WO2009010932A2 - Distribution de polymère dans des applications de traitement de puits - Google Patents

Distribution de polymère dans des applications de traitement de puits Download PDF

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Publication number
WO2009010932A2
WO2009010932A2 PCT/IB2008/052866 IB2008052866W WO2009010932A2 WO 2009010932 A2 WO2009010932 A2 WO 2009010932A2 IB 2008052866 W IB2008052866 W IB 2008052866W WO 2009010932 A2 WO2009010932 A2 WO 2009010932A2
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WO
WIPO (PCT)
Prior art keywords
water
polymer
guar
stream
water emulsion
Prior art date
Application number
PCT/IB2008/052866
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English (en)
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WO2009010932A3 (fr
Inventor
Philip F. Sullivan
Gary John Tustin
Yenny Christanti
Gregory Kubala
Bruno Drochon
Yiyan Chen
Marie Noelle Dessinges
Paul R. Howard
Original Assignee
Schlumberger Canada Limited
Services Petroliers Schlumberger
Schlumberger Holdings Limited
Schlumberger Technology B.V.
Prad Research And Development Limited
Priority date (The priority date 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 date listed.)
Filing date
Publication date
Priority claimed from US12/166,804 external-priority patent/US9574128B2/en
Application filed by Schlumberger Canada Limited, Services Petroliers Schlumberger, Schlumberger Holdings Limited, Schlumberger Technology B.V., Prad Research And Development Limited filed Critical Schlumberger Canada Limited
Priority to CA2693246A priority Critical patent/CA2693246A1/fr
Priority to EA201070153A priority patent/EA020002B1/ru
Publication of WO2009010932A2 publication Critical patent/WO2009010932A2/fr
Publication of WO2009010932A3 publication Critical patent/WO2009010932A3/fr

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
    • E21B21/06—Arrangements for treating drilling fluids outside the borehole
    • E21B21/062—Arrangements for treating drilling fluids outside the borehole by mixing components
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01F—MIXING, e.g. DISSOLVING, EMULSIFYING OR DISPERSING
    • B01F23/00—Mixing according to the phases to be mixed, e.g. dispersing or emulsifying
    • B01F23/50—Mixing liquids with solids
    • B01F23/54—Mixing liquids with solids wetting solids
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01F—MIXING, e.g. DISSOLVING, EMULSIFYING OR DISPERSING
    • B01F23/00—Mixing according to the phases to be mixed, e.g. dispersing or emulsifying
    • B01F23/50—Mixing liquids with solids
    • B01F23/59—Mixing systems, i.e. flow charts or diagrams
    • 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
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/62—Compositions for forming crevices or fractures
    • C09K8/66—Compositions based on water or polar solvents
    • C09K8/68—Compositions based on water or polar solvents containing organic compounds
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/84—Compositions based on water or polar solvents
    • C09K8/86—Compositions based on water or polar solvents containing organic compounds
    • C09K8/88—Compositions based on water or polar solvents containing organic compounds macromolecular compounds
    • C09K8/90—Compositions based on water or polar solvents containing organic compounds macromolecular compounds of natural origin, e.g. polysaccharides, cellulose
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01F—MIXING, e.g. DISSOLVING, EMULSIFYING OR DISPERSING
    • B01F2101/00—Mixing characterised by the nature of the mixed materials or by the application field
    • B01F2101/49—Mixing drilled material or ingredients for well-drilling, earth-drilling or deep-drilling compositions with liquids to obtain slurries
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01F—MIXING, e.g. DISSOLVING, EMULSIFYING OR DISPERSING
    • B01F23/00—Mixing according to the phases to be mixed, e.g. dispersing or emulsifying
    • B01F23/40—Mixing liquids with liquids; Emulsifying
    • B01F23/41—Emulsifying
    • B01F23/414—Emulsifying characterised by the internal structure of the emulsion
    • B01F23/4146—Emulsions including solid particles, e.g. as solution or dispersion, i.e. molten material or material dissolved in a solvent or dispersed in a liquid
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01F—MIXING, e.g. DISSOLVING, EMULSIFYING OR DISPERSING
    • B01F33/00—Other mixers; Mixing plants; Combinations of mixers
    • B01F33/80—Mixing plants; Combinations of mixers
    • B01F33/83—Mixing plants specially adapted for mixing in combination with disintegrating operations
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K2208/00—Aspects relating to compositions of drilling or well treatment fluids
    • C09K2208/28—Friction or drag reducing additives

Definitions

  • This invention relates to methods for and fluids used in treating a subterranean formation.
  • the invention relates to the preparation and use of polymer delivery systems in the form of concentrated polymer suspensions useful for creating wellbore fluids and in methods of treating subterranean formations.
  • Various types of fluids are used in operations related to the development and completion of wells that penetrate subterranean formations, and to the production of gaseous and liquid hydrocarbons from natural reservoirs into such wells. These operations include perforating subterranean formations, fracturing subterranean formations, modifying the permeability of subterranean formations, or controlling the production of sand or water from subterranean formations.
  • the fluids employed in these oilfield operations are known as drilling fluids, completion fluids, work-over fluids, packer fluids, fracturing fluids, stimulation fluids, conformance or permeability control fluids, consolidation fluids, and the like, and are collectively referred to herein as well treatment fluids.
  • Water-soluble polymers are frequently used for modifying the rheology, e.g. viscosification, proppant suspension, friction reduction, etc., in a number of subterranean formation treatment fluids, including fracturing fluids, wellbore cleanout fluids, gravel pack fluids, and the like. Creating these fluids often involves the steps of dispersing and hydrating polymers, such as guar, cellulose, and derivatives thereof, into a water stream. Hydration of polymers for oilfield applications is generally a slow process. The process normally involves at least a few minutes of agitating the polymer, either a hydrocarbon slurry or dry polymer, with water in a flow path that contains different compartments.
  • Guar powders are generally obtained through a grinding process.
  • the guar particles generally have a twisted, plate-like structure that can be observed under a microscope. Upon contact with water, the twisted structures quickly unwind into layered structures that are more flat.
  • a successful technique for gelling an aqueous fluid must meet several criteria, including but not limited to allowing accurate metering of polymer material into a water stream, producing hydrated polymer fluids with a minimum amount of equipment, while also avoiding the formation of fish-eyes when polymer particles contact water.
