WO2006106287A1 - Methods useful for controlling fluid loss in subterranean treatments - Google Patents
Methods useful for controlling fluid loss in subterranean treatments Download PDFInfo
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- WO2006106287A1 WO2006106287A1 PCT/GB2006/000839 GB2006000839W WO2006106287A1 WO 2006106287 A1 WO2006106287 A1 WO 2006106287A1 GB 2006000839 W GB2006000839 W GB 2006000839W WO 2006106287 A1 WO2006106287 A1 WO 2006106287A1
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- fluid loss
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- hydrophobically modified
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- 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
- C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
- C09K8/504—Compositions based on water or polar solvents
- C09K8/506—Compositions based on water or polar solvents containing organic compounds
- C09K8/508—Compositions based on water or polar solvents containing organic compounds macromolecular compounds
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- 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
- C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
- C09K8/504—Compositions based on water or polar solvents
- C09K8/506—Compositions based on water or polar solvents containing organic compounds
- C09K8/508—Compositions based on water or polar solvents containing organic compounds macromolecular compounds
- C09K8/5083—Compositions based on water or polar solvents containing organic compounds macromolecular compounds obtained by reactions only involving carbon-to-carbon unsaturated bonds
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- 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
- C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
- C09K8/504—Compositions based on water or polar solvents
- C09K8/506—Compositions based on water or polar solvents containing organic compounds
- C09K8/508—Compositions based on water or polar solvents containing organic compounds macromolecular compounds
- C09K8/5086—Compositions based on water or polar solvents containing organic compounds macromolecular compounds obtained otherwise than by reactions only involving carbon-to-carbon unsaturated bonds
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- 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
- C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
- C09K8/516—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls characterised by their form or by the form of their components, e.g. encapsulated material
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- 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
- C09K8/56—Compositions for consolidating loose sand or the like around wells without excessively decreasing the permeability thereof
- C09K8/57—Compositions based on water or polar solvents
- C09K8/575—Compositions based on water or polar solvents containing organic compounds
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- 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
Definitions
- the present invention relates to subterranean treatments and, more particularly, to using fluid loss control additives that comprise a water-soluble polymer with hydrophobic or hydrophilic modification.
- a problem often encountered during subterranean treatments is the undesired loss or leak off of fluid into the formation. This undesired loss or leak off is commonly referred to as "fluid loss.”
- Such treatments include, but are not limited to, drilling operations, cleanup operations, workover operations, completion operations, stimulation treatments (e.g., fracturing, acidizing), and sand control treatments (e.g., gravel packing).
- stimulation treatments e.g., fracturing, acidizing
- sand control treatments e.g., gravel packing
- fluid loss into the formation may result in a reduction in fluid efficiency, such that the fracturing fluid cannot propagate the fracture as desired.
- the term “treatment,” or “treating” refers to any subterranean treatment that uses a fluid in conjunction with a desired function and/or for a desired purpose.
- the term “treatment,” or “treating,” does not imply any particular action by the fluid or any particular component thereof.
- Fluid loss into the formation may result from a number of downhole conditions, such as high-formation permeability, overbalance pressures, perforated or open- hole intervals in the well bore, and large differential pressures associated with differential segregation in wells completed in a multilayer reservoir.
- the fluid loss may be into a low-pressure portion of the formation due to overbalance pressures, for example, where a well is completed in a multilayer reservoir.
- fluid loss control additives commonly may be included in the treatment fluids.
- fluid loss control additives include, but are not limited to, gelling agents, such as hydroxyethylcellulose and xanthan. Additional fluid loss control may be provided by crosslinking the gelling agent or by including fluid loss control materials, such as sized solids (e.g., calcium carbonate), silica particles, oil-soluble resins, and degradable particles, in the treatment fluids.
- the fluid loss control materials may be used in combination with or separately from the conventional fluid loss control additives. These conventional methods commonly work at the well bore and/or formation face and if they invade the reservoir, formation damage may occur. Additionally, the use of crosslinked fluids may impact fracture geometry, for example, creating wider, shorter fractures. Further, the crosslinked fluids may form a filter cake, which may be detrimental to the production of reservoir fluids.
- Chemical fluid loss control pills also may be used to combat fluid loss.
- Conventional chemical fluid loss control pills may be characterized as either solids-containing pills or solids-free pills.
- solids-containing pills include sized-salt pills and sized- carbonate pills.
- These solids-containing pills often are not optimized for the particular downhole hardware and conditions that may be encountered. For instance, the particle sizes of the solids may not be optimized for a particular application and, as a result, may increase the risk of invasion into the interior of the formation matrix, which may greatly increase the difficulty of removal by subsequent remedial treatments. Additionally, high-solids loading in the pills, in conjunction with the large volumes of these pills needed to control fluid losses, may greatly increase the complexity of subsequent cleanup.
- Solids-free fluid loss control pills commonly comprise hydrated polymer gels that may not be effective without some invasion into the formation matrix. These pills typically require large volumes to control fluid loss and remedial treatments to remove.
- remedial treatments may be required to remove the previously placed pills, inter alia, so that the wells may be placed into production.
- a chemical breaker such as an acid, oxidizer, or enzyme may be used to either dissolve the solids or reduce the viscosity of the pill.
- use of a chemical breaker to remove the pill from inside the well bore and/or the formation matrix may be either ineffective or not a viable economic option.
