroxide, potassium hydroxide, ammonium hydroxide or the like.
• water soluble polymer is intended to include both the acid form of the friction reducing copolymer and its various salts.
• the water-in-oil emulsion is added to water by inverting the emulsion to form a friction reducing treatment solution.
• invert and/or “inverting” refer to exposing the water-in-oil emulsion to conditions that cause the aqueous phase to become the continuous phase. This inversion releases the water soluble polymer into the make up water.
• an inverting surfactant in order to aid the inversion, make down and dissolution of the water soluble polymer, can be included in the water-in-oil emulsion.
• the inverting surfactant can facilitate the inverting of the emulsion upon addition to make up water and/or the aqueous treatment fluids of the disclosed subject matter.
• the water-in-oil emulsion upon addition to the aqueous treatment fluid, the water-in-oil emulsion should invert, releasing the copolymer into the aqueous treatment fluid.
• Non-limiting examples of suitable inverting surfactants include, polyoxyethylene alkyl phenol; polyoxyethylene (10 mole) cetyl ether; polyoxyethylene alkyl-aryl ether; quaternary ammonium derivatives; potassium oleate; N-cetyl-N-ethyl morpholinium ethosulfate; sodium lauryl sulfate; condensation products of higher fatty alcohols with ethylene oxide, such as the reaction product of oleyl alcohol with 10 ethylene oxide units; condensation products of alkylphenols and ethylene oxide, such as the reaction products of isooctylphenol with 12 ethylene oxide units; condensation products of higher fatty acid amines with five, or more, ethylene oxide units; ethylene oxide condensation products of polyhydric alcohol partial higher fatty esters, and their inner anhydrides (e.g., mannitol anhydride, and sorbitol-anhydride).
• ethylene oxide condensation products of polyhydric alcohol partial higher fatty esters and their inner anhydr
• the inverting surfactants can include ethoxylated nonyl phenols, ethoxylated nonyl phenol formaldehyde resins, ethoxylated alcohols, nonionic surfactants with an HLB of from 12 to 14, and mixtures thereof.
• a specific non-limiting example of a suitable inverting surfactant includes an ethoxylated C 12 -C 16 alcohol.
• the inverting surfactant can be a C 12 -C 14 alcohol having 5 to 10 units of ethoxylation.
• the inverting surfactant can be present in an amount sufficient to provide the desired inversion of the emulsion upon contact with the water in the aqueous treatment fluid.
• the inverting surfactant can be present in an amount in the range of from about 1%, in some cases about 1.1%, in other cases about 1.25% and can be up to about 5%, in some cases about 4%, in other cases about 3%, in some instances about 2% and in other instances about 1.75% by weight of the water-in-oil emulsion.
• the inverting surfactants are added to the water-in-oil emulsion after the polymerization is completed.
• a batch method can be used to make down the water-in-oil emulsion.
• the water soluble polymer containing water-in-oil emulsion and water are delivered to a common mixing tank. Once in the tank, the solution is beat or mixed for a specific length of time in order to impart energy thereto. After mixing, the resulting solution must age to allow enough time for the molecules to unwind. This period of time is significantly reduced in the present disclosure.
• continuous in-line mixers as well as in-line static mixers can be used to combine the water soluble polymer containing water-in-oil emulsion and water.
• suitable mixers utilized for mixing and feeding are disclosed in U.S. Pat. Nos. 4,522,502; 4,642,222; 4,747,691; and 5,470,150, which are incorporated herein by reference.
• suitable static mixers can be found in U.S. Pat. Nos. 4,051,065 and 3,067,987, which are incorporated herein by reference.
• any other additives are added to the solution to form a treatment solution, which is then introduced into the portion of the subterranean formation.
• the water soluble polymer can be included in any aqueous treatment fluid used in subterranean treatments to reduce friction.
• Such subterranean treatments include, but are not limited to, drilling operations, stimulation treatments (e.g., fracturing treatments, acidizing treatments, fracture acidizing treatments), and completion operations.
• stimulation treatments e.g., fracturing treatments, acidizing treatments, fracture acidizing treatments
• completion operations e.g., completion operations.
• the water used in the aqueous treatment fluids of the disclosed subject matter can be freshwater, brackish water, saltwater (e.g., water containing one or more salts dissolved therein), brine (e.g., produced from subterranean formations), seawater, pit water, pond water—or—the like, or combinations thereof. It is common for freshwater to include total dissolved solids at a level of less than 1000 ppm; brackish water to include total dissolved solids at a level of 1,000 ppm to less than 10,000 ppm; saltwater to include total dissolved solids at a level of 10,000 ppm to 30,000 ppm; and brine to include total dissolved solids at a level of greater than 30,000 ppm.
• the water used may be from any source, provided that it does not contain an excess of compounds that may adversely affect other components in the aqueous treatment fluid or the formation itself.
• the disclosed subject matter is effective in all aqueous treating fluid waters.
• the water soluble polymers of the present disclosure should be included in the aqueous treatment fluids of the present disclosure in an amount sufficient to provide the desired reduction of friction.