  • Non-aqueous slurries comprise dry polymer suspended in an oil solvent, often diesel fuel which presents some difficulties.
  • oil solvent often diesel fuel which presents some difficulties.
  • service companies have also developed dry systems in which dry polymer is directly mixed with water, but such systems can present another set of difficulties known to those of skill in the art.
  • Some examples of complicated polymer hydration equipment are disclosed in US5190374, US5382411, US5426137 and US 2004/0256106.
  • Friction reducers are available commercially in oil or oil-and-water emulsions. To reduce turbulent flow in the slickwater fluid, the friction reducer must "flip" from the emulsion to rapidly dissolve in the water, usually within several seconds, or else the full drag reduction will not be achieved during transit through the wellbore.
  • Such two-phase systems are variously referred to in the literature as water-in-water emulsions, biphasic systems, aqueous two phase systems (ATPS) or the like. Although they may be referred to as emulsions they do not necessarily contain either oil or surfactant.
  • Some embodiments of the present invention are based in part on the discovery that water-in-water or other solvent-in-solvent emulsions can be used to deliver polymers, especially rheology modifying polymers, to dense brines and other well treatment fluids.
  • the dispersed phase comprises small polymer solution droplets or water-wet polymer particles
  • the emulsions behave Theologically much like a slurry of hard particles in the continuous phase.
  • the apparent viscosity of the emulsion is influenced primarily by the rheology of the continuous phase, and not much at all by the viscosity of the dispersed phase.
  • water-in-water emulsion as used herein is used to encompass mixtures comprising normally water-soluble polymers in the dispersed phase regardless of whether the dispersed phase is a liquid droplet of low or high viscosity polymer solution, or a paste- like or water wet polymer globule containing solid polymer particles, i.e. the water-in-water emulsion is applicable to both liquid-liquid mixtures and liquid-solid slurries comprising water-soluble polymers.
  • the present invention uses a partitioning agent that severely limits the solubility of a rheological agent, such as a polymer.
  • a rheological agent such as a polymer.
  • the mixture forms a water-in-water emulsion where a concentrated rheological agent is concentrated in the dispersed phase, as a viscous aqueous solution or as water-wet, hydrated, or partially hydrated particles, and the partitioning agent is concentrated in the continuous phase.
  • a rheological agent such as a polymer.
  • the water-in-water emulsion of concentrated guar in embodiments of the present invention has a relatively low viscosity and is very easily pumped, but when diluted with water at the wellsite, the binodal point is crossed and a continuous aqueous polymer phase forms to readily viscosify the fluid.
  • the concentrated guar embodiment thus has a low viscosity convenient for transport to the wellsite and/or preparation of the well treatment fluid, but thickens rapidly when diluted in the treatment fluid.
  • partitioning agents such as the PEG embodiment can be used effectively in the water-in-water emulsions at concentrations relative to the viscosifying polymer that, upon dilution in the well treatment fluid, are sufficiently low to minimize any deleterious effects on the treatment fluid in terms of, for example, rheology, stability, crosslinkability, and so on.
  • Another benefit of the water-in-water emulsion is that the mixture is easily flowable or pumpable, even though a comparable mixture of the water and polymer alone without any partitioning agent would be very thick or paste-like.
  • the swollen guar or other polymer in the water-in-water emulsion thus has a head start on the hydration process and can thus be hydrated in water or aqueous fluid more quickly relative to dry guar.
  • the swollen guar in the water-in-water emulsion can be further processed in beneficial ways to additionally enhance rapid hydration.
  • mechanical processing such as wet grinding of the water-in-water emulsion can be used to break the guar particles into smaller pieces and thus achieve faster hydration, but without the problems noted above in the prior art dry grinding.
  • the swollen guar particle is relatively larger and softer than the dry counterpart, which facilitates the grinding.
  • wet grinding the heat generated can be dissipated in the liquid medium. Since the grinding is also cushioned by the fluid, there is less reduction of the polymer molecular weight.
  • the invention provides a method of treating a subterranean formation penetrated by a well bore.
  • the method can include the steps of: (1) mixing a rheological polymer, a partitioning agent and a first liquid medium to form a heterogeneous mixture comprising a dispersed rheological polymer-rich phase and a partitioning agent-rich phase; (2) diluting the heterogeneous mixture with a second liquid medium miscible with the first liquid medium to mutually dissolve the polymer-rich phase and the partitioning-agent rich phase and form a well treatment fluid comprising a continuous mixed polymer-agent phase; and (3) injecting the well treatment fluid into the well bore.
  • the rheological polymer can be a thickening polymer effective to increase the viscosity of the well treatment fluid; or a friction reducer effective to reduce friction pressure losses when the well treatment fluid is pumped in the well bore at a high flow rate, e.g. 4 m/s.
  • the continuous mixed polymer-agent phase has an apparent viscosity at 1 1/s and 25°C that is greater than the bulk apparent viscosity of the heterogeneous mixture; an apparent viscosity at 10 1/s and 25 0 C that is greater than the bulk apparent viscosity of the heterogeneous mixture; or an apparent viscosity at 100 1/s and 25 0 C that is greater than the bulk apparent viscosity of the heterogeneous mixture.
  • the first and second liquid media can be aqueous and the mixing step can further include at least partially hydrating the thickening polymer.
  • the partitioning agent-rich phase can be continuous and the rheological -polymer-rich phase can be finely dispersed therein.
  • the first and second liquid media can be aqueous and the partitioning agent can comprise a water soluble polymer.
  • the mixing step comprises a weight ratio of rheological polymer to partitioning agent from 1 :4 to 4: 1.
  • the heterogeneous mixture can comprise from 2 to 20 percent by weight rheological polymer based on the weight of the liquid media in the heterogeneous mixture.
  • the continuous mixed polymer phase can comprise from 0.01 to 1 percent by weight rheological polymer based on the weight of the liquid media.
  • the partitioning agent can comprise a polymer soluble in the liquid media and having a solubility different with respect to the rheological polymer. Concentrated solutions of the rheological polymer and of the partitioning agent in the first liquid medium are preferably immiscible.
  • the rheological polymer can be a polysaccharide; the partitioning agent a polyalkylene oxide.
  • the heterogeneous mixture can comprise polyethylene glycol and one or more of guar, guar derivative, cellulose, cellulose derivative, heteropolysaccharide, heteropolysaccharide derivative, or polyacrylamide in an aqueous medium.