- the chemical breakers may be corrosive to downhole tools. Additionally, as the chemical breakers leak off into the formation, they may carry undissolved fines that may plug and/or damage the formation or may produce undesirable reactions with the formation.
- the present invention relates to subterranean treatments and, more particularly, to using fluid loss control additives that comprise a water-soluble polymer with hydrophobic or hydrophilic modification.
- An embodiment of the present invention provides a method of providing at least some degree of fluid loss control during a subterranean treatment.
- the method may comprise providing a treatment fluid comprising an aqueous liquid and a fluid loss control additive, the fluid loss control additive comprising a water-soluble polymer with hydrophobic or hydrophilic modification; and introducing the treatment fluid into a well bore that penetrates a subterranean formation, wherein there is at least a partial reduction in fluid loss into at least a portion of the subterranean formation from the treatment fluid and/or another aqueous fluid introduced into the well bore subsequent to the treatment fluid.
- Another embodiment of the present invention provides a method of providing at least some degree of fluid loss control during a fracturing treatment.
- the method may comprise providing a fracturing fluid comprising an aqueous liquid and a fluid loss control additive, the fluid loss control additive comprising a water-soluble polymer with hydrophobic or hydrophilic modification; and contacting a subterranean formation with the fracturing fluid at a pressure sufficient to create or enhance one or more fractures in the subterranean formation, wherein there is at least a partial reduction in fluid loss from the fracturing fluid into at least a portion of the subterranean formation.
- the method may comprise providing a treatment fluid comprising an aqueous liquid and a fluid loss control additive, the fluid loss control additive comprising a water-soluble hydrophobically modified polymer, wherein the hydrophobically modified polymer comprises an amino methacrylate/alkyl amino methacrylate copolymer; and introducing the treatment fluid into a well bore that penetrates a subterranean formation, wherein there is at least a partial reduction in fluid loss into at least a portion of the subterranean formation from the treatment fluid and/or another aqueous fluid introduced into well bore subsequent to the treatment fluid.
- Figure 1 is a plot of fluid loss volume per time for a dynamic fluid loss test performed using a round cell containing a H.P. Berea sandstone core and various sample fluids.
- Figure 2 is a plot of fluid loss volume per time for a dynamic fluid loss test performed using a round cell containing a L.P. Berea sandstone core and various sample fluids.
- Figure 3 is a plot of fluid loss volume per time for a dynamic fluid loss test performed using a round cell containing an Ohio sandstone core and various sample fluids.
- Figure 4 is a plot of fluid loss volume per time for a dynamic fluid loss test performed using a round cell containing a H.P. Berea sandstone core and various sample fluids.
- Figure 5 is a plot of fluid loss volume per time for a dynamic fluid loss test performed using a round cell containing a L.P. Berea sandstone core and various sample fluids.
- Figure 6 is a plot of fluid loss volume per time for a dynamic fluid loss test performed using a round cell containing an Ohio sandstone core and various sample fluids. While the present invention is susceptible to various modifications and alternative forms, specific exemplary embodiments thereof have been shown by way of example in the drawings and are herein described in detail. It should be understood, however, that the description herein of specific embodiments is not intended to limit or define the invention to the particular forms disclosed, but on the contrary, the intention is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the invention as defined by the appended claims. The figures should in no way be used to limit the meaning of the claim terms.
- the present invention relates to subterranean treatments and, more particularly, to using fluid loss control additives that comprise a water-soluble polymer with hydrophobic or hydrophilic modification.
- water-soluble refers to at least 0.01 weight percent soluble in distilled water.
- hydrophobically modified or “hydrophobic modification” refers to the incorporation into the hydrophilic polymer structure of hydrophobic groups, wherein the alkyl chain length is from about 4 to about 22 carbons.
- hydrophilically modified or “hydrophilic modification” refers to the incorporation into the hydrophilic polymer structure of hydrophilic groups, such as to introduce branching or to increase the degree of branching in the hydrophilic polymer.
- the methods and compositions of the present invention may be utilized in horizontal, vertical, inclined, or otherwise formed portions of wells.
- the treatment fluids of the present invention generally comprise an aqueous liquid and a fluid loss control additive that comprises a water-soluble polymer with hydrophobic or hydrophilic modification.
- a variety of additional additives suitable for use in the chosen treatment may be included in the treatment fluids as desired.
- the aqueous liquid of the treatment fluids of the present invention may include freshwater, saltwater, brine (e.g., saturated saltwater), or seawater.
- the aqueous liquid may be from any source, provided that it does not contain components that may adversely affect other components in the treatment fluid.
- the fluid loss control additives used in the treatment fluids of the present invention comprise a water-soluble polymer with hydrophobic or hydrophilic modification.
- a water-soluble polymer with hydrophobic modification is referred to as hydrophobically modified.
- a water-soluble polymer with hydrophilic modification is referred to as hydrophilically modified.
- the fluid loss control additives should reduce fluid loss from the treatment fluid or any other aqueous fluids subsequently introduced into the well bore.
- the water-soluble polymer should attach to surfaces within the porosity of the subterranean formation, thereby reducing the permeability of the subterranean formation to aqueous fluids without substantially changing its permeability to hydrocarbons.
- the hydrophobically modified polymers useful in the present invention typically have molecular weights in the range of from about 100,000 to about 10,000,000. While these hydrophobically modified polymers have hydrophobic groups incorporated into the hydrophilic polymer structure, they should remain water-soluble.
