CA2641479C - Method of using polyquaterniums in well treatments - Google Patents
Method of using polyquaterniums in well treatments Download PDFInfo
- Publication number
- CA2641479C CA2641479C CA2641479A CA2641479A CA2641479C CA 2641479 C CA2641479 C CA 2641479C CA 2641479 A CA2641479 A CA 2641479A CA 2641479 A CA2641479 A CA 2641479A CA 2641479 C CA2641479 C CA 2641479C
- Authority
- CA
- Canada
- Prior art keywords
- fluid
- well treatment
- monomer
- integer
- water
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Expired - Fee Related
Links
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
- C09K8/52—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning
- C09K8/536—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning characterised by their form or by the form of their components, e.g. encapsulated material
-
- 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
- C09K8/70—Compositions for forming crevices or fractures characterised by their form or by the form of their components, e.g. foams
Abstract
A subterranean formation, such as a low permeability gas reservoir, may be subjected to hydraulic fracturing by use of a well treatment fluid which is void of a viscosifying polymer and which contains, as a friction reducer, a high molecular weight polyacrylate of the formula: (A)a(B)b(C)c, wherein A is a dialkylaminoalkyl acrylate monomer or its quaternary ammonium or acid addition salt, B is a dialkylaminoalkyl methacrylate monomer or its quaternary ammonium or acid addition salt, C is a monomer that is polymerizable with A or B, a as an integer of 0 or greater, b is an integer of 0 or greater, c is an integer greater than 0 and either a or b, or both, must be 1 or greater. The well treatment fluid further contains water and an alcohol. The well treatment fluid is particularly applicable for use in slickwater fracturing operations.
Description
METHOD OF USING POLYQUATERNIUMS IN WELL TREATMENTS
SPECIFICATION
Field of the Invention The invention relates to the field of fracturing a subterranean formation by use of an aqueous fluid, which may be foamed, which contains a polyacrylate friction reducer.
Background of the Invention Hydraulic fracturing is a common stimulation technique used to enhance production of fluids from subterranean formations in oil, gas and geothermal wells. In a typical hydraulic fracturing treatment operation, a viscosified fracturing fluid is pumped at high pressures and high rates into a wellbore penetrating a subterranean formation to initiate and propagate a hydraulic fracture in the formation. Subsequent stages of viscosified fracturing fluid containing proppant are then typically pumped into the created fracture. Once the treatment is completed, the fracture closes onto a permeable proppant pack which maintains the fracture open and provides a highly conductive pathway for hydrocarbons and/or other formation fluids to flow into the wellbore.
Hydraulic fracturing is often used to stimulate low permeability formations where recovery efficiency is limited. For instance, hydraulic fracturing may be used in low permeability gas reservoirs, such as those having an in-situ matrix permeability to gas of 0.5 mD or less. Reservoirs with low in-situ matrix permeability often contain trapped saturated fluids since the reservoir is in contact with mobile water and exhibits capillary equilibrium with the mobile water. Such reservoirs are prevalent in the Deep Basin area in Canada, the Powder River Basin in the central portion of the United States and the Permian Basin in Texas where the average in-situ permeability may be 0.1mD or less.
The productivity of low permeability gas reservoirs is dependent on the proper selection of an appropriate fracturing fluid.
Fracturing fluids, especially those used in the stimulation of gas wells, often contain an alcohol, such as aqueous methanol, either by itself or in conjunction with a foaming agent (surfactant) and a gas, such as carbon dioxide or nitrogen. The use of an alcohol in stimulation fluids is desirable for several reasons. First, such solvents function as a freezing point depressant and often eliminate the need to heat aqueous fluids in cold weather climates. Second, such solvents minimize the tendency of clay in the reservoir to swell and migrate. As such, dislodgement of fines and migration of fines into the formation or fracture is minimized. Third, the presence of an alcohol prevents the suction of connate water into the hydrophilic clays and thus controls water imbibition, thereby reducing sub-irreducible initial water saturation within the formation. Such phenomena are discussed in Bennion et al, "Low Permeability Gas Reservoirs and Formation Damage ¨ Tricks and Traps", SPE 59753 (2000).
The stimulation of tight gas reservoirs normally uses aqueous fracturing fluids (such as water, salt brine and slickwater) which do not contain viscosifying polymers.
Slickwater fracturing refers to stimulation of a well by pumping water at high rates into the well, thereby creating a fracture in the productive formation. Slickwater fracturing is generally cheaper than conventional fracturing treatments which rely upon fracturing fluids containing a viscosifying polymer and/or gelled or gellable surfactant.
In addition, such fluids introduce less damage into the formation in light of the absence of a viscosifying polymer and/or surfactant in the fluid.
When aqueous fluids not containing a viscosfiying polymer are used in stimulation, the pressure during the pumping stage is normally lower than that required in fracturing treatments using viscosifying polymers. Such lower pressure is needed in order to reduce the frictional drag of the aqueous fluid against the well tubulars.
Polyacrylamide polymers are widely used as friction reducers for this purpose.
Polyacrylamide emulsions, however, are typically unacceptable, for use in the treatment of low permeability reservoirs, especially those found in cold climates. For instance, polyacrylamides typically precipitate from aqueous emulsions in the presence of an alcohol. Further, such fluids typically exhibit poor leakoff control of filtrate into the formation in light of their unviscosified nature.
SPECIFICATION
Field of the Invention The invention relates to the field of fracturing a subterranean formation by use of an aqueous fluid, which may be foamed, which contains a polyacrylate friction reducer.
Background of the Invention Hydraulic fracturing is a common stimulation technique used to enhance production of fluids from subterranean formations in oil, gas and geothermal wells. In a typical hydraulic fracturing treatment operation, a viscosified fracturing fluid is pumped at high pressures and high rates into a wellbore penetrating a subterranean formation to initiate and propagate a hydraulic fracture in the formation. Subsequent stages of viscosified fracturing fluid containing proppant are then typically pumped into the created fracture. Once the treatment is completed, the fracture closes onto a permeable proppant pack which maintains the fracture open and provides a highly conductive pathway for hydrocarbons and/or other formation fluids to flow into the wellbore.
Hydraulic fracturing is often used to stimulate low permeability formations where recovery efficiency is limited. For instance, hydraulic fracturing may be used in low permeability gas reservoirs, such as those having an in-situ matrix permeability to gas of 0.5 mD or less. Reservoirs with low in-situ matrix permeability often contain trapped saturated fluids since the reservoir is in contact with mobile water and exhibits capillary equilibrium with the mobile water. Such reservoirs are prevalent in the Deep Basin area in Canada, the Powder River Basin in the central portion of the United States and the Permian Basin in Texas where the average in-situ permeability may be 0.1mD or less.
The productivity of low permeability gas reservoirs is dependent on the proper selection of an appropriate fracturing fluid.