  • the first liquid medium is aqueous and the second liquid medium can be a high density brine.
  • the first and second liquid media can be aqueous, and the method can also include mechanically, thermally, or a combination of mechanically thermally processing the heterogeneous mixture effective to increase a rate of hydration of the polymer in the dilution step.
  • the processing can include, for example, wet grinding, high shear mixing, ultrasonification, heating, or the like, or any combination thereof.
  • the liquid media can be aqueous and the partitioning agent can include nonionic surfactant. Additionally or alternatively, the method can further comprise the step of dispersing a gas phase in the well treatment fluid to form an energized fluid or foam.
  • the invention can provide a method of preparing a well treatment fluid, comprising the steps of: (1) mixing polyethylene glycol and one or more polymers selected from the group consisting of guar, modified guar, cellulose, modified cellulose, heteropolysaccharide, heteropolysaccharide derivative, or polyacrylamide, with a first aqueous medium to hydrate the one or more polymers and form a water-in-water emulsion; and (2) mixing the water-in-water emulsion with a second aqueous medium to form a well treatment fluid.
  • polymers selected from the group consisting of guar, modified guar, cellulose, modified cellulose, heteropolysaccharide, heteropolysaccharide derivative, or polyacrylamide
  • the water-in-water emulsion can comprise from 5 to 20 percent of the one or more polymers, by weight of the water in the emulsion.
  • the well treatment fluid can comprise from 0.01 to 1 weight percent of the one or more polymers, by weight of the water in the well treatment fluid.
  • Another embodiment of the invention provides a method of preparing a polymer concentrate for use in a fluid for treating a subterranean formation penetrated by a well bore.
  • the method for preparing the concentrate can include the steps of: (a) admixing a rheological polymer, a partitioning agent and a first aqueous medium to form a heterogeneous mixture comprising a dispersed polymer-rich phase and a partitioning agent-rich phase; and (b) mechanically, thermally, or mechanically and thermally processing the heterogeneous mixture to increase a rate of hydration of the polymer upon dilution.
  • the processing step in various embodiments can include heating the heterogeneous mixture to a temperature above 60 0 C, wet grinding the heterogeneous mixture, high shear mixing of the heterogeneous mixture, e.g., at a shear rate above 1000 1/sec, ultrasonification of the heterogeneous mixture, or the like, including combinations thereof.
  • the heterogeneous mixture can include from 5 to 20 percent of the rheological polymer, by weight of the water in the mixture, and a weight ratio of the partitioning agent to the thickening polymer from 1:4 to 4: 1.
  • Another embodiment of the invention provides a method of preparing a well treatment fluid comprising mixing the polymer concentrate described above with a second aqueous medium to disperse the polymer in the resulting mixture.
  • the resulting mixture is completely dispersed within 90 seconds, preferably within 80, 70 or 60 seconds.
  • Another embodiment of the invention provides a method of treating a subterranean formation penetrated by a well bore comprising the steps of: (a) mixing the polymer concentrate described above with a second aqueous medium to disperse the polymer in the resulting mixture within 90 seconds, and (b) injecting the resulting mixture into the well bore.
  • Another embodiment of the invention provides a concentrated viscosifying additive for preparing a well treatment fluid, comprising a pumpable water-in-water emulsion of polyethylene glycol, one or more polymers selected from the group consisting of guar, modified guar, cellulose, modified cellulose, heteropolysaccharide, heteropolysaccharide derivative, or polyacrylamide, and one or more of an additament selected from the group consisting of proppants, fibers, crosslinkers, breakers, breaker aids, friction reducers, surfactants, clay stabilizers, buffers, similar additives used in fluids in the oil and gas industry and combinations thereof.
  • the water-in-water emulsion comprises from 5 to 20 percent of the one or more polymers, by weight of the water in the emulsion, and a weight ratio of the polyethylene glycol to the one or more polymers is from 1:4 to 4: 1.
  • a further embodiment of the invention provides apparatus for preparing a well treatment fluid.
  • the apparatus can include a solids feeder for supplying rheological polymer solids to a first mixing zone receiving a metered stream of a partitioning agent and a first aqueous stream to form a water-in-water emulsion stream.
  • a dilution zone can be provided for mixing the water-in-water emulsion stream with a second aqueous stream to mutually dissolve the rheological polymer- and the partitioning agent and form a Theologically modified aqueous stream.
  • the apparatus can also include a line for supplying the Theologically modified aqueous stream to a stirred header tank, and additive pumps for supplying one or more well treatment fluid additives to the header tank.
  • the apparatus can also include a prehydration processing unit for the water-in-water emulsion stream before the dilution zone.
  • the prehydration processing unit can include, for example, a wet grinder, a high shear mixer, a heater, an ultrasonic generator, or any combination thereof.
  • a further embodiment of the invention provides a method for supplying a hydrated polymer solution.
  • the method can include the steps of: (a) supplying rheological polymer solids, a partitioning agent and a first aqueous stream to a mixing zone to form a water-in- water emulsion stream; (b) optionally mechanically, thermally or mechanically and thermally processing the water-in-water emulsion stream to improve hydratability of the rheological polymer; and (c) supplying the water-in-water emulsion stream with a second aqueous stream to a dilution zone to form a Theologically modified aqueous stream.
  • the invention provides the well treatment fluid prepared by any one of the embodiments of the methods described above, including any combination or permutation of the individual method steps.
  • Figure 1 illustrates an approximated binodal curve for the aqueous systems of guar and polyethylene glycol having a molecular weight of 8000 (PEG 8000) in deionized (DI) water, wherein filled circles indicate single-phase mixtures and open circles indicate biphasic mixtures comprising low-viscosity guar concentrates, and wherein the diagonal line represents an embodiment of a dilution path for making a 0.5 wt% guar solution from a 1:1 guar:PEG 8000 concentrate.
  • PEG 8000 polyethylene glycol having a molecular weight of 8000
  • DI deionized
  • Figure 2 illustrates a phase diagram for guar mixed with PEG 8000 in DI water including the binodal separating single-phase solutions from two-phase solutions; the equivolumetric biphase line indicating compositions where equilibrium phase separation results in two phases of equal volume, and wherein compositions above and below the equivolumetric biphase line form relatively larger and smaller concentrated guar phases; and one embodiment according to the invention of a limit line where the mixture can be diluted to 0.5 wt% guar without rheological changes due to the PEG 8000, corresponding to a weight ratio of gua ⁇ PEG 8000 of approximately 5:8.