- a mole ratio of a hydrophilic monomer to the hydrophobic compound in the hydrophobically modified polymer is in the range of from about 99.98:0.02 to about .90:10, wherein the hydrophilic monomer is a calculated amount present in the hydrophilic polymer.
- the hydrophobically modified polymers may comprise a polymer backbone that comprises polar heteroatoms. Generally, the polar heteroatoms present within the polymer backbone of the hydrophobically modified polymers include, but are not limited to, oxygen, nitrogen, sulfur, or phosphorous.
- the hydrophobically modified polymers may be synthesized utilizing any suitable method.
- the hydrophobically modified polymers may be a reaction product of a hydrophilic polymer and a hydrophobic compound.
- the hydrophobically modified polymers may be prepared from a polymerization reaction comprising a hydrophilic monomer and a hydrophobically modified hydrophilic monomer.
- suitable hydrophobically modified polymers may be synthesized by the hydrophobic modification of a hydrophilic polymer.
- the hydrophilic polymers suitable for forming the hydrophobically modified polymers used in the present invention should be capable of reacting with hydrophobic compounds.
- Suitable hydrophilic polymers include, homo-, co-, or terpolymers such as, but not limited to, polyacrylamides, polyvinylamines, poly(vinylamines/vinyl alcohols), alkyl acrylate polymers in general, and derivatives thereof.
- alkyl acrylate polymers include, but are not limited to, polydimethylaminoethyl methacrylate, polydimethylaminopropyl methacrylamide, poly(acrylamide/dimethylaminoethyl methacrylate), poly(methacrylic acid/dimethylaminoethyl methacrylate), poly(2-acrylamido-2-methyl propane sulfonic acid/dimethylaminoethyl methacrylate), poly(acrylamide/dimethylaminopropyl methacrylamide), poly (acrylic acid/dimethylaminopropyl methacrylamide), and poly(methacrylic acid/dimethylaminopropyl methacrylamide).
- the hydrophilic polymers comprise a polymer backbone and reactive amino groups in the polymer backbone or as pendant groups, the reactive amino groups capable of reacting with hydrophobic compounds.
- the hydrophilic polymers comprise dialkyl amino pendant groups.
- the hydrophilic polymers comprise a dimethyl amino pendant group and a monomer comprising dimethylaminoethyl methacrylate or dimethylaminopropyl methacrylamide.
- the hydrophilic polymers comprise a polymer backbone that comprises polar heteroatoms, wherein the polar heteroatoms present within the polymer backbone of the hydrophilic polymers include, but are not limited to, oxygen, nitrogen, sulfur, or phosphorous.
- Suitable hydrophilic polymers that comprise polar heteroatoms within the polymer backbone include homo-, CO-, or terpolymers, such as, but not limited to, celluloses, chitosans, polyamides, polyetheramines, polyethyleneimines, polyhydroxyetheramines, polylysines, polysulfones, gums, starches, and derivatives thereof.
- the starch is a cationic starch.
- a suitable cationic starch may be formed by reacting a starch, such as corn, maize, waxy maize, potato, and tapioca, and the like, with the reaction product of epichlorohydrin and trialkylamine.
- the hydrophobic compounds that are capable of reacting with the hydrophilic polymers of the present invention include, but are not limited to, alkyl halides, sulfonates, sulfates, organic acids, and organic acid derivatives.
- suitable organic acids and derivatives thereof include, but are not limited to, octenyl succinic acid; dodecenyl succinic acid; and anhydrides, esters, imides, and amides of octenyl succinic acid or dodecenyl succinic acid.
- the hydrophobic compounds may have an alkyl chain length of from about 4 to about 22 carbons. In another embodiment, the hydrophobic compounds may have an alkyl chain length of from about 7 to about 22 carbons.
- the hydrophobic compounds may have an alkyl chain length of from about 12 to about 18 carbons.
- the reaction between the hydrophobic compound and hydrophilic polymer may result in the quaternization of at least some of the hydrophilic polymer amino groups with an alkyl halide, wherein the alkyl chain length is from about 4 to about 22 carbons.
- suitable hydrophobically modified polymers also may be prepared from a polymerization reaction comprising a hydrophilic monomer and a hydrophobically modified hydrophilic monomer. Examples of suitable methods of their preparation are described in U.S. Patent Number 6,476,169, the relevant disclosure of which is incorporated herein by reference.
- the hydrophobically modified polymers synthesized from the polymerization reactions may have estimated molecular weights in the range of from about 100,000 to about 10,000,000 and mole ratios of the hydrophilic monomer(s) to the hydrophobically modified hydrophilic monomer(s) in the range of from about 99.98:0.02 to about 90:10.
- hydrophilic monomers may be used to form the hydrophobically modified polymers useful in the present invention.
- suitable hydrophilic monomers include, but are not limited to acrylamide, 2-acrylamido-2-methyl propane sulfonic acid, N,N-dimethylacrylamide, vinyl pyrrolidone, dimethylaminoethyl methacrylate, acrylic acid, dimethylaminopropylmethacrylamide, vinyl amine, vinyl acetate, trimethylammoniumethyl methacrylate chloride, methacrylamide, hydroxyethyl acrylate, vinyl sulfonic acid, vinyl phosphonic acid, methacrylic acid, vinyl caprolactam, N-vinylformamide, N,N-diallylacetamide, dimethyldiallyl ammonium halide, itaconic acid, styrene sulfonic acid, methacrylamidoethyltrimethyl ammonium halide, quaternary salt derivatives of acrylamide, and
- hydrophobically modified hydrophilic monomers also may be used to form the hydrophobically modified polymers useful in the present invention.