Fracturing fluids, especially those used in the stimulation of gas wells, often contain an alcohol, such as aqueous methanol, either by itself or in conjunction with a foaming agent (surfactant) and a gas, such as carbon dioxide or nitrogen. The use of an alcohol in stimulation fluids is desirable for several reasons. First, such solvents function as a freezing point depressant and often eliminate the need to heat aqueous fluids in cold weather climates. Second, such solvents minimize the tendency of clay in the reservoir to swell and migrate. As such, dislodgement of fines and migration of fines into the formation or fracture is minimized. Third, the presence of an alcohol prevents the suction of connate water into the hydrophilic clays and thus controls water imbibition, thereby reducing sub-irreducible initial water saturation within the formation. Such phenomena are discussed in Bennion et al, "Low Permeability Gas Reservoirs and Formation Damage ¨ Tricks and Traps", SPE 59753 (2000).
The stimulation of tight gas reservoirs normally uses aqueous fracturing fluids (such as water, salt brine and slickwater) which do not contain viscosifying polymers.
Slickwater fracturing refers to stimulation of a well by pumping water at high rates into the well, thereby creating a fracture in the productive formation. Slickwater fracturing is generally cheaper than conventional fracturing treatments which rely upon fracturing fluids containing a viscosifying polymer and/or gelled or gellable surfactant.
In addition, such fluids introduce less damage into the formation in light of the absence of a viscosifying polymer and/or surfactant in the fluid.
When aqueous fluids not containing a viscosfiying polymer are used in stimulation, the pressure during the pumping stage is normally lower than that required in fracturing treatments using viscosifying polymers. Such lower pressure is needed in order to reduce the frictional drag of the aqueous fluid against the well tubulars.
Polyacrylamide polymers are widely used as friction reducers for this purpose.
Polyacrylamide emulsions, however, are typically unacceptable, for use in the treatment of low permeability reservoirs, especially those found in cold climates. For instance, polyacrylamides typically precipitate from aqueous emulsions in the presence of an alcohol. Further, such fluids typically exhibit poor leakoff control of filtrate into the formation in light of their unviscosified nature.
A need exists therefore for aqueous based fracturing fluids, such as slickwater fracturing fluids, which are acceptable for use in low permeability reservoirs, especially in reservoirs which are exposed to cold climates.
Summary of the Invention Hydraulic fracturing using aqueous fracturing fluids is enhanced by the use of a well treatment fluid which is void of a viscosifying polymer. The fluid contains, as a friction reducer, a high molecular weight polyacrylate of the formula:
(A)a(B)b(C)c, wherein A is a dialkylaminoalkyl acrylate monomer or its quaternary ammonium or acid addition salt, B is a dialkylaminoalkyl methacrylate monomer or its quaternary ammonium or acid addition salt, C is a monomer that is polymerizable with A or B, a as an integer of 0 or greater, b is an integer of 0 or greater, c is an integer greater than 0 and either a or b, or both, must be 1 or greater.
The alkyl portions of the A and B monomers are preferably C1- C8 alkyl groups.
At least one of A and B is preferably quaternized. Acrylamide is especially desirable as the C monomer. In a preferred embodiment, the high molecular polyacrylate is polyquaternium 32.
In addition, the fluid for use in the invention contains water and an alcohol, such as a C1-C4 alkanol.
The method described herein using the well treatment fluid reduces leak-off from natural and created fractures into the pores of the formation. The well treatment fluids are particularly desirable in the stimulation of tight gas reservoirs where slickwater fracturing is desired.
The well treatment fluid may further be used in the cleaning of a wellbore.
For instance, the well treatment fluid may be used as a cleanout fluid in conjunction with a coiled tubing assembly.
The well treatment fluids described herein typically provide greater than 50%
more friction reduction compared to similar well treatment fluids which do not contain the high molecular polyacrylate.
Summary of the Invention Hydraulic fracturing using aqueous fracturing fluids is enhanced by the use of a well treatment fluid which is void of a viscosifying polymer. The fluid contains, as a friction reducer, a high molecular weight polyacrylate of the formula:
(A)a(B)b(C)c, wherein A is a dialkylaminoalkyl acrylate monomer or its quaternary ammonium or acid addition salt, B is a dialkylaminoalkyl methacrylate monomer or its quaternary ammonium or acid addition salt, C is a monomer that is polymerizable with A or B, a as an integer of 0 or greater, b is an integer of 0 or greater, c is an integer greater than 0 and either a or b, or both, must be 1 or greater.
The alkyl portions of the A and B monomers are preferably C1- C8 alkyl groups.
At least one of A and B is preferably quaternized. Acrylamide is especially desirable as the C monomer. In a preferred embodiment, the high molecular polyacrylate is polyquaternium 32.
In addition, the fluid for use in the invention contains water and an alcohol, such as a C1-C4 alkanol.
The method described herein using the well treatment fluid reduces leak-off from natural and created fractures into the pores of the formation. The well treatment fluids are particularly desirable in the stimulation of tight gas reservoirs where slickwater fracturing is desired.
The well treatment fluid may further be used in the cleaning of a wellbore.
For instance, the well treatment fluid may be used as a cleanout fluid in conjunction with a coiled tubing assembly.
The well treatment fluids described herein typically provide greater than 50%
more friction reduction compared to similar well treatment fluids which do not contain the high molecular polyacrylate.
Brief Description of the Drawings In order to more fully understand the drawings referred to in the detailed description of the present invention, a brief description of each drawing is presented, in which:
FIG. 1 exemplifies the percent friction reduction at 80 F of compositions, pre-mixed, containing the copolymer friction reducer as defined herein;
FIG. 2 exemplifies the percent friction reduction at 80 F of compositions, mixed on the fly, containing the copolymer friction reducer as defined herein; and FIG. 3 exemplifies the percent friction reduction at 50 F of compositions, mixed on the fly, containing the copolymer friction reducer as defined herein;
Detailed Description of the Preferred Embodiments The well treatment fluid for use in the invention contains a high molecular weight polyacrylate of the formula: (A)a(B)b(C)c, wherein A is a dialkylaminoalkyl acrylate monomer or its quaternary ammonium or acid addition salt, B is a dialkylaminoalkyl methacrylate monomer or its quaternary ammonium or acid addition salt, C is a monomer that is polymerizable with A or B (for example a monomer having a carbon-carbon double bond or such other polymerizable functional group), a as an integer of 0 or greater, b is an integer of 0 or greater, c is an integer greater than 0 and either a or b, or both, must be 1 or greater.
Suitable monomers of C include ethylene, propylene, butylene, isobutylene, eicosene, maleic anhydride, acrylamide, methacrylamide, maleic acid, acrolein, cyclohexene, ethyl vinyl ether, and methyl vinyl ether. In a preferred embodiment, C is acrylamide.