  • Figure 3 shows the rheology of 0.5 wt% guar solutions with and without addition of PEG 8000, in terms of apparent viscosity versus shear rate, indicating that concentrations of PEG 8000 less than approximately 1 wt% do not measurably alter the rheology of 0.5 wt% guar solutions according to one embodiment of the invention.
  • Figure 4 shows the viscosities of the baseline Example 4 fluid prepared from dry guar and the inventive Example 5 fluid prepared from a guar concentrate with PEG 8000, both in an otherwise identical borate crosslinking formulation, at a shear rate of 100 s "1 as the temperature of the sample was increased from room temperature to 79.4°C (175°F).
  • Figure 5 shows the viscosities at 100 s "1 of the Example 4 and 5 fluids from Figure 4 were equivalent while the samples were held at the 79.4°C (175°F) temperature for two hours.
  • Figure 6 shows the viscosities of two hydroxypropyl guars (HPG) of 0.6 and 0.4 degree of substitution injected into dense CaCl 2 brine as dry HPG for comparison and pre- hydrated HPG concentrates in water-in-water emulsions according to the present invention, as described in Examples 7-10, wherein each of the pre-hydrated HPG concentrate formulations generated viscosity rapidly, and addition of dry HPG to the brine showed very little viscosity development even after 30 minutes.
  • Figure 7 shows the relationship between the rpm of a blender, charged with water at relatively constant power to which guar is added all at once, and the viscosity of the guar solution, as a function of time, as described in Example 11.
  • Figure 8 shows the relationship between the percent hydration of the guar solution in Figure 7 as a function of time, from which the percent hydration can be correlated to blender rpm, as described in Example 11.
  • Figure 9 compares the hydration curves for: dry guar (Example 11, comparative); a water-in-water emulsion of 10 wt% guar and 6 wt% PEG 8000 prepared in a WARING blender (base WIWE, Example 12, inventive); the base WIWE processed with a SILVERSON high shear mixer for 10 minutes (Example 13, inventive); the base WIWE processed with a SILVERSON high shear mixer for 20 minutes (Example 14, inventive); and the base WIWE processed with an electric mortar for 10 minutes (Example 15, inventive), as described in Examples 11-15, according to embodiments of the invention.
  • Figure 10 compares the hydration curves for a water-in-water emulsion of 10 wt% guar and 6 wt% PEG 8000 prepared in a WARING blender (base WIWE), and the base WIWE preheated to 65.6°C (150 0 F), as described in Examples 12 and 16, according to embodiments of the invention.
  • Figure 11 shows a schematic flow diagram for wellsite preparation of a polymer gel in a well treatment fluid, based on dry guar powder via a water-in-water emulsion process for prehydration, as described in Example 17, according to an embodiment of the invention.
  • This invention relates to fluids used in treating a subterranean formation, and in particular, the invention relates to the use of water-in-water emulsions to create concentrated polymer suspensions useful for creating wellbore fluids and in methods of treating subterranean formations.
  • the invention is an improvement over the existing art by providing a concentrated polymer suspension which can be conveniently prepared, easily stored and/or transported, and accurately delivered to the treatment fluid with minimum equipment and dissolution time.
  • the use of water-in-water emulsions may also serve as a significant improvement for viscosifying dense brines for oilfield use.
  • Some embodiments of the invention incorporate the concept of aqueous two-phase systems as delivery systems for pre-hydrated wellsite polymer concentrates.
  • An advantage of the pre-hydrated concentrates in embodiments is the reduction or elimination of fish-eye formation which otherwise can occur when it is attempted to disperse the dry polymer in water.
  • the presence of the partitioning agent in the preparation of the polymer concentrate inhibits the formation of a coating gel over the polymer particle aggregates, and even low shear mixing in many embodiments will readily disaggregate and disperse the polymer particles within the solution of the partitioning agent.
  • the partitioning agent can be dissolved in water in advance of adding the polymer particles.
  • the method of preparing a well treatment fluid or of treating a subterranean formation is free of the formation of fish-eyes.
  • a heavy brine sometimes also called a high density brine or high brine
  • a heavy brine is an aqueous inorganic salt solution having a specific gravity of greater than about 1.02 kg/L (8.5 lb/gal (ppg)), 1.08 kg/L (9 ppg) orl.14 kg/L (9.5 ppg), especially above 1.2, 1.32, 1.44 or 1.5 kg/L (10, 11, 12 or 12.5 ppg).
  • Another advantage of these water-in-water emulsion systems is that they are very tolerant to any accidental water entering the concentrate, such as, for example, condensation in a tote, whereas even small amounts of water present in non-aqueous polymer slurries or dry, free-flowing powder or granulated polymer systems can render the material unusable.
  • Some embodiments of the invention use a low viscosity, concentrated polymer solution for rapidly making polymer solutions at the wellsite with minimal equipment and horsepower.
  • the water-in-water emulsion allows the polymer to be dissolved or at least partially hydrated in a water phase without making an excessively viscous liquid carrier vehicle.
  • This emulsion may be a phase-separated fluid in which a polymer, which may be a high molecular weight, water-soluble polymer, and a partitioning agent, which may also be a water-soluble polymer and/or a low molecular weight, water-soluble polymer, are dissolved in water to create a low viscosity mixture.
  • the mixture has a low viscosity due to the continuous phase having a very low concentration of the rheological polymer, but the invention is not limited by this theory and is generally applicable to any polymer-concentrated, triphasic mixtures in a mutual solvent or solvent system wherein dilution with additional solvent rapidly dissolves the rheological polymer in a monophasic system.
  • the polymer concentrate can have a lower viscosity than the corresponding polymer concentrate would have without the partitioning agent, i.e. dilution with additional solvent can thicken the polymer solution.
  • Such a pre-hydrated concentrated solution or slurry in the case of aqueous media, can be rapidly dispersed into another aqueous media, e.g. a water stream, to continuously make Theologically modified polymer solutions or gels for wellbore treatments.
  • This can in an embodiment eliminate the disadvantages of dissolving a dry polymer powder, or using a polymer slurried in oil, or using an ionically collapsed polymer solution.