- suitable hydrophobically modified hydrophilic monomers include, but are not limited to, alkyl acrylates, alkyl methacrylates, alkyl acrylamides, alkyl methacrylamides alkyl dimethylammoniumethyl methacrylate halides, and alkyl dimethylammoniumpropyl methacrylamide halides, wherein the alkyl groups have from about 4 to about 22 carbon atoms. In another embodiment, the alkyl groups have from about 7 to about 22 carbons. In another embodiment, the alkyl groups have from about 12 to about 18 carbons.
- the hydrophobically modified hydrophilic monomer comprises octadecyldimethylammoniumethyl methacrylate bromide, hexadecyldimethylammoniumethyl methacrylate bromide, hexadecyldimethylammoniumpropyl methacrylamide bromide, 2- ethylhexyl methacrylate, or hexadecyl methacrylamide.
- Suitable hydrophobically modified polymers that may be formed from the above-described reactions include, but are not limited to, acrylamide/octadecyldimethylammoniumethyl methacrylate bromide copolymer, dimethylaminoethyl methacrylate/vinyl pyrrolidone/hexadecyldimethylammoniumethyl methacrylate bromide terpolymer, and acrylamide/2-acrylamido-2-methyl propane sulfonic acid/2-ethylhexyl methacrylate terpolymer.
- Another suitable hydrophobically modified polymer formed from the above-described reaction comprises an amino methacrylate/alkyl amino methacrylate copolymer.
- a suitable dimethlyaminoethyl methacrylate/alkyl- dimethylammoniumethyl methacrylate copolymer is a dimethylaminoethyl methacrylate/hexadecyl-dimethylammoniumethyl methacrylate copolymer.
- these copolymers may be formed by reactions with a variety of alkyl halides.
- the hydrophobically modified polymer may comprise a dimethylaminoethyl methacrylate/hexadecyl-dimethylammoniumethyl methacrylate bromide copolymer.
- the fluid loss control additives of the present invention may comprise a water-soluble hydrophilically modified polymer.
- the hydrophilically modified polymers of the present invention typically have molecular weights in the range of from about 100,000 to about 10,000,000.
- the hydrophilically modified polymers comprise a polymer backbone that comprises polar heteroatoms.
- the polar heteroatoms present within the polymer backbone of the hydrophilically modified polymers include, but are not limited to, oxygen, nitrogen, sulfur, or phosphorous.
- the hydrophilically modified polymers may be synthesized utilizing any suitable method.
- the hydrophilically modified polymers may be a reaction product of a hydrophilic polymer and a hydrophilic compound.
- Those of ordinary skill in the art, with the benefit of this disclosure, will be able to determine other suitable methods for the preparation of suitable hydrophilically modified polymers.
- suitable hydrophilically modified polymers may be formed by additional hydrophilic modification, for example, to introduce branching or to increase the degree of branching, of a hydrophilic polymer.
- the hydrophilic polymers suitable for forming the hydrophilically modified polymers used in the present invention should be capable of reacting with hydrophilic compounds.
- suitable hydrophilic polymers include, homo-, co-, or terpolymers, such as, but not limited to, polyacrylamides, polyvinylamines, poly(vinylamines/vinyl alcohols), and alkyl acrylate polymers in general.
- alkyl acrylate polymers include, but are not limited to, polydimethylaminoethyl methacrylate, polydimethylaminopropyl methacrylamide, poly(acrylamide/dimethylaminoethyl methacrylate), poly(methacrylic acid/dimethylaminoethyl methacrylate), poly(2-acrylamido-2-methyl propane sulfonic acid/dimethylaminoethyl methacrylate), poly(acrylamide/dimethylaminopropyl methacrylamide), poly (acrylic acid/dimethylaminopropyl methacrylamide), and poly(methacrylic acid/dimethylaminopropyl methacrylamide).
- the hydrophilic polymers comprise a polymer backbone and reactive amino groups in the polymer backbone or as pendant groups, the reactive amino groups capable of reacting with hydrophilic compounds.
- the hydrophilic polymers comprise dialkyl amino pendant groups.
- the hydrophilic polymers comprise a dimethyl amino pendant group and at least one monomer comprising dimethylaminoethyl methacrylate or dimethylaminopropyl methacrylamide.
- the hydrophilic polymers comprise a polymer backbone that comprises polar heteroatoms, wherein the polar heteroatoms present within the polymer backbone of the hydrophilic polymers include, but are not limited to, oxygen, nitrogen, sulfur, or phosphorous.
- Suitable hydrophilic polymers that comprise polar heteroatoms within the polymer backbone include homo-, co-, or terpolymers, such as, but not limited to, celluloses, chitosans, polyamides, polyetheramines, polyethyleneimines, polyhydroxyetheramines, polylysines, polysulfones, gums, starches, and derivatives thereof.
- the starch is a cationic starch.
- a suitable cationic starch may be formed by reacting a starch, such as corn, maize, waxy maize, potato, tapioca, and the like, with the reaction product of epichlorohydrin and trialkylamine.