The alkyl portions of the A and B monomers are short chain length alkyls such as C1- C8, preferably Ci-05, more preferably C1-C3, and most preferably Ci-C2. At least one of A and B is preferably quaternized, preferably with short chain alkyls, i.e., CI- C83 preferably Ci-05, more preferably C1-C3, and most preferably C1-C2. The acid addition salts refer to polymers having protonated amino groups. Acid addition salts can be obtained through the use of halogen (e.g. chloride), acetic, phosphoric, nitric, citric, or other acids.
FIG. 1 exemplifies the percent friction reduction at 80 F of compositions, pre-mixed, containing the copolymer friction reducer as defined herein;
FIG. 2 exemplifies the percent friction reduction at 80 F of compositions, mixed on the fly, containing the copolymer friction reducer as defined herein; and FIG. 3 exemplifies the percent friction reduction at 50 F of compositions, mixed on the fly, containing the copolymer friction reducer as defined herein;
Detailed Description of the Preferred Embodiments The well treatment fluid for use in the invention contains a high molecular weight polyacrylate of the formula: (A)a(B)b(C)c, wherein A is a dialkylaminoalkyl acrylate monomer or its quaternary ammonium or acid addition salt, B is a dialkylaminoalkyl methacrylate monomer or its quaternary ammonium or acid addition salt, C is a monomer that is polymerizable with A or B (for example a monomer having a carbon-carbon double bond or such other polymerizable functional group), a as an integer of 0 or greater, b is an integer of 0 or greater, c is an integer greater than 0 and either a or b, or both, must be 1 or greater.
Suitable monomers of C include ethylene, propylene, butylene, isobutylene, eicosene, maleic anhydride, acrylamide, methacrylamide, maleic acid, acrolein, cyclohexene, ethyl vinyl ether, and methyl vinyl ether. In a preferred embodiment, C is acrylamide.
The alkyl portions of the A and B monomers are short chain length alkyls such as C1- C8, preferably Ci-05, more preferably C1-C3, and most preferably Ci-C2. At least one of A and B is preferably quaternized, preferably with short chain alkyls, i.e., CI- C83 preferably Ci-05, more preferably C1-C3, and most preferably C1-C2. The acid addition salts refer to polymers having protonated amino groups. Acid addition salts can be obtained through the use of halogen (e.g. chloride), acetic, phosphoric, nitric, citric, or other acids.
The molar proportion of C monomer, based on the total molar amount of A, B and C, can be from 1 molar % to about 99 molar %. The molar proportions of A and B
can each be from 0% to 100%. When acrylamide, is used as the C monomer, it will preferably be used at a level of from about 20% to about 99%, more preferably from about 50% to about 90%.
Where monomer A and B are both present, the ratio of monomer A to monomer B
in the final polymer, on a molar basis, is preferably from about 99:5 to about 15:85, more preferably from about 80:20 to about 20:80. Alternatively, in another class of polymers, the ratio is from about 5:95 to about 50:50, preferably from about 5:95 to about 25:75. In another alternative class of polymers, the ratio A:B is from about 50:50 to about 85:15.
Preferably the ratio A:B is about 60:40 to about 85:15, most preferably about 75:25 to about 85:15.
Most preferred is a cationic polymer where monomer A is not present, B is preferably methyl quaternized dimethylaminoethyl methacrylate and the ratio of monomer B:C is from about 30:70 to about 70:30, preferably from about 40:60 to about 60:40 and most preferably from about 45:55 to about 55:45. An example of a cationic polymer is designated as CAS Registry Number 35429-19-7 and may be referred to as polyquaternium 32.
In addition, the fluid for use in the invention contains water and an alcohol, such as a C1-C4 alkanol. Preferred CI-Ca alkanols are preferably methanol, ethanol or isopropanol, most preferably methanol. Further, the water can be any aqueous solution such as distilled water, fresh water or salt water or brine. Typically, the alkanol/water blend contains between from about 15 to about 80 volume percent of alkanol and the remainder water. The well treatment fluid typically contains from about 15 to about 50 volume percent of the aqueous blend of alkanol and water. Since the fluid contains a high percentage of alcohol, the emulsion is particularly efficacious when used in gas wells.
The well treatment fluid normally exhibits a viscosity less than or equal to centipoi se s.
The high molecular weight polyacrylate may be prepared by polymerization of the monomers in an aqueous solution in the presence of an initiator (usually a redox or =
thermal initiator) until the polymerization terminates. In the polymerization reaction, the temperature generally starts between about 0 C and 95 C.
In a preferred embodiment, the polymerization is conducted by forming an invert (or reverse) emulsion of an aqueous phase of the monomers in an outer (or continuous) hydrophobic phase of non-aqueous solvent which is either non-miscible in or slightly miscible with water. Suitable non-aqueous solvents include as mineral oil, lanolin, isododecane, oleyl alcohol and other volatile and other nonvolatile solvents like terpenes, mono-, di- and tri-glycerides of saturated or unsaturated fatty acids including natural and synthetic triglycerides, aliphatic esters such as methyl esters of a mixture of acetic, succinic and glutaric acids, aliphatic ethers of glycols such as ethylene glycol monobutyl ether, minerals oils such as vaseline oil, chlorinated solvents like 1,1,1-trichloroethane, perchloroethylene and methylene chloride, deodorized kerosene, solvent naphtha, paraffins (including linear paraffins), isoparaffins, olefins (especially linear olefins) and aliphatic or aromatic hydrocarbons (such as toluene).
Such reverse emulsions release the high molecular weight polyacrylate upon contact with the aqueous mixture of water and alcohol where the polyacrylate hydrates.
Thus, they are particularly useful when used on the fly since inversion may occur almost immediately when placed into contact with water. Such reverse emulsions are particularly desirable when slickwater is used. Inversion of the emulsion typically occurs almost instantaneously even at a temperature of 50 F.
The outer phase may further contain a surfactant which enhances the formation of the emulsion and facilitates the inversion of the emulsion into the aqueous mixture. The surfactant is preferably hydrophobic though it may be characterized as having portions which are strongly attracted to each of the phases present, i.e., hydrophilic and hydrophobic portions. Suitable surfactants include non-ionic as well as ionic surfactants such as sorbitan derivatives, glycerol derivatives, cetyl alcohol derivatives, polyoxyalkylenes and sulfonates. Particular surfactants may include sorbitan trioleate and polyoxyethylenated sorbitans, glycerol monostearate, propylene glycerol monostearate, sodium cetyl stearyl sulfate, cetyl ethyl morpholinium ethosulfate, polyoxyethylene alkyl amines and alkyl aryl sulfonates.
can each be from 0% to 100%. When acrylamide, is used as the C monomer, it will preferably be used at a level of from about 20% to about 99%, more preferably from about 50% to about 90%.
Where monomer A and B are both present, the ratio of monomer A to monomer B
in the final polymer, on a molar basis, is preferably from about 99:5 to about 15:85, more preferably from about 80:20 to about 20:80. Alternatively, in another class of polymers, the ratio is from about 5:95 to about 50:50, preferably from about 5:95 to about 25:75. In another alternative class of polymers, the ratio A:B is from about 50:50 to about 85:15.