• a water soluble polymer of the present disclosure may be present in an amount that is at least about 0.0025%, in some cases at least about 0.003%, in other cases at least about 0.0035% and in some instances at least about 0.05% by weight of the aqueous treatment fluid and can be up to about 4%, in some cases up to about 3%, in other cases up to about 2%, in some instances up to about 1%, in other instances up to about 0.02%, in some situations up to less than about 0.1%, in other situations, up to about 0.09%, and in specific situations, up to about 0.08% by weight of the aqueous treatment fluid.
• the amount of the water soluble polymers included in the aqueous treatment fluids can be any value or range between any of the values recited above.
• the water soluble polymer can be present in aqueous treatment fluids in an amount in the range of from about 0.0025% to about 0.025%, in some cases in the range of from about 0.0025% to less than about 0.01%, in other cases in the range of from about 0.0025% to about 0.009%, and in some situations in the range of from about 0.0025% to about 0.008%, by weight of the aqueous treatment fluid.
• the amount of water soluble polymer in the aqueous treatment fluid can be at least about 5%, in some cases at least about 7.5%, in other cases at least about 10%, in some instances at least about 12.5%, in other instances at least about 15%, in some situations at least about 20%, and in other situations at least about 25% less than when water-in-oil emulsion containing a polymer of the same composition at a concentration of 30 weight percent or more are used in the in the aqueous treatment fluid.
• the water-in-oil emulsions according to the disclosure are used in the friction reducing treatment solution in an amount of at least about 0.1 gallons of water-in-oil emulsion per thousand gallons of aqueous treating fluid water (gpt), in some cases at least about 0.15 gpt, and in other cases at least about 0.2 gpt and can be up to about 3 gpt, in some cases up to about 2.5 gpt, in other cases up to about 2.0 gpt, in some instances up to about 1.5 gpt, and in other instances up to about 1.5 gpt.
• the amount of water-in-oil emulsion used in the friction reducing treatment solution can be any value or range between any of the values recited above.
• the aqueous treatment fluid contains 10,000 to 300,000 ppm of total dissolved solids.
• the total dissolved solids include at least 10 weight percent of a multivalent cation.
• the any multivalent cation can be included and can include one or more selected from iron (in its ferrous and ferric forms), calcium, magnesium, manganese, strontium, barium, and zinc.
• the aqueous treatment fluid can include total dissolved solids at a level of at least about 100 ppm, in some instances at least about 500 ppm, in other instances at least about 1,000 ppm, in some cases at least about 5,000 ppm and in other cases at least about 10,000 ppm and can be up to about 500,000 ppm, in certain cases up to about 400,000 ppm, in many cases up to about 300,000 ppm, in some cases up to about 250,000 ppm, in other cases up to about 200,000 ppm, in some instances up to about 100,000 ppm, in other instances up to about 50,000 ppm and in some situations up to about 25,000 ppm.
• the amount of total dissolved solids in the aqueous treatment solution can be any value or range between any of the values recited above.
• the total dissolved solids in the aqueous treatment fluid can contain multivalent cations at a level of at least about 10%, in some cases at least about 15% and in other cases at least about 20% and can be up to about 50%, in some cases up to about 40% and in other cases up to about 35% by weight of the total dissolved solids.
• the amount of multivalent cation in the total dissolved solids in the aqueous treatment solution can be any value or range between any of the values recited above.
• Additional additives can be included in the aqueous treatment fluids of the present disclosure as deemed appropriate by one of ordinary skill in the art, with the benefit of this disclosure.
• additives include, but are not limited to, corrosion inhibitors, proppant particulates, acids, fluid loss control additives, and surfactants.
• an acid may be included in the aqueous treatment fluids, among other things, for a matrix or fracture acidizing treatment.
• proppant particulates may be included in the aqueous treatment fluids to prevent the fracture from closing when the hydraulic pressure is released.
• aqueous treatment fluids of the present disclosure can be used in any subterranean treatment where the reduction of friction is desired.
• Such subterranean treatments include, but are not limited to, drilling operations, stimulation treatments (e.g., fracturing treatments, acidizing treatments, fracture acidizing treatments), and completion operations.
• stimulation treatments e.g., fracturing treatments, acidizing treatments, fracture acidizing treatments
• completion operations e.g., completion operations.
• the disclosed subject matter includes a method of treating a portion of a subterranean formation that includes providing the above-described aqueous treatment fluid and introducing the aqueous treatment fluid into the portion of the subterranean formation.
• the aqueous treatment fluid can be introduced into the portion of the subterranean formation at a rate and pressure sufficient to create or enhance one or more fractures in the portion of the subterranean formation.
• the portion of the subterranean formation that the aqueous treatment fluid is introduced will vary dependent upon the particular subterranean treatment.
• the portion of the subterranean formation may be a section of a well bore, for example, in a well bore cleanup operation.
• the portion may be the portion of the subterranean formation to be stimulated.