- the hydrophilic compounds suitable for reaction with the hydrophilic polymers include polyethers that comprise halogens, sulfonates, sulfates, organic acids, and organic acid derivatives.
- suitable polyethers include, but are not limited to, polyethylene oxides, polypropylene oxides, and polybutylene oxides, and copolymers, terpolymers, and mixtures thereof.
- the polyether comprises an epichlorohydrin-terminated polyethylene oxide methyl ether.
- hydrophilically modified polymers formed from the reaction of a hydrophilic polymer with a hydrophilic compound may have estimated molecular weights in the range of from about 100,000 to about 10,000,000 and may have weight ratios of the hydrophilic polymers to the polyethers in the range of from about 1:1 to about 10:1.
- Suitable hydrophilically modified polymers having molecular weights and weight ratios in the ranges set forth above include, but are not limited to, the reaction product of polydimethylaminoethyl methacrylate and epichlorohydrin-terminated polyethyleneoxide methyl ether; the reaction product of polydimethylaminopropyl methacrylamide and epichlorohydrin-terminated polyethyleneoxide methyl ether; and the reaction product of poly(acrylamide/dimethylaminopropyl methacrylamide) and epichlorohydrin-terminated polyethyleneoxide methyl ether.
- the hydrophilically modified polymer comprises the reaction product of a polydimethylaminoethyl methacrylate and epichlorohydrin-terminated polyethyleneoxide methyl ether having a weight ratio of polydimethylaminoethyl methacrylate to epichlorohydrin-terminated polyethyleneoxide methyl ether of about 3:1.
- the fluid loss control additives of the present invention should be present in the treatment fluids of the present invention to provide the desired level of fluid loss control.
- the fluid loss control additives should be present in the treatment fluids of the present invention in an amount in the range of from about 0.02% to about 10% by weight of the treatment fluid.
- the fluid loss control additive should be present in the treatment fluids of the present invention in an amount in the range of from about 0.05% to about 1.0% by weight of the treatment fluid.
- the fluid loss control additive may be provided in a concentrated aqueous solution prior to its combination with the other components necessary to form the treatment fluids of the present invention.
- Additional additives may be added to the treatment fluids of the present invention as deemed appropriate for a particular application by one skilled in the art with the benefit of this disclosure.
- additives include, but are not limited to, weighting agents, surfactants, scale inhibitors, antifoaming agents, bactericides, salts, foaming agents, acids, conventional fluid loss control additives, viscosifying agents, crosslinking agents, gel breakers, shale swelling inhibitors, combinations thereof, and the like.
- the treatment fluids of the present invention may be used in subterranean treatments where it is desirable to provide fluid loss control.
- the fluid loss control additives may be used at any stage of a subterranean treatment.
- the treatment fluid may be a drilling fluid, a fracturing fluid, a workover fluid, a well bore cleanup fluid, a gravel packing fluid, or any other suitable aqueous fluid used in subterranean treatments.
- the treatment fluids may be a fluid loss control pill that is introduced into the well bore at any stage of the subterranean treatment.
- the treatment fluid may be a preflush that is introduced into the well bore prior to the subterranean treatment.
- the methods of the present invention comprise introducing a treatment fluid of the present invention that comprises an aqueous fluid and a fluid loss control additive that comprises a water-soluble polymer with hydrophobic or hydrophilic modification into a well bore that penetrates a subterranean formation so as to reduce fluid loss into at least a portion of the subterranean formation from the treatment fluid or another aqueous fluid introduced into the well bore subsequent to the treatment fluid.
- a treatment fluid should penetrate into the porosity of at least a portion of the subterranean formation at least some depth from the treated surface during normal leak off from the treatment fluid.
- the water-soluble polymer present in the portion of the treatment fluid that leaked off into the formation should attach to surfaces within the porosity of the portion of the subterranean formation.
- the presence of the water-soluble polymers therein should reduce the permeability of treated portion of the subterranean formation to aqueous fluids without substantially changing the permeability thereof to hydrocarbons. This should reduce fluid loss into the treated portion from the treatment fluid and/or any other aqueous fluids (e.g., workover fluids, cleanup fluids, fracturing fluids, gravel packing fluids, drilling fluids, etc.) subsequently introduced into the well bore.
- the water-soluble polymers also may reduce subsequent problems associated with water flowing into the well bore from the treated portion of the subterranean formation. Among other things, subsequent remedial treatments should not be required to remove the water- soluble polymers prior to placing the well into production.
- a fluid loss control additive useful in the present invention was prepared by mixing 47.7 grams (“g") of deionized water, 0.38 g of (n-hexadecyl) dimethylammonium ethyl methacrylate bromide, and 1.1 g of acrylamide, and sparging with nitrogen for approximately 30 minutes. Thereafter, a polymerization initiator, such as 0.0127 g of 2,2'-azo bis (2-amidinopropane) dihydrochloride was added. The resulting solution was then heated, with stirring, to 110° F and held for 18 hours to produce a highly viscous polymer solution.
- a polymerization initiator such as 0.0127 g of 2,2'-azo bis (2-amidinopropane) dihydrochloride was added.
- the resulting solution was then heated, with stirring, to 110° F and held for 18 hours to produce a highly viscous polymer solution.