Preferably the ratio A:B is about 60:40 to about 85:15, most preferably about 75:25 to about 85:15.
Most preferred is a cationic polymer where monomer A is not present, B is preferably methyl quaternized dimethylaminoethyl methacrylate and the ratio of monomer B:C is from about 30:70 to about 70:30, preferably from about 40:60 to about 60:40 and most preferably from about 45:55 to about 55:45. An example of a cationic polymer is designated as CAS Registry Number 35429-19-7 and may be referred to as polyquaternium 32.
In addition, the fluid for use in the invention contains water and an alcohol, such as a C1-C4 alkanol. Preferred CI-Ca alkanols are preferably methanol, ethanol or isopropanol, most preferably methanol. Further, the water can be any aqueous solution such as distilled water, fresh water or salt water or brine. Typically, the alkanol/water blend contains between from about 15 to about 80 volume percent of alkanol and the remainder water. The well treatment fluid typically contains from about 15 to about 50 volume percent of the aqueous blend of alkanol and water. Since the fluid contains a high percentage of alcohol, the emulsion is particularly efficacious when used in gas wells.
The well treatment fluid normally exhibits a viscosity less than or equal to centipoi se s.
The high molecular weight polyacrylate may be prepared by polymerization of the monomers in an aqueous solution in the presence of an initiator (usually a redox or =
thermal initiator) until the polymerization terminates. In the polymerization reaction, the temperature generally starts between about 0 C and 95 C.
In a preferred embodiment, the polymerization is conducted by forming an invert (or reverse) emulsion of an aqueous phase of the monomers in an outer (or continuous) hydrophobic phase of non-aqueous solvent which is either non-miscible in or slightly miscible with water. Suitable non-aqueous solvents include as mineral oil, lanolin, isododecane, oleyl alcohol and other volatile and other nonvolatile solvents like terpenes, mono-, di- and tri-glycerides of saturated or unsaturated fatty acids including natural and synthetic triglycerides, aliphatic esters such as methyl esters of a mixture of acetic, succinic and glutaric acids, aliphatic ethers of glycols such as ethylene glycol monobutyl ether, minerals oils such as vaseline oil, chlorinated solvents like 1,1,1-trichloroethane, perchloroethylene and methylene chloride, deodorized kerosene, solvent naphtha, paraffins (including linear paraffins), isoparaffins, olefins (especially linear olefins) and aliphatic or aromatic hydrocarbons (such as toluene).
Such reverse emulsions release the high molecular weight polyacrylate upon contact with the aqueous mixture of water and alcohol where the polyacrylate hydrates.
Thus, they are particularly useful when used on the fly since inversion may occur almost immediately when placed into contact with water. Such reverse emulsions are particularly desirable when slickwater is used. Inversion of the emulsion typically occurs almost instantaneously even at a temperature of 50 F.
The outer phase may further contain a surfactant which enhances the formation of the emulsion and facilitates the inversion of the emulsion into the aqueous mixture. The surfactant is preferably hydrophobic though it may be characterized as having portions which are strongly attracted to each of the phases present, i.e., hydrophilic and hydrophobic portions. Suitable surfactants include non-ionic as well as ionic surfactants such as sorbitan derivatives, glycerol derivatives, cetyl alcohol derivatives, polyoxyalkylenes and sulfonates. Particular surfactants may include sorbitan trioleate and polyoxyethylenated sorbitans, glycerol monostearate, propylene glycerol monostearate, sodium cetyl stearyl sulfate, cetyl ethyl morpholinium ethosulfate, polyoxyethylene alkyl amines and alkyl aryl sulfonates.
A particularly preferred polyacrylate-containing reverse emulsion for use in the invention is one which is an approximate 50% by weight dispersion of 1 micron diameter particles with low water content (<6%) and contains essentially linear high molecular weight cationic acrylamide copolymer in a naphthenic mineral seal oil. The copolymer may consist of 20% by weight acrylamide and about 80% by weight of methacryloxyethyl trimethyl ammonium chloride and has a molecular weight between about 5 to 7 million. Such products may be commercially available as a mineral oil dispersion from Ciba Specialty Chemicals PLC under the trademark ZETAGo.
The well treatment fluid may further be combined with proppant and breaker.
When used, the breaker is typically an oil or is oil-based. Suitable breakers in such circumstances include mineral oil.
The well treatment fluids used herein exhibit acceptable fluid loss control properties and thus reduce leak-off from the fracture into the pores of the formation. In addition to preventing leak-off, the fluids exhibit a viscosity which is sufficient to support proppant without settling. The fluid, however, is void of a crosslinked or non-crosslinked viscosifying polymer (a polymer which imparts viscosity to the fluid).
The well treatment fluid used herein may further be energized (containing less than or equal to 63 volume percent of foaming agent) or foamed with a gas (containing more than 63 volume percent of foaming agent). Any foaming agent may be employed though the foaming agent is most preferably nitrogen and/or carbon dioxide.
The presence of the gas in the well treatment fluid is especially effective in controlling leak off into the natural and created fractures as well as providing increased viscosity to the fluid while minimizing the amount of water pumped into the formation.
The well treatment fluids described herein typically provide greater than 50%
more friction reduction compared to similar well treatment fluids which do not contain the high molecular polyacrylate. The well treatment fluids described herein further minimize the tendency of clay in the reservoir to swell and migrate.
The well treatment fluids are particularly desirable in the stimulation of low permeability gas reservoirs such as when slicicwater fracturing is employed.
The presence of the polyacrylate in the well treatment fluid reduces the frictional drag of the aqueous fluid against tubulars within the wellbore. Further, use of the well treatment agent in slickwater fracturing improves leakoff control of filtrate into the formation.
The well treatment fluids described herein may further be used as a cleaning fluid.
For instance, the well treatment fluid may be used to clean unwanted particulate matter from a wellbore such as fills which accumulate in the bottom or bottom portions of oil and gas wellbores. The fill may include proppant, weighting materials, gun debris, accumulated powder as well as crushed sandstone. Fill might include general formation debris and well rock in addition to cuttings from drilling muds. The well treatment fluids may be used in conjunction with conventional cleaning equipment. More particularly, the well treatment fluids may be used in conjunction with coiled tubing. For instance, the well treatment fluid may be used to clean fill from a wellbore by disturbing particulate solids by running in hole with a coiled tubing assembly while circulating the fluid through a nozzle having a jetting action directed downhole. This may include creating particulate entrainment by pulling out of hole while circulating the well treatment fluid through a nozzle having a jetting action directed uphole. Such mechanisms and coiled tubing systems include those set forth in U.S. Pat. No. 6,982,008.
The following examples are illustrative of some of the embodiments of the present invention.
All percentages set forth in the Examples are given in terms of weight units except as may otherwise be indicated.
Examples The Examples illustrate the ability of the subject friction reducer to rapidly hydrate in a winterized methanol/water solution.