  • Some embodiments of the invention are based upon two-phase polymer-polymer systems achievable with polymers of interest to the oilfield, e.g. viscosifiers, friction reducers, etc. Also, these two phase systems can be exploited to create low viscosity pre- hydrated (in the case of aqueous solvent systems) or pre-solvated (in the case of non-aqueous solvents) concentrated mixtures to allow rapid polymer mixing at a well site.
  • polymers useful in the invention include polymers that are either crosslinked or linear, or any combination thereof.
  • Polymers include natural polymers, derivatives of natural polymers, synthetic polymers, biopolymers, and the like, or any mixtures thereof.
  • An embodiment uses any viscosifying polymer used in the oil industry to form gels.
  • Another embodiment uses any friction-reducing polymer used in the oil industry to reduce friction pressure losses at high pumping rates, e.g. in slickwater systems.
  • suitable polymers include: polysaccharides, such as, for example, guar gums, high-molecular weight polysaccharides composed of mannose and galactose sugars, including guar derivatives such as hydropropyl guar (HPG), carboxymethyl guar (CMG), and carboxymethylhydroxypropyl guar (CMHPG), and other polysaccharides such as xanthan, diutan, and scleroglucan; cellulose derivatives such as hydroxyethyl cellulose (HEC), hydroxypropyl cellulose (HPC), carboxymethlyhydroxyethyl cellulose (CMHEC), and the like; synthetic polymers such as, but not limited to, acrylic and methacrylic acid, ester and amide polymers and copolymers, polyalkylene oxides such as polymers and copolymers of ethylene glycol, propylene glycol or oxide, and the like.
  • polysaccharides such as, for example, guar gums, high
  • the polymers are preferably water soluble.
  • associative polymers for which viscosity properties are enhanced by suitable surfactants and hydrophobically modified polymers can be used, such as cases where a charged polymer in the presence of a surfactant having a charge that is opposite to that of the charged polymer, the surfactant being capable of forming an ion- pair association with the polymer resulting in a hydrophobically modified polymer having a plurality of hydrophobic groups, as described published application US 2004209780.
  • a polymer when referred to as comprising a monomer or comonomer, the monomer is present in the polymer in the polymerized form of the monomer or in the derivative form of the monomer.
  • the phrase comprising the (respective) monomer or the like may be used as shorthand.
  • the polymer or polymers are formed of a linear, nonionic, hydroxyalkyl galactomannan polymer or a substituted hydroxyalkyl galactomannan polymer.
  • useful hydroxyalkyl galactomannan polymers include, but are not limited to, hydroxy-Ci-C 4 -alkyl galactomannans, such as hydroxy-Ci-C 4 -alkyl guars.
  • hydroxyalkyl guars include hydroxyethyl guar (HE guar), hydroxypropyl guar (HP guar), and hydroxybutyl guar (HB guar), and mixed C 2 -C 4 , C 2 /C 3 , C 3 /C 4 , or C 2 /C 4 hydroxyalkyl guars. Hydroxymethyl groups can also be present in any of these.
  • substituted hydroxyalkyl galactomannan polymers are obtainable as substituted derivatives of the hydroxy-Ci-C4-alkyl galactomannans, which include: 1) hydrophobically-modified hydroxyalkyl galactomannans, e.g., Ci-C 24 -alkyl-substituted hydroxyalkyl galactomannans, e.g., wherein the amount of alkyl substituent groups is preferably about 2 percent by weight or less by weight of the hydroxyalkyl galactomannan; and 2) poly(oxyalkylene)-grafted galactomannans (see, e.g., A. Bahamdan & W.H. Daly, in Proc.
  • hydrophobically-modified hydroxyalkyl galactomannans e.g., Ci-C 24 -alkyl-substituted hydroxyalkyl galactomannans, e.g., wherein the amount of alkyl substituent groups is preferably about
  • Poly(oxyalkylene)-grafts thereof can comprise two or more than two oxyalkylene residues; and the oxyalkylene residues can be C 1 -C 4 oxyalkylenes.
  • Mixed-substitution polymers comprising alkyl substituent groups and poly(oxyalkylene) substituent groups on the hydroxyalkyl galactomannan are also useful herein.
  • the ratio of alkyl and/or poly(oxyalkylene) substituent groups to mannosyl backbone residues can be about 1:25 or less, i.e. with at least one substituent per hydroxyalkyl galactomannan molecule; the ratio can be: at least or about 1 :2000, 1 :500, 1 :100, or 1 :50; or up to or about 1:50, 1 :40, 1:35, or 1:30. Combinations of galactomannan polymers according to the present disclosure can also be used.
  • galactomannans in one embodiment comprise a polymannose backbone attached to galactose branches that are present at an average ratio of from 1 : 1 to 1:5 galactose branches :mannose residues.
  • Preferred galactomannans comprise a 1— >4-linked ⁇ -D-mannopyranose backbone that is l ⁇ 6-linked to ⁇ -D-galactopyranose branches.
  • Galactose branches can comprise from 1 to about 5 galactosyl residues; in various embodiments, the average branch length can be from 1 to 2, or from 1 to about 1.5 residues.
  • Preferred branches are monogalactosyl branches.
  • the ratio of galactose branches to backbone mannose residues can be, approximately, from 1: 1 to 1 :3, from 1: 1.5 to 1 :2.5, or from 1: 1.5 to 1 :2, on average.
  • the galactomannan can have a linear polymannose backbone.
  • the galactomannan can be natural or synthetic. Natural galactomannans useful herein include plant and microbial (e.g., fungal) galactomannans, among which plant galactomannans are preferred.
  • legume seed galactomannans can be used, examples of which include, but are not limited to: tara gum (e.g., from Cesalpinia spinosa seeds) and guar gum (e.g., from Cyamopsis tetragonoloba seeds).
  • tara gum e.g., from Cesalpinia spinosa seeds
  • guar gum e.g., from Cyamopsis tetragonoloba seeds.
  • embodiments of the present invention may be described or exemplified with reference to guar, such as by reference to hydroxy-Ci-C 4 -alkyl guars, such descriptions apply equally to other galactomannans, as well.
  • the partitioning agent depends on the polymer that is to be concentrated in the heterogeneous mixture, as well as the solvent system, e.g. aqueous, nonaqueous, oil, etc.
  • the partitioning agent is soluble in the solvent medium, but has dissimilar thermodynamic properties such that a solution thereof is immiscible with a solution of the polymer at concentrations above a binodal curve for the system, or such that a solid phase of the polymer will not dissolve in a solution of the portioning agent at the concentration in the system.