- a fluid loss control additive useful in the present invention was prepared by mixing 41.2 g of deionized water, 0.06 g of octadecyl methacrylate, 0.45 g of cocoamidopropyl betaine surfactant, and 1.26 g of acrylamide. Thereafter, a polymerization initiator, such as 0.0127 g of 2,2'-azo bis(2-amidinopropane) dihydrochloride was added. The resulting solution was then heated, with stirring, to 110° F and held for 18 hours to produce a highly viscous polymer solution.
- a polymerization initiator such as 0.0127 g of 2,2'-azo bis(2-amidinopropane) dihydrochloride
- a fluid loss control additive useful in the present invention was prepared as follows. First, a polymer was prepared by mixing 1,968 g of deionized water, 105 g of dimethylaminoethyl methacrylate and sparging with nitrogen for 30 minutes. Thereafter, the pH was adjusted to approximately 7.9 with sulfuric acid and a polymerization initiator, such as 0.46 g of 2,2'-azo bis(2-amidinopropane) dihydrochloride was added. The resulting solution was then heated, with stirring, to 110° F and held for 18 hours to produce poly(dimethylaminoethyl methacrylate).
- a polymer was prepared by mixing 1,968 g of deionized water, 105 g of dimethylaminoethyl methacrylate and sparging with nitrogen for 30 minutes. Thereafter, the pH was adjusted to approximately 7.9 with sulfuric acid and a polymerization initiator, such as 0.46 g of 2,2'-azo bis(2-amidinopropane) dihydr
- the poly(dimethylaminoethyl methacrylate) was then hydrophobically modified by adding 71.0 g of it to a 250 ml round flask, followed by 15% NaOH to achieve a pH of approximately 8.9.
- 54.6 g of water, 0.36 g of C16 alkyl (n-hexadecyl) bromide, and 0.39 g of benzylcetyldimethylammonium bromide surfactant were added to quaternize the poly(dimethylaminoethyl methacrylate) homopolymer and form a dimethylaminoethyl methacrylate/hexadecyl-dimethyiammoniumethyl methacrylate copolymer.
- This mixture was then heated, with stirring, to 140° F and held for 24 hours to produce a highly viscous polymer solution.
- Fluid loss control tests were performed using a hollow Berea sandstone core with the following dimensions: 2.75-inch length, 2.5-inch outer diameter, 1-inch inner diameter.
- the Berea sandstone core was mounted in a cell in which fluids can be pumped through the core in two directions. In one direction, defined as the "production direction," fluid is flowed from the exterior of the core, through the core, and into the hollow interior. Fluid also may be flowed in the direction opposite the production direction so that fluid is flowed from the hollow interior of the core, through the core, and to the exterior of the core. Fluid flowing opposite the production direction represents fluid loss from a well bore into the formation. Two treatment solutions were prepared for this series of tests.
- Test No. 1 The sample treatment fluid used in Test No. 1 (comparative) was a brine containing 21% potassium chloride by weight. Test No. 1 was performed at room temperature.
- the sample treatment fluid used in Tests No. 2 was prepared by adding 0.2% of a fluid loss control additive by weight to a brine containing 21% potassium chloride by weight. Accordingly, the sample treatment fluid used in Test No. 2 comprised 21% of potassium chloride by weight and 0.2% of a fluid loss control additive by weight.
- the fluid loss control additive was a dimethylaminoethyl methacrylate/hexadecyl- dimethylammoniumethyl methacrylate copolymer prepared as described in Example 3. Test No. 2 was performed at room temperature.
- the following procedure was used for this series of tests.
- the core experienced a flow sequence of 1) brine, 2) oil (kerosene), 3) drilling mud (to build a filter cake), 4) sample treatment fluid, 5) oil (kerosene).
- the first flow step brine, was in the production direction and prepared the core for the test.
- the brine used in the first flow step was a brine containing 7% potassium chloride by weight.
- the second flow step the kerosene was flowed in the production direction at a constant rate until the pressure stabilized, and the initial permeability of the core was calculated.
- a sample drilling mud was placed in the hollow interior of the core and pressure was applied, such that a drilling fluid filter cake was formed on the inner surface of the core.
- the sample treatment fluid was placed in the inner hole, and a constant pressure of 120 psi was applied. The filtrate loss from the sample treatment fluid was then measured as a function of time.
- kerosene was flowed in the production direction at the same rate and the final permeability of the core was calculated. For each series of tests, the initial and final permeability of the core to kerosene was essentially unchanged. Table 1 contains the data for this series of tests.
- this example indicates that the above-described fluid loss control additives that comprise hydrophobically modified polymers may be useful for controlling fluid loss from a well bore into a subterranean formation.
- Permeability reduction tests were performed using two treatment solutions and a multipressure tap Hassler sleeve containing a Brown sandstone core.
- the Hassler sleeve contained three pressure taps, as well as an inlet and an outlet for determining pressure, thereby dividing the core into four segments.
- Test No. 3 was performed at 15O 0 F 5 and Test No. 4 was performed at 175 0 F.
- the sample treatment fluid used in Test No. 3 was prepared by adding 0.6% of a fluid loss control additive by weight to a 2% by weight potassium chloride ("KCI") brine.
- KCI potassium chloride
- the sample treatment fluid used in Test No. 3 comprised 2% of KCI by weight and 0.6% of a fluid loss control additive by weight.