The following components were used in the Examples:
The well treatment fluid may further be combined with proppant and breaker.
When used, the breaker is typically an oil or is oil-based. Suitable breakers in such circumstances include mineral oil.
The well treatment fluids used herein exhibit acceptable fluid loss control properties and thus reduce leak-off from the fracture into the pores of the formation. In addition to preventing leak-off, the fluids exhibit a viscosity which is sufficient to support proppant without settling. The fluid, however, is void of a crosslinked or non-crosslinked viscosifying polymer (a polymer which imparts viscosity to the fluid).
The well treatment fluid used herein may further be energized (containing less than or equal to 63 volume percent of foaming agent) or foamed with a gas (containing more than 63 volume percent of foaming agent). Any foaming agent may be employed though the foaming agent is most preferably nitrogen and/or carbon dioxide.
The presence of the gas in the well treatment fluid is especially effective in controlling leak off into the natural and created fractures as well as providing increased viscosity to the fluid while minimizing the amount of water pumped into the formation.
The well treatment fluids described herein typically provide greater than 50%
more friction reduction compared to similar well treatment fluids which do not contain the high molecular polyacrylate. The well treatment fluids described herein further minimize the tendency of clay in the reservoir to swell and migrate.
The well treatment fluids are particularly desirable in the stimulation of low permeability gas reservoirs such as when slicicwater fracturing is employed.
The presence of the polyacrylate in the well treatment fluid reduces the frictional drag of the aqueous fluid against tubulars within the wellbore. Further, use of the well treatment agent in slickwater fracturing improves leakoff control of filtrate into the formation.
The well treatment fluids described herein may further be used as a cleaning fluid.
For instance, the well treatment fluid may be used to clean unwanted particulate matter from a wellbore such as fills which accumulate in the bottom or bottom portions of oil and gas wellbores. The fill may include proppant, weighting materials, gun debris, accumulated powder as well as crushed sandstone. Fill might include general formation debris and well rock in addition to cuttings from drilling muds. The well treatment fluids may be used in conjunction with conventional cleaning equipment. More particularly, the well treatment fluids may be used in conjunction with coiled tubing. For instance, the well treatment fluid may be used to clean fill from a wellbore by disturbing particulate solids by running in hole with a coiled tubing assembly while circulating the fluid through a nozzle having a jetting action directed downhole. This may include creating particulate entrainment by pulling out of hole while circulating the well treatment fluid through a nozzle having a jetting action directed uphole. Such mechanisms and coiled tubing systems include those set forth in U.S. Pat. No. 6,982,008.
The following examples are illustrative of some of the embodiments of the present invention.
All percentages set forth in the Examples are given in terms of weight units except as may otherwise be indicated.
Examples The Examples illustrate the ability of the subject friction reducer to rapidly hydrate in a winterized methanol/water solution.
The following components were used in the Examples:
ZETAG 7888, a 50% by weight dispersion containing a copolymer of acrylamide 20% and methacryloxyethyl trimethyl ammonium chloride 80% (by weight) of molecular weight between from 5 to 7 million, in a naphthenic mineral seal oil;
ALCOMER 11ORD, a dry polyacrylamide friction reducer;
MAGNAFLOC 156, a high molecular weight fully anionic polyacrylamide flocculant, supplied as a free flowing micro bead.
FRW-14, a high molecular weight acrylamidomethylpropane sulfonic acid (AMPS) copolymer friction reducer formulation, a product of BJ Services Company; and ALCOMER 11ORD, a high molecular weight, anionic, water-soluble, acrylamide-based copolymer, supplied as a free-flowing powder.
Examples 1-11. These Examples relate to the solubility of the tested components.
Approximately 60 ml of tap water was measured into a glass beaker. While stirring using an overhead stirrer, 40 ml of methanol was added. The methanol/water solution was mixed for about a minute, and then polymer was added. The fluid was mixed for another 15 minutes at 2500 rpm. Compositions and results are set forth in Table I
below:
Table I
Ex. No. Water, Methanol, Polymer, Amount Observations ml ml Comp. 60 40 ALCOMER 11ORD, 0.012 Polymer swelled, not completely in solution.
Ex. I vol. %
Comp. 80 20 ALCOMER 11ORD, 0.012 Polymer swelled, not completely in solution.
Ex. 2 vol. %) Comp Ex. 60 40 ALCOMER 11ORD, 0.25 Polymer swelled and sample gelled, not 3 vol %) completely in solution Comp. 60 40 FRW-14, 0.5 gpt Settling on bottom of glass jar, not into Ex. 4 solution.
Comp. 80 20 FRW-14, 0.5 gpt Went into solution only after mixing of Ex. 5 polymer.
Comp. 70 30 FRW-14, 0.5 gpt Went into solution only after mixing of Ex. 6 polymer.
7 60 40 ZETAG 7888, 0.5 gpt Very thick gel, polymer went into solution.
8 60 40 ZETAG 7888, 1 gpt Sample gelled, polymer into solution.
ALCOMER 11ORD, a dry polyacrylamide friction reducer;
MAGNAFLOC 156, a high molecular weight fully anionic polyacrylamide flocculant, supplied as a free flowing micro bead.
FRW-14, a high molecular weight acrylamidomethylpropane sulfonic acid (AMPS) copolymer friction reducer formulation, a product of BJ Services Company; and ALCOMER 11ORD, a high molecular weight, anionic, water-soluble, acrylamide-based copolymer, supplied as a free-flowing powder.
Examples 1-11. These Examples relate to the solubility of the tested components.
Approximately 60 ml of tap water was measured into a glass beaker. While stirring using an overhead stirrer, 40 ml of methanol was added. The methanol/water solution was mixed for about a minute, and then polymer was added. The fluid was mixed for another 15 minutes at 2500 rpm. Compositions and results are set forth in Table I
below:
Table I
Ex. No. Water, Methanol, Polymer, Amount Observations ml ml Comp. 60 40 ALCOMER 11ORD, 0.012 Polymer swelled, not completely in solution.
Ex. I vol. %
Comp. 80 20 ALCOMER 11ORD, 0.012 Polymer swelled, not completely in solution.
Ex. 2 vol. %) Comp Ex. 60 40 ALCOMER 11ORD, 0.25 Polymer swelled and sample gelled, not 3 vol %) completely in solution Comp. 60 40 FRW-14, 0.5 gpt Settling on bottom of glass jar, not into Ex. 4 solution.
Comp. 80 20 FRW-14, 0.5 gpt Went into solution only after mixing of Ex. 5 polymer.
Comp. 70 30 FRW-14, 0.5 gpt Went into solution only after mixing of Ex. 6 polymer.
7 60 40 ZETAG 7888, 0.5 gpt Very thick gel, polymer went into solution.
8 60 40 ZETAG 7888, 1 gpt Sample gelled, polymer into solution.
9 60 40 MAGNAFLOC 156, 1 ppt Insoluble.