  • the partitioning agent can be a low molecular weight hydrophobic polymer.
  • the partitioning agent in an embodiment is a polyoxyalkylene, wherein the oxyalkylene units comprise from one to four carbon atoms, such as, for example a polymer of ethylene glycol, propylene glycol or oxide, or a combination thereof, having a weight average molecular weight from 1000 to 25,000.
  • polyoxyalkylene and refers to homopolymers and copolymers comprising at least one block, segment, branch or region composed of oxyalkylene repeat units, e.g. polyethylene glycol.
  • Polyethylene glycol (PEG) having a molecular weight between 2000 and 10,000 is widely commercially available.
  • mPEG methoxy-PEG
  • PPO PEG- polypropylene oxide
  • BRIJ alkylated and hydroxyalkylated PEG available under the trade designation BRIJ, e.g. BRIJ 38; and the like.
  • partitioning agents can include polyvinyl pyrrolidone, vinyl pyrrolidine-vinyl acetate copolymers, and hydroxyalkylated or carboxyalkylated cellulose, especially low molecular weight hydroxyalkylated cellulose such as hydroxypropyl cellulose having a molecular weight of about 10,000.
  • partitioning agents comprises the class of water soluble chemicals known as non-ionic surfactants. These surfactants comprise hydrophilic and hydrophobic groups, that is, they are amphiphilic, but are electrophilically neutral, i.e. uncharged.
  • Nonionic surfactants can be selected from the group consisting of alkyl polyethylene oxides (such as BRIJ surfactants, for example), polyethylene oxide- polypropylene oxide copolymers (such as poloxamers or poloxamines, for example), alkyl-, hydroxyalkyl- and alkoxyalkyl polyglucosides (such as octyl or decyl glucosides or maltosides), fatty alcohols, fatty acid amides, and the like.
  • alkyl polyethylene oxides such as BRIJ surfactants, for example
  • polyethylene oxide- polypropylene oxide copolymers such as poloxamers or poloxamines, for example
  • alkyl-, hydroxyalkyl- and alkoxyalkyl polyglucosides such as octyl or decyl glucosides or maltosides
  • fatty alcohols such as octyl or decyl glucosides or maltosides
  • the heterogeneous polymer concentrate can have any suitable weight ratio of rheological polymer to partitioning agent that provides a heterogeneous mixture, i.e. a binary liquid mixture or a solid-liquid slurry. If the ratio of polyme ⁇ partitioning agent is too high, the mixture becomes too thick to pour or pump, or may even form a paste; if too low, the partitioning agent upon dilution may have an adverse impact on the polymer solution or well treatment fluid.
  • a polyme ⁇ partitioning agent ratio from 1 :4 to 4: 1 may be suitably employed, or higher or lower ratios may be used where the abovementioned disadvantages are avoided.
  • the polyme ⁇ partitioning agent ratio is from 1 :2 to 2.5: 1, preferably from 3:5 to 5:3.
  • the heterogeneous mixture can comprise anywhere upwards from 1 percent by weight rheological polymer, based on the weight of the liquid in the heterogeneous mixture, up to any maximum upper limit where the mixture is no longer fluid, e.g. pumpable or pourable using conventional oilfield pumping equipment. Lower concentrations of rheological polymer may provide little or no benefit because the dilution rate to obtain the treatment fluid is too low to be practical.
  • a 1 wt% concentrate would be mixed with water (or other liquid media) at 1 : 1 whereas a 20 wt% concentrate could be mixed at 40: 1.
  • the heterogeneous aqueous concentrate comprises a range of from a lower limit of 1, 2, 3 or 5 up to an upper limit of 10, 15 or 20 percent by weight of the polymer, by weight of the water or other liquid in the mixture.
  • the water-in-water emulsion may further include other additives such as dispersing aids, surfactants, pH adjusting compounds, buffers, antioxidants, colorants, biocides, which do not materially change the miscibility or solubility of the heterogeneous phases, or interfere with the desirable characteristics of the well treatment fluid.
  • the polymer concentrate can include any additive that is to be introduced into the well treatment fluid separately, provided that it is essentially inert in the concentrate.
  • at least one other well treatment fluid additive is present in the polymer concentrate, such as, for example, proppants, fibers, crosslinkers, breakers, breaker aids, friction reducers, surfactants, clay stabilizers, buffers, and the like.
  • the other additive can also be concentrated in the polymer concentrate so that the additive does not need to be added to the well treatment fluid separately, or can be added in a lesser amount. This can be advantageous where the other additive is usually added proportionally with respect to the polymer. Also, the activity of an additive(s) can be delayed, in one embodiment, and the delay can at least in part be facilitated where the additive is preferentially concentrated in the partitioning agent-rich phase or otherwise reactively separated from the polymer.
  • the water-in-water emulsion can also include or be mixed in a hydrophobic liquid, e.g. an oil-in-water or an invert (water-in-oil) emulsion wherein the aqueous phase in the oil emulsion comprises the water-in-water emulsion.
  • a hydrophobic liquid e.g. an oil-in-water or an invert (water-in-oil) emulsion wherein the aqueous phase in the oil emulsion comprises the water-in-water emulsion.
  • the oil-in-(water-in- water emulsion) emulsion can comprise a relatively high volume of oil in a discontinuous phase, for example, 90 volume percent or greater oil.
  • the viscosifying polymers When incorporated in the well treatment or other fluid, for example upon dilution of the water-in-water polymer concentrates in a second aqueous medium, the viscosifying polymers may be present at any suitable concentration.
  • the rheological polymer can be present in an amount of from about 0.01 g/L of fluid (0.1 lb/1000 gal of fluid (ppt)) to less than about 7.2 g/L (60 ppt), or from about 0.018 to about 4.8 g/L (about 1.5 to about 40 ppt), from about 0.018 to about 4.2 g/L (about 1.5 to about 35 ppt), or from 0.018 to about 3 g/L (1.5 to about 25 ppt), or even from about 0.24 to about 1.2 g/L (about 2 to about 10 ppt).
  • Friction reducing polymers are generally diluted for use in the treatment fluid to a concentration from 0.01 to 0.4 percent by weight of the liquid phase, especially from 0.025 to 0.2 percent by weight of the liquid phase.