- the fluid loss control additive was a dimethylaminoethyl methacrylate/hexadecyl-dimethylammoniumethyl methacrylate copolymer prepared as described in Example 3.
- the sample treatment fluid used in Test No. 4 was prepared by adding 0.2% of a fluid loss control additive by weight to a 2% by weight KCI brine.
- the sample treatment fluid used in Test No. 4 comprised 2% of KCI by weight and 0.2% of a fluid loss control additive by weight.
- the fluid loss control additive was a dimethylaminoethyl methacrylate/hexadecyl-dimethylammoniumethyl methacrylate copolymer prepared as described in Example 3.
- the following procedure was used for this series of tests.
- the core experienced a flow sequence of 1) brine, 2) oil (kerosene), 3) brine, 4) sample treatment fluid, 5) brine.
- the brine used in flow steps 1, 3, and 5 was a brine containing 7% potassium chloride by weight.
- the first two flow steps of brine and oil prepared the core for the test.
- the brine flow in step 3 was maintained until the pressure stabilized, yielding an initial permeability for the core, listed in Tables 2 and 3 below as "Initial Core Permeability.”
- 15 ml of the sample treatment fluid were flowed into the core.
- the multipressure tap Hassler Sleeve divided the core into four segments. For the above-described tests, flow steps 1, 2, 3, and 5 were from segment 1 to segment 4, and flow step 4 was from segment 4 to segment 1.
- the results of Test No. 3 utilizing a polymer concentration of 6,000 ppm are provided in Table No. 2 below.
- Test No. 4 utilizing a polymer concentration of 2,000 ppm are provided in Table No. 3 below.
- Example 5 indicates that the fluid loss control additives useful in the present invention that comprise hydrophobically modified polymers may be useful for controlling fluid loss from a well bore into a subterranean formation.
- Hassler sleeve containing a Brown sandstone core.
- the Hassler sleeve contained three pressure taps, as well as an inlet and an outlet for determining pressure), thereby dividing the core into four segments.
- the sample treatment fluid used in Test No. 5 was prepared by adding 0.2% of a fluid loss control additive by weight to a 2% by weight KCI brine.
- the sample treatment fluid used in Test No. 4 comprised 2% of KCI by weight and 0.2% of a fluid loss control additive by weight.
- the fluid loss control additive was a dimethylaminoethyl methacrylate/hexadecyl-dimethylammoniumethyl methacrylate copolymer prepared as described in Example 3.
- Test No. 5 was performed at 15O 0 F.
- the following procedure was used for this series of tests.
- the core experienced a flow sequence of 1) brine, 2) oil (kerosene), 3) sample treatment fluid, 4) oil (kerosene).
- the first flow step of brine prepared the core for the test.
- the brine used in flow step 1 was a brine containing 7% KCl by weight.
- the oil flow in step 2 was maintained until the pressure stabilized, yielding an initial permeability for the core, listed in Tables 2 and 3 below as "Initial Core Permeability.”
- the sample treatment fluid was flowed into the core.
- the multipressure tap Hassler Sleeve divided the core into four segments.
- flow steps Nos. 1, 2, and 4 were from segment 1 to segment 4
- flow step No. 3 was from segment 4 to segment 1.
- the results of Test No. 5 utilizing a polymer concentration of 2,000 ppm are provided in Table No. 4 below.
- this example indicates that the above-described fluid loss control additives that comprise hydrophobically modified polymers may be useful for controlling fluid loss from a well bore into a subterranean formation.
- a fluid loss control additive useful in the present invention was prepared as follows. First, a polymer was prepared by mixing 45.0 g of dimethylaminoethyl methacrylate, 6.8 g acrylic acid, 372.0 g of water and sparging with nitrogen for 30 minutes. Thereafter, the pH was adjusted to approximately 5.3 with 5.7 mL of concentrated sulfuric acid, followed by the addition of 0.2 mL of 2-mercaptoethanol and 1.3 g of 2,2'-azo bis (2-amidinopropane) dihydrochloride. The resulting solution was then heated to 71° C, with stirring, and held for 18 hours to produce poly(dimethylaminoethyl methacrylate/acrylic acid).
- the ⁇ oly(dimethylaminoethyl methacrylate/acrylic acid) was then hydrophilically modified by adding 95.0 g of the polymer to a 250 mL roundbottom flask, followed by the addition of 5.7 g of a 65% solution of an epichlorohydrin-terminated polyethylene oxide methyl ether and 8.0 g of sodium chloride. Approximately 17 mL of 3% active sodium hydroxide solution was then added to reach a pH of approximately 8.2. The mixture was then heated, with stirring, to 71° C.
- the viscosity of the solution was monitored, and when the viscosity reached 2000 centipoise (as measured with a Brookf ⁇ eld LVT viscometer, #2 spindle at 12 rpm, 25° C) the reaction was terminated by removing the heat source and adding 5 mL of 17% hydrochloric acid, 2.0 g sodium chloride and 14.7 g water.
- Dynamic fluid loss control tests were performed using four sample fluids and a round cell containing a formation core sample.
- High Pressure (“HP") Berea Sandstone, Low Pressure (“LP”) Berea Sandstone, and Ohio Sandstone core samples were used for this series of tests.
- the formation core samples were cut for a round core holder and placed into the core holder.
- the round core holder used a 1.5-inch diameter core. There was a 0.16-inch gap to allow fluid flow through the cell and across the core face for the dynamic test conditions.