10 70 30 MAGNAFLOC 156, 1 ppt Sample did not gel;
polymer into solution only after mixing.
polymer into solution only after mixing.
11 80 20 MAGNAFLOC 156, 1 ppt Sample did not gel, polymer into solution only after mixing.
As set forth in Table I, the polymer in Comparative Examples 1-3 did not hydrate in the water/methanol solutions. ALCOMER 11ORD needs high shear (8000 rpm) and water with no methanol to go into solution. In Comparative Example 4, the polymer precipitated when added to a 60/40 water/methanol solution. In Comparative Examples 5-6, the polymer went into solution only at lower methanol concentration solutions with additional mixing. In Examples 7-8, the polymer was soluble in a 60/40 water/methanol solution at both concentrations, 0.5 gpt and 1 gpt. In Comparative Examples 9-11, the polymer at 1 ppt was soluble in solutions with lower methanol concentration solutions (70/30 water/Me0H and lower). The product further required at least 15 minutes of mixing time.
Examples 12-17.
The amount of friction reduction of various friction reducers in methanol/water solutions was determined.
A friction loop was comprised of a small gear pump with a range of 1.5-3.25 gpm, a manual pressure gauge, and 20 ft. of 1/4" tube coiled in a circle of 1.5 ft. diameter.
Fluid was drawn from a bucket into the pump via a large 1/4" nylon tube. The fluid passed through the pump. Immediately after exiting the pump, the fluid passed through the pressure transducer, situated between the pump and the section of tubing.
After passing through the 1/4" stainless steel tubing, the fluid entered a short section of 3/4" nylon tubing that was submerged in the fluid as it re-entered the bucket. This prevented air entrapment in the fluid. Fluid was re-circulated through the coil continuously at various flow rates.
Tap water (1800 ml), methanol (1200 ml) and polymer were mixed in high shear with an overhead stirrer for 15 minutes. Fluid was transferred to the friction loop bucket and a screening loop program was allowed to commence. The fluid was circulated through the loop initially at the highest flow rate and then decreasing flow rate in several increments. Differential pressure was measured at each flow rate.
The compositions tested are set forth in Table II:
Table II
Ex. No. Polymer, Amount Comp. Ex. 12 ALCOMER 1101W, 1.0 ppt _ Comp. Ex. 13 ALCOMER 11ORD, 5.0 ppt Ex. 14 ZETAG 7888, 0.25 gpt Ex. 15 ZETAG 7888, 0.5 gpt Ex. 16 ZETAG 7888, 1.0 gpt Ex. 17 ZETAG 7888, 1.5 gpt FIG. 1 exemplifies the percent friction reduction at 80 F at the stated concentrations in the water/methanol solution. As shown in FIG. 1, Example 15 rendered the best friction reduction performance Examples 16 and 17 also show significant friction reduction in the 60% water and 40% methanol solution. ZETAG 7888 at the 0.25 gpt concentration in the 60% water and 40% methanol solution showed some shear degradation with time at shear.
Examples 18-21.
The amount of friction reduction of various friction reducers in methanol/water solutions was determined by mixing the components on the fly.
The friction loop was comprised of a small gear pump with a range of 1.5-3.25 gpm, a manual pressure gauge, and 20 ft. of 1/4" tube coiled in a circle of 1.5 ft. diameter.
Fluid was drawn from a bucket into the pump via a large 3/4" nylon tube. The fluid passed through the pump. Immediately after exiting the pump, the fluid passed through the pressure transducer, situated between the pump and the section of tubing.
After passing through the 1/4" stainless steel tubing, the fluid entered a short section of 3/4" nylon tubing that was submerged in the fluid as it re-entered the bucket. This prevented air entrapment in the fluid. Fluid was re-circulated through the coil continuously at various flow rates.
To the screening loop bucket were added 1800 ml of water and 1200 ml of methanol. The polymer and optional surfactant (a hydrate enhancer composed of alkoxylated alcohols, commercially available as PSA-2L from BJ Services Company, were then added to the re-circulating fluid. The fluid was circulated through the loop, and the differential pressure was recorded every second for 5 to 10 minutes total circulation time. Testing was conducted in ambient temperature conditions, ¨80 F, and in cold water at 50 F. The compositions tested are set forth in Table III:
Table III
Ex. No. Polymer, Amount (gpt) PSA-2L, gpt Ex. 18 ZETAG 7888,0.25 2.0 Ex. 19 _ ZETAG 7888, 0.5 Ex. 20 ZETAG 7888, 0.5 2.0 Ex. 21 ZETAG 7888, 0.5 3.0 FIG. 2 exemplifies the percent friction reduction at 80 F at the stated concentrations in the water/methanol solution. As shown in FIG. 2, hydration is much faster and friction reduction is quicker when the formulation contains PSA-2L at a concentration of polymer of 0.25 gpt. Formulations containing a concentration of polymer of 0.5 gpt hydrates quickly and shows excellent friction reduction. FIG. 3 exemplifies the percent friction reduction at 50 F at the stated concentrations in the water/methanol solution.
As shown in FIG. 3, hydration is also much faster and friction reduction is quicker when the formulation contains PSA-2L at a concentration of polymer of 0.25 gpt.
Hydration rate of the polymer at a concentration of 0.5 gpt is slowed by the addition of the PSA-2L.
Example 22. This Example illustrates the carbon dioxide compatibility of ZETAG
7888. A 500 inL sample fluid was prepared containing 5 gpt ZETAG0 7888 in v/v mixture of fresh water and methanol was prepared. About 300 mL of the fluid was introduced into a large chamber viewing cell, typically used to inspect foams.
The cell was oriented vertically and there were two valves on the bottom of the viewing cell and one valve and a pressure regulator on the top of the viewing cell. The fluid was poured into the viewing cell from the top through a funnel and the existing 1/2"
stainless steel tubing. This filled the chamber to about 50% of its volumetric capacity. The top valve and regulator were then replaced. Carbon dioxide was then flowed from a dip (siphon) tube bottle with the flow being regulated by a CO2 pressure regulator. Carbon dioxide was then introduced into the bottom of the cell and effectively bubbled up through the liquid fluid. The pressure on the chamber was controlled via the regulator on top of the viewing cell. Observations were made looking for color changes, precipitates and solids or any other indications that would be consistent with fluid incompatibility.
No incompatibility was noted. The fluid remained cloudy, but no particulates were noted in the view cell or graduated cylinder. The pressure was then relieved via the top (a ventilator was used to evacuate the area of any C07). The fluid was drained out and a 250 mL sample was captured in a glass graduated cylinder, which was placed on the counter top and observed for 1 day. No incompatibility was observed.