  • the polymer is diluted from the concentrate into the treatment or other fluid at a rate within a range of from any lower limit selected from 0.0001, 0.001, 0.01, 0.025, 0.05, 0.1, or 0.2 percent by weight of the liquid phase, up to any higher upper limit selected from 1.0, 0.5, 0.4, 0.25, 0.2, 0.15 or 0.1 percent by weight of the liquid phase.
  • Some fluid compositions useful in some embodiments of the invention may also include a gas component, produced from any suitable gas that forms an energized fluid or foam when introduced into an aqueous medium.
  • a gas component produced from any suitable gas that forms an energized fluid or foam when introduced into an aqueous medium.
  • the gas component comprises a gas selected from the group consisting of nitrogen, air, argon, carbon dioxide, and any mixtures thereof. More preferably the gas component comprises nitrogen or carbon dioxide, in any quality readily available.
  • the gas component may assist in the fracturing and acidizing operation, as well as the well clean-up process.
  • the fluid in one embodiment may contain from about 10% to about 90% volume gas component based upon total fluid volume percent, preferably from about 20% to about 80% volume gas component based upon total fluid volume percent, and more preferably from about 30% to about 70% volume gas component based upon total fluid volume percent.
  • the fluid is a high-quality foam comprising 90 volume percent or greater gas phase.
  • the partitioning agent used in the polymer delivery system can be selected to enhance the characteristics of the energized fluid or foam, such as gas phase stability or viscosity, for example, where the partitioning agent is a surfactant such as a nonionic surfactant, especially the alkoxylated (e.g., ethoxylated) surfactants available under the BRIJ designation.
  • the fluids used may further include a crosslinker.
  • Adding crosslinkers to the fluid may further augment the viscosity of the fluid.
  • Crosslinking consists of the attachment of two polymeric chains through the chemical association of such chains to a common element or chemical group.
  • Suitable crosslinkers may comprise a chemical compound containing a polyvalent ion such as, but not necessarily limited to, boron or a metal such as chromium, iron, aluminum, titanium, antimony and zirconium, or mixtures of polyvalent ions.
  • the crosslinker can be delayed, in one embodiment, and the delay can at least in part be facilitated where the crosslinker or activator is concentrated or otherwise reactively separated in the partitioning agent-rich phase.
  • the fluids of some embodiments of the invention may include an electrolyte which may be an organic acid, organic acid salt, organic salt, or inorganic salt. Mixtures of the above members are specifically contemplated as falling within the scope of the invention. This member will typically be present in a minor amount (e.g. less than about 30% by weight of the liquid phase).
  • the organic acid is typically a sulfonic acid or a carboxylic acid
  • the anionic counter-ion of the organic acid salts is typically a sulfonate or a carboxylate.
  • organic molecules include various aromatic sulfonates and carboxylates such as p-toluene sulfonate, naphthalene sulfonate, chlorobenzoic acid, salicylic acid, phthalic acid and the like, where such counter-ions are water-soluble.
  • Most preferred organic acids are formic acid, citric acid, 5-hydroxy-l-napthoic acid, 6- hydroxy- 1-napthoic acid, 7 -hydroxy- 1-napthoic acid, 1 -hydroxy -2-naphthoic acid, 3-hydroxy-2-naphthoic acid, 5-hydroxy -2 -naphthoic acid, 7-hydroxy-2-napthoic acid, 1, 3-dihydroxy-2-naphthoic acid, and 3,4- dichlorobenzoic acid.
  • the inorganic salts that are particularly suitable include, but are not limited to, water- soluble potassium, sodium, and ammonium salts, such as potassium chloride and ammonium chloride. Additionally, magnesium chloride, calcium chloride, calcium bromide, zinc halide, sodium carbonate, and sodium bicarbonate salts may also be used. Any mixtures of the inorganic salts may be used as well.
  • the inorganic salts may aid in the development of increased viscosity that is characteristic of preferred fluids. Further, the inorganic salt may assist in maintaining the stability of a geologic formation to which the fluid is exposed.
  • the electrolyte is an organic salt such as tetramethyl ammonium chloride, or inorganic salt such as potassium chloride.
  • the electrolyte is preferably used in an amount of from about 0.01 wt% to about 12.0 wt% of the total liquid phase weight, and more preferably from about 0.1 wt% to about 8.0 wt% of the total liquid phase weight.
  • Fluids used in some embodiments of the invention may also comprise an organoamino compound.
  • suitable organoamino compounds include, but are not necessarily limited to, tetraethylenepentamine, triethylenetetramine, pentaethylenehexamine, triethanolamine, and the like, or any mixtures thereof.
  • organoamino compounds are used in fluids of the invention, they are incorporated at an amount from about 0.01 wt% to about 2.0 wt% based on total liquid phase weight.
  • the organoamino compound is incorporated at an amount from about 0.05 wt% to about 1.0 wt% based on total liquid phase weight.
  • a particularly useful organoamino compound is tetraethylenepentamine, particularly when used with diutan viscosifying agent at temperatures of approximately 300 0 F.
  • Breakers may optionally be used in some embodiments of the invention.
  • the purpose of this component is to "break" or diminish the viscosity of the fluid so that this fluid is even more easily recovered from the formation during cleanup.
  • oxidizers, enzymes, or acids may be used. Breakers reduce the polymer's molecular weight by the action of an acid, an oxidizer, an enzyme, or some combination of these on the polymer itself.
  • increasing the pH and therefore increasing the effective concentration of the active crosslinker (the borate anion) will allow the polymer to be crosslinked. Lowering the pH can just as easily eliminate the borate/polymer bonds.
  • Preferred breakers include 0.1 to 20 pounds per thousands gallons of conventional oxidizers such as ammonium persulfates, live or encapsulated, or potassium periodate, calcium peroxide, chlorites, and the like.
  • conventional oxidizers such as ammonium persulfates, live or encapsulated, or potassium periodate, calcium peroxide, chlorites, and the like.
  • the film may be at least partially broken when contacted with formation fluids (oil), which may help de-stabilize the film.
  • the breaker can be delayed, in one embodiment, and the delay can at least in part be facilitated where the breaker or breaker activator is concentrated or otherwise reactively separated in the partitioning agent- rich phase.
  • a fiber component may be included in the fluids used in the invention to achieve a variety of properties including improving particle suspension, and particle transport capabilities, and gas phase stability. Fibers used may be hydrophilic or hydrophobic in nature, but hydrophilic fibers are preferred.