- the round cells were heated to 14O 0 F.
- the sample fluid was pumped through 340 feet of 0.194-inch LD. tubing to provide preconditioning and shear history for the fluid.
- the shear rate was approximately 440 sec "1 at a pump rate of 0.31 1/min.
- the sample fluid was pumped into a 0.402-inch LD. tubing section (110 feet) that was immersed in a heating bath. This simulated the lower shear rate of fluid flow in a fracture.
- the shear rate was about 50 sec '1 .
- the sample fluid was heated to 140 0 F as it flowed through this tubing section. After exiting this tubing section, the sample fluid was forced through the heated round cells where the dynamic fluid loss occurred.
- the gap for fluid flow in the round cell created the same shear rate (50 sec "1 ) as in the previous tubing section.
- a 1,000-psi pressure differential drives fluid loss through the formation core sample.
- the fluid loss test was continued for the desired length of time while fluid loss volumes were collected.
- Sample Fluid No. 1 (comparative) was a WaterFracTM 25 fluid system having a gelling agent concentration of 25 pounds per thousand gallons (lbs/mgal).
- WaterFracTM 25 is a fluid system that is commercially available from Halliburton Energy Services, Inc., Duncan, Oklahoma.
- Sample Fluid No. 1 was prepared by adding 25 lbs/mgal of WG-22TM gelling agent to a base fluid.
- WG-22TM is a guar-based gelling agent that is commercially available from Halliburton Energy Services, Inc., Duncan, Oklahoma.
- the base fluid was water that contained 2% KCl by weight.
- Sample Fluid No. 1 had a pH of 8.01. The viscosity of Sample Fluid No. 1 was found to be 17 cP at 74.1°F on a Farm® Model 35 Viscometer 1/5 spring at 300 rpm.
- Sample Fluid No. 2 was prepared by adding 67 gallons per thousand gallons (gal/mgal) of a fluid loss control additive to the WaterFracTM 25 fluid system of Sample Fluid No. 1.
- the fluid loss control additive was a dimethylaminoethyl methacrylate/hexadecyl- dimethylammoniumethyl methacrylate copolymer prepared as described in Example 3.
- the sample was buffered to a pH of 6.09 using BA-20TM buffering agent, which is commercially available from Halliburton Energy Services, Inc., Duncan, Oklahoma.
- the viscosity of Sample Fluid No. 2 was found to be 19.7 cP at 74.1 0 F on a Fann® Model 35 Viscometer 1/5 spring at 300 rpm.
- Sample Fluid No. 3 (comparative) was a Delta Frac® 140 25 fluid system having a gelling agent concentration of 25 lbs/mgal.
- Delta Frac® 140 25 is a fluid system that is commercially available from Halliburton Energy Services, Inc., Duncan, Oklahoma.
- Sample No. 2 was prepared by adding 25 lbs/mgal of WG-22TM gelling agent to a base fluid.
- WG-22TM is a guar-based gelling agent that is commercially available from Halliburton Energy Services, Inc., Duncan, Oklahoma.
- the base fluid was water that contained 2% KCl by weight.
- the base gel had a pH of 7.72.
- the viscosity of the base gel was found to be 16.1 cP at 72.3 0 F on a Fann® Model 35 Viscometer 1/5 spring at 300 rpm.
- 2 gals/mgal of BC-2 crosslinking agent was added to the base gel.
- BC-2 is a borate crosslinking agent that is commercially available from Halliburton Energy Services, Inc., Duncan, Oklahoma.
- 0.0017 gals/mgal of N-Zyme 3TM breaking agent was added to the base gel.
- N-Zyme 3TM is a breaking agent that is commercially available from Halliburton Energy Services, Inc., Duncan, Oklahoma.
- the gelled and crosslmked Sample Fluid No. 3 had a pH of 8.55.
- Sample Fluid No. 4 was prepared by adding 67 gal/mgal of a fluid loss control additive to the Delta Frac® 140 25 fluid system of Sample Fluid No. 3.
- the fluid loss control additive was a dimethylaminoethyl methacrylate/hexadecyl-dimethylammoniumethyl methacrylate copolymer prepared as described in Example 3.
- Sample Fluid No. 4 had a pH of 8.54.
- the viscosity of Sample Fluid No. 4 was found to be 16.2 cP at 74.1°F on a Fann® Model 35 Viscometer 1/5 spring at 300 rpm.
- this Example illustrates that the fluid loss control additives useful in the present invention may be suitable for providing dynamic fluid loss control in a variety of formation rock types and fluid systems.
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CN108753267A (en) * | 2018-05-25 | 2018-11-06 | 成都理工大学 | Drilling fluid and completion fluid anti-superhigh temperature anionic polymer fluid loss additive and preparation method thereof |
CN108753267B (en) * | 2018-05-25 | 2020-08-07 | 成都理工大学 | Superhigh temperature resistant anionic polymer fluid loss additive for drilling fluid and completion fluid and preparation method thereof |
Also Published As
Publication number | Publication date |
---|---|
AU2006231096A1 (en) | 2006-10-12 |
US20050199396A1 (en) | 2005-09-15 |
AR054244A1 (en) | 2007-06-13 |
AU2006231096B2 (en) | 2011-11-17 |
US8631869B2 (en) | 2014-01-21 |
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