As set forth in Table I, the polymer in Comparative Examples 1-3 did not hydrate in the water/methanol solutions. ALCOMER 11ORD needs high shear (8000 rpm) and water with no methanol to go into solution. In Comparative Example 4, the polymer precipitated when added to a 60/40 water/methanol solution. In Comparative Examples 5-6, the polymer went into solution only at lower methanol concentration solutions with additional mixing. In Examples 7-8, the polymer was soluble in a 60/40 water/methanol solution at both concentrations, 0.5 gpt and 1 gpt. In Comparative Examples 9-11, the polymer at 1 ppt was soluble in solutions with lower methanol concentration solutions (70/30 water/Me0H and lower). The product further required at least 15 minutes of mixing time.
Examples 12-17.
The amount of friction reduction of various friction reducers in methanol/water solutions was determined.
A friction loop was comprised of a small gear pump with a range of 1.5-3.25 gpm, a manual pressure gauge, and 20 ft. of 1/4" tube coiled in a circle of 1.5 ft. diameter.
Fluid was drawn from a bucket into the pump via a large 1/4" nylon tube. The fluid passed through the pump. Immediately after exiting the pump, the fluid passed through the pressure transducer, situated between the pump and the section of tubing.
After passing through the 1/4" stainless steel tubing, the fluid entered a short section of 3/4" nylon tubing that was submerged in the fluid as it re-entered the bucket. This prevented air entrapment in the fluid. Fluid was re-circulated through the coil continuously at various flow rates.
Tap water (1800 ml), methanol (1200 ml) and polymer were mixed in high shear with an overhead stirrer for 15 minutes. Fluid was transferred to the friction loop bucket and a screening loop program was allowed to commence. The fluid was circulated through the loop initially at the highest flow rate and then decreasing flow rate in several increments. Differential pressure was measured at each flow rate.
The compositions tested are set forth in Table II:
Table II
Ex. No. Polymer, Amount Comp. Ex. 12 ALCOMER 1101W, 1.0 ppt _ Comp. Ex. 13 ALCOMER 11ORD, 5.0 ppt Ex. 14 ZETAG 7888, 0.25 gpt Ex. 15 ZETAG 7888, 0.5 gpt Ex. 16 ZETAG 7888, 1.0 gpt Ex. 17 ZETAG 7888, 1.5 gpt FIG. 1 exemplifies the percent friction reduction at 80 F at the stated concentrations in the water/methanol solution. As shown in FIG. 1, Example 15 rendered the best friction reduction performance Examples 16 and 17 also show significant friction reduction in the 60% water and 40% methanol solution. ZETAG 7888 at the 0.25 gpt concentration in the 60% water and 40% methanol solution showed some shear degradation with time at shear.
Examples 18-21.
The amount of friction reduction of various friction reducers in methanol/water solutions was determined by mixing the components on the fly.
The friction loop was comprised of a small gear pump with a range of 1.5-3.25 gpm, a manual pressure gauge, and 20 ft. of 1/4" tube coiled in a circle of 1.5 ft. diameter.
Fluid was drawn from a bucket into the pump via a large 3/4" nylon tube. The fluid passed through the pump. Immediately after exiting the pump, the fluid passed through the pressure transducer, situated between the pump and the section of tubing.
After passing through the 1/4" stainless steel tubing, the fluid entered a short section of 3/4" nylon tubing that was submerged in the fluid as it re-entered the bucket. This prevented air entrapment in the fluid. Fluid was re-circulated through the coil continuously at various flow rates.
To the screening loop bucket were added 1800 ml of water and 1200 ml of methanol. The polymer and optional surfactant (a hydrate enhancer composed of alkoxylated alcohols, commercially available as PSA-2L from BJ Services Company, were then added to the re-circulating fluid. The fluid was circulated through the loop, and the differential pressure was recorded every second for 5 to 10 minutes total circulation time. Testing was conducted in ambient temperature conditions, ¨80 F, and in cold water at 50 F. The compositions tested are set forth in Table III:
Table III
Ex. No. Polymer, Amount (gpt) PSA-2L, gpt Ex. 18 ZETAG 7888,0.25 2.0 Ex. 19 _ ZETAG 7888, 0.5 Ex. 20 ZETAG 7888, 0.5 2.0 Ex. 21 ZETAG 7888, 0.5 3.0 FIG. 2 exemplifies the percent friction reduction at 80 F at the stated concentrations in the water/methanol solution. As shown in FIG. 2, hydration is much faster and friction reduction is quicker when the formulation contains PSA-2L at a concentration of polymer of 0.25 gpt. Formulations containing a concentration of polymer of 0.5 gpt hydrates quickly and shows excellent friction reduction. FIG. 3 exemplifies the percent friction reduction at 50 F at the stated concentrations in the water/methanol solution.
As shown in FIG. 3, hydration is also much faster and friction reduction is quicker when the formulation contains PSA-2L at a concentration of polymer of 0.25 gpt.
Hydration rate of the polymer at a concentration of 0.5 gpt is slowed by the addition of the PSA-2L.
Example 22. This Example illustrates the carbon dioxide compatibility of ZETAG
7888. A 500 inL sample fluid was prepared containing 5 gpt ZETAG0 7888 in v/v mixture of fresh water and methanol was prepared. About 300 mL of the fluid was introduced into a large chamber viewing cell, typically used to inspect foams.
The cell was oriented vertically and there were two valves on the bottom of the viewing cell and one valve and a pressure regulator on the top of the viewing cell. The fluid was poured into the viewing cell from the top through a funnel and the existing 1/2"
stainless steel tubing. This filled the chamber to about 50% of its volumetric capacity. The top valve and regulator were then replaced. Carbon dioxide was then flowed from a dip (siphon) tube bottle with the flow being regulated by a CO2 pressure regulator. Carbon dioxide was then introduced into the bottom of the cell and effectively bubbled up through the liquid fluid. The pressure on the chamber was controlled via the regulator on top of the viewing cell. Observations were made looking for color changes, precipitates and solids or any other indications that would be consistent with fluid incompatibility.
No incompatibility was noted. The fluid remained cloudy, but no particulates were noted in the view cell or graduated cylinder. The pressure was then relieved via the top (a ventilator was used to evacuate the area of any C07). The fluid was drained out and a 250 mL sample was captured in a glass graduated cylinder, which was placed on the counter top and observed for 1 day. No incompatibility was observed.
Claims (13)
1. A method of fracturing a subterranean formation penetrated by a wellbore which comprises introducing into the wellbore an aqueous well treatment fluid void of a viscosifying polymer and comprising:
(a) an alkanol; and (b) a polyacrylate of the formula: (A)a(B)b(C)c, wherein A is a dialkylaminoalkyl acrylate monomer or its quaternary ammonium or acid addition salt, B
is a dialkylaminoalkyl methacrylate monomer or its quaternary ammonium or acid addition salt, C is a monomer that is polymerizable with A or B, a is an integer of 0 or greater, b is an integer of 0 or greater, c is an integer greater than 0 and either a or b, or both, must be 1 or greater; and (c) water; and (d) proppant wherein the viscosity of the well treatment fluid is less than or equal to 10 centipoises.