• the methods of the present disclosure can also include preparing the aqueous treatment fluid.
• Preparing the aqueous treatment fluid can include providing the water soluble polymer containing water-in-oil emulsion and combining the water soluble polymer with the water to from the aqueous treatment fluid.
• the water-in-oil emulsion composition was prepared by combining softened water, acrylamide, acrylic acid, acryloyloxyethyltrimethyl ammonium chloride (AETAC), EDTA and 25% sodium hydroxide (to pH of 6.5) and stirring until uniform to form the aqueous phase (about 77.5%).
• the oil phase (about 21.5%) was made by combining an aliphatic hydrocarbon liquid (about 20%) with surfactants (ethoxylated amine (about 1.1%), sorbitan monooleate (about 0.15%), and polyoxyalkylene sorbitan monooleate (about 0.25%) with mixing.
• the aqueous phase was added to the oil phase with mixing to form a dispersion of the aqueous phase dispersed in the continuous oil phase.
• the dispersion was heated to an initiation temperature while sparging with nitrogen and sodium metabisulfite and an oil soluble peroxide initiator was added to the dispersion to initiate polymerization.
• the oil phase was added to a glass resin kettle and once agitation was begun, the aqueous phase was added to the resin kettle.
• the resulting dispersion was sparged with nitrogen for 30 minutes while the temperature was equilibrated to 25° C., at which time 37 microliters of peroxide was added to the stirring dispersion and 0.075% sodium metabisulfite (SMBS) solution was fed to the dispersion at a rate of 0.1 milliliters per minute.
• SMBS sodium metabisulfite
• the polymerization temperature was controlled between 38° and 42° C. for approximately 90 minutes. Residual monomers were scavenged by feeding 25% sodium metabisulfite (SMBS) solution at a rate of 1.0 milliliters per minute.
• An inverting surfactant (C 12 -C 14 9 mole ethoxylate, 1.4%) was blended into the water-in-oil polymer emulsion to aid in make-down on use and the dispersion was subsequently cooled to room temperature.
• the resulting water-in-oil emulsion contained about 30% of water soluble polymer.
• a friction flow loop was constructed from 5/16′′ inner diameter stainless steel tubing, approximately 30 feet in overall length. Test solutions were pumped out of the bottom of a tapered 5 gallon reservoir. The solution flowed through the tubing and was returned back into the reservoir. The flow is achieved using a plunger pump equipped with a variable speed drive. Pressure is measured from two inline gages, with the last gage located approximately 2 ft from the discharge back into reservoir.
• the pressure drop was calculated at each time interval comparing it to the initial pressure differential reading of the brine solution.
• the percentage friction reduction was determined as described in U.S. Pat. No. 7,004,254 at col. 9, line 36 to col. 10, line 43.
• the brine used was an aqueous solution containing 165,000 ppm total dissolved solids including about 43,430 ppm sodium, 3,670 ppm magnesium, 14,400 ppm calcium and 103,290 ppm chloride.
• the results are shown in Table 2 below.
• the dose is the amount of water-in-oil emulsion used as gallons per thousand gallons of brine solution.
• the data show an improvement in friction reduction provided by the inventive water soluble polymers (Am/AA/AETAC) compared with traditional Am/AA copolymers.
• a water-in-oil emulsion polymer was prepared as in sample A in example 1 (48/2/50 w/w Am/AA/AETAC) except the inverting surfactant (C 12 -C 14 ethoxylate) was varied from 7 to 9 moles of ethoxylation as in Table 3 below.
• water-in-oil polymer emulsion polymers according to the disclosure are able to provide excellent better friction reduction performance in high brine solutions.
• Water-in-oil emulsion polymers were prepared as in sample A in example 1 (48/2/50 w/w Am/AA/AETAC) except the amount of inverting surfactant (C 12 -C 14 9-mole ethoxylate) was varied as shown in Table 5 below.
• the following samples were evaluated in a friction loop as described in example 1, except The brine used was an aqueous solution containing about 206,000 ppm total dissolved solids including about 53,500 ppm sodium, about 4,600 ppm magnesium, about 18,000 ppm calcium and about 139,300 ppm chloride. The results are shown in Table 6 below.
• the following samples were evaluated in a friction loop as described in example 1, except The brine used was an aqueous solution containing about 247,000 ppm total dissolved solids including about 65,010 ppm sodium, about 5,500 ppm magnesium, about 21.610 ppm calcium and about 154,930 ppm chloride. The results are shown in Table 7 below.
• water-in-oil polymer emulsion polymers according to the disclosure are able to provide excellent better friction reduction performance in high brine solutions.
• compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components, substances and steps.
• the term “consisting essentially of” shall be construed to mean including the listed components, substances or steps and such additional components, substances or steps which do not materially affect the basic and novel properties of the composition or method.
• a composition in accordance with embodiments of the present disclosure that “consists essentially of” the recited components or substances does not include any additional components or substances that alter the basic and novel properties of the composition, e.g., the friction reduction performance or viscosity of the composition.
• All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values.

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