(a) an alkanol; and (b) a polyacrylate of the formula: (A)a(B)b(C)c, wherein A is a dialkylaminoalkyl acrylate monomer or its quaternary ammonium or acid addition salt, B
is a dialkylaminoalkyl methacrylate monomer or its quaternary ammonium or acid addition salt, C is a monomer that is polymerizable with A or B, a is an integer of 0 or greater, b is an integer of 0 or greater, c is an integer greater than 0 and either a or b, or both, must be 1 or greater; and (c) water; and (d) proppant wherein the viscosity of the well treatment fluid is less than or equal to 10 centipoises.
2. The method of Claim 1, wherein C is selected from the group consisting of ethylene, propylene, butylene, isobutylene, eicosene, maleic anhydride, acrylamide, methacrylamide, maleic acid, acrolein, cyclohexene, ethyl vinyl ether, and methyl vinyl ether.
3. The method of Claim 2, wherein C is acrylamide.
4. The method of Claim 1, wherein the alkyl portions of the A and B
monomers are independently selected form a C1-C8 alkyl group.
monomers are independently selected form a C1-C8 alkyl group.
5. The method of Claim 4, wherein the alkyl portion of the A and B
monomers are a C1-C5 alkyl group.
monomers are a C1-C5 alkyl group.
6. The method of Claim 5, wherein the alkyl portion of the A and B
monomers are a C1-C2 alkyl group.
monomers are a C1-C2 alkyl group.
7. The method of Claim 1, wherein a is 0, B is methyl quaternized dimthylaminoethyl methacrylate and the ratio of B:C is between from about 45:55 to about 55:45.
8. The method of Claim 1, wherein the alkanol is methanol.
9. The method of Claim 1, wherein the fluid further comprises a surfactant.
10. The method of Claim 1, wherein the fluid further comprises a gas.
11. The method of Claim 10, wherein the gas is carbon dioxide or nitrogen.
12. A method of slickwater fracturing a subterranean formation comprising:
injecting into the formation at a pressure sufficient to fracture the formation an emulsion comprising a polyacrylate of the formula (B)(C), wherein B is methyl quaternized dimethylaminoethyl methacrylate, C is acrylamide and the weight ratio of B:C
is between from about 45:55 to about 55:45.
injecting into the formation at a pressure sufficient to fracture the formation an emulsion comprising a polyacrylate of the formula (B)(C), wherein B is methyl quaternized dimethylaminoethyl methacrylate, C is acrylamide and the weight ratio of B:C
is between from about 45:55 to about 55:45.
13. The method of Claim 12, wherein the polyacrylate is polyquaternium 32.
Priority Applications (2)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA2829901A CA2829901C (en) | 2008-10-22 | 2008-10-22 | Method of using polyquaterniums in well treatments |
| CA2641479A CA2641479C (en) | 2008-10-22 | 2008-10-22 | Method of using polyquaterniums in well treatments |
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA2641479A CA2641479C (en) | 2008-10-22 | 2008-10-22 | Method of using polyquaterniums in well treatments |
Related Child Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA2829901A Division CA2829901C (en) | 2008-10-22 | 2008-10-22 | Method of using polyquaterniums in well treatments |
Publications (2)
| Publication Number | Publication Date |
|---|---|
| CA2641479A1 CA2641479A1 (en) | 2010-04-22 |
| CA2641479C true CA2641479C (en) | 2014-12-09 |
Family
ID=42122675
Family Applications (2)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA2829901A Expired - Fee Related CA2829901C (en) | 2008-10-22 | 2008-10-22 | Method of using polyquaterniums in well treatments |
| CA2641479A Expired - Fee Related CA2641479C (en) | 2008-10-22 | 2008-10-22 | Method of using polyquaterniums in well treatments |
Family Applications Before (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA2829901A Expired - Fee Related CA2829901C (en) | 2008-10-22 | 2008-10-22 | Method of using polyquaterniums in well treatments |
Country Status (1)
| Country | Link |
|---|---|
| CA (2) | CA2829901C (en) |
Families Citing this family (3)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US8691734B2 (en) | 2008-01-28 | 2014-04-08 | Baker Hughes Incorporated | Method of fracturing with phenothiazine stabilizer |
| RU2013112855A (en) * | 2010-08-23 | 2014-09-27 | Флоукем, Лтд. | COMPOSITIONS REDUCING HYDRODYNAMIC RESISTANCE, AND METHODS FOR THEIR MANUFACTURE AND USE |
| WO2015168690A1 (en) | 2014-05-02 | 2015-11-05 | Baker Hughes Incorporated | Use of ultra lightweight particulates in multi-path gravel packing operations |
-
2008
- 2008-10-22 CA CA2829901A patent/CA2829901C/en not_active Expired - Fee Related
- 2008-10-22 CA CA2641479A patent/CA2641479C/en not_active Expired - Fee Related
Also Published As
| Publication number | Publication date |
|---|---|
| CA2829901C (en) | 2016-01-05 |
| CA2829901A1 (en) | 2010-04-22 |
| CA2641479A1 (en) | 2010-04-22 |
Similar Documents
| Publication | Publication Date | Title |
|---|---|---|
| US11001748B2 (en) | Method of preparing and using a drag-reducing additive having a dispersion polymer | |
| RU2307144C2 (en) | Non-harmful liquid for reducing absorption of drill mud and method for application thereof | |
| US9909403B2 (en) | Adjusting surfactant concentrations during hyraulic fracturing | |
| US7204311B2 (en) | Methods for controlling migration of particulates in a subterranean formation | |
| AU2005228173B2 (en) | Method for increasing the production of hydrocarbon liquids and gases | |
| AU2015374328B2 (en) | Emulsions containing alkyl ether sulfates and uses thereof | |
| CN113646381B (en) | Reverse emulsion for hydraulic fracturing | |
| EA017431B1 (en) | Provision of viscous compositions below ground | |
| AU2016429781B2 (en) | Nanoemulsions for use in subterranean fracturing treatments | |
| NO20180258A1 (en) | Ethoxylated amines for use in subterranean formations | |
| CA2641479C (en) | Method of using polyquaterniums in well treatments | |
| US20030083206A1 (en) | Oil and gas production optimization using dynamic surface tension reducers | |
| US11898086B2 (en) | Cationic and anionic shale inhibitors and clay stabilizers | |
| WO2017155524A1 (en) | Exothermic reactants for use in subterranean formation treatment fluids | |
| RU2816318C2 (en) | Reverse emulsion for hydraulic fracturing | |
| RU2698784C2 (en) | Thickener of an aqueous acid solution, a method of thickening an aqueous acid solution and an oil recovery method using said thickener, a set of components for thickening an aqueous acid solution and a composition for carrying out acidic hydraulic fracturing of the formation, including said thickener | |
| RU2778702C2 (en) | Polymer mixtures for production intensification in oil and gas wells |
Legal Events
| Date | Code | Title | Description |
|---|---|---|---|
| EEER | Examination request | ||
| MKLA | Lapsed |
Effective date: 20211022 |