  • Fibers can be any fibrous material, such as, but not necessarily limited to, natural organic fibers, comminuted plant materials, synthetic polymer fibers (by non-limiting example polyester, polyaramide, polyamide, novoloid or a novoloid-type polymer), fibrillated synthetic organic fibers, ceramic fibers, inorganic fibers, metal fibers, metal filaments, carbon fibers, glass fibers, ceramic fibers, natural polymer fibers, and any mixtures thereof.
  • Particularly useful fibers are polyester fibers coated to be highly hydrophilic, such as, but not limited to, DACRON® polyethylene terephthalate (PET) Fibers available from Invista Corp. Wichita, KS, USA, 67220.
  • useful fibers include, but are not limited to, polylactic acid polyester fibers, polyglycolic acid polyester fibers, polyvinyl alcohol fibers, and the like.
  • the fiber component may be included at concentrations from about 1 to about 15 grams per liter of the liquid phase of the fluid, preferably the concentration of fibers are from about 2 to about 12 grams per liter of liquid, and more preferably from about 2 to about 10 grams per liter of liquid.
  • Embodiments of the invention may use other additives and chemicals that are known to be commonly used in oilfield applications by those skilled in the art. These include, but are not necessarily limited to, materials in addition to those mentioned hereinabove, such as breaker aids, oxygen scavengers, alcohols, scale inhibitors, corrosion inhibitors, fluid-loss additives, bactericides, iron control agents, organic solvents, and the like.
  • a co-surfactant to optimize viscosity or to minimize the formation of stabilized emulsions that contain components of crude oil, or as described hereinabove, a polysaccharide or chemically modified polysaccharide, natural polymers and derivatives of natural polymers, such as cellulose, derivatized cellulose, guar gum, derivatized guar gum, or biopolymers such as xanthan, diutan, and scleroglucan, synthetic polymers such as polyacrylamides and polyacrylamide copolymers, oxidizers such as persulfates, peroxides, bromates, chlorates, chlorites, periodates, and the like.
  • a co-surfactant to optimize viscosity or to minimize the formation of stabilized emulsions that contain components of crude oil, or as described hereinabove, a polysaccharide or chemically modified polysaccharide, natural polymers and derivatives of natural polymers, such as cellulose, derivatized cellulose,
  • Embodiments of the invention may also include placing proppant particles that are substantially insoluble in the fluids. Proppant particles carried by the treatment fluid remain in the fracture created, thus propping open the fracture when the fracturing pressure is released and the well is put into production.
  • Suitable proppant materials include, but are not limited to, sand, walnut shells, sintered bauxite, glass beads, ceramic materials, naturally occurring materials, or similar materials. Mixtures of proppants can be used as well.
  • Naturally occurring materials may be underived and/or unprocessed naturally occurring materials, as well as materials based on naturally occurring materials that have been processed and/or derived.
  • Suitable examples of naturally occurring particulate materials for use as proppants include, but are not necessarily limited to: ground or crushed shells of nuts such as walnut, coconut, pecan, almond, ivory nut, brazil nut, etc.; ground or crushed seed shells (including fruit pits) of seeds of fruits such as plum, olive, peach, cherry, apricot, etc.; ground or crushed seed shells of other plants such as maize (e.g., corn cobs or corn kernels), etc.; processed wood materials such as those derived from woods such as oak, hickory, walnut, poplar, mahogany, etc. including such woods that have been processed by grinding, chipping, or other form of particalization, processing, etc. Further information on nuts and composition thereof may be found in Encyclopedia of Chemical Technology, Edited by Raymond E. Kirk and Donald F. Othmer, Third Edition, John Wiley & Sons, Volume 16, pages 248-273 (entitled "Nuts”), Copyright 1981.
  • the concentration of proppant in the fluid can be any concentration known in the art, and will preferably be in the range of from about 0.05 to about 3 kilograms of proppant added per liter of liquid phase. Also, any of the proppant particles can further be coated with a resin to potentially improve the strength, clustering ability, and flow back properties of the proppant.
  • One preferred fracture stimulation treatment according to the present invention typically begins with a conventional pad stage to generate the fracture, followed by a sequence of stages in which a viscous carrier fluid transports proppant into the fracture as the fracture is propagated. Typically, in this sequence of stages the amount of propping agent is increased, normally stepwise.
  • the pad and carrier fluid can be a fluid of adequate viscosity.
  • the pad and carrier fluids may contain various additives. Non-limiting examples are fluid loss additives, crosslinking agents, clay control agents, breakers, iron control agents, and the like, provided that the additives do not affect the stability or action of the fluid.
  • fluids of the invention may be used in the pad treatment, the proppant stage, or both.
  • the components of the liquid phase are preferably mixed on the surface.
  • a the fluid may be prepared on the surface and pumped down tubing while the gas component could be pumped down the annular to mix down hole, or vice versa.
  • Yet another embodiment of the invention includes cleanup method.
  • cleanup or "fracture cleanup” refers to the process of removing the fracture fluid (without the proppant) from the fracture and wellbore after the fracturing process has been completed.
  • Techniques for promoting fracture cleanup traditionally involve reducing the viscosity of the fracture fluid as much as practical so that it will more readily flow back toward the wellbore. While breakers are typically used in cleanup, the fluids of the invention may be effective for use in cleanup operations, with or without a breaker.
  • the invention relates to gravel packing a wellbore.
  • a gravel packing fluid it preferably comprises gravel or sand and other optional additives such as filter cake clean up reagents such as chelating agents referred to above or acids (e.g. hydrochloric, hydrofluoric, formic, acetic, citric acid) corrosion inhibitors, scale inhibitors, biocides, leak-off control agents, among others.
  • filter cake clean up reagents such as chelating agents referred to above or acids (e.g. hydrochloric, hydrofluoric, formic, acetic, citric acid) corrosion inhibitors, scale inhibitors, biocides, leak-off control agents, among others.
  • suitable gravel or sand is typically having a mesh size between 8 and 70 U.S. Standard Sieve Series mesh.
  • water-in-water emulsions are used to provide friction reducers, such as acrylamide polymers and copolymers having pendant cationic and/or anionic groups.
  • friction reducers such as acrylamide polymers and copolymers having pendant cationic and/or anionic groups.
  • the friction reducer can be provided as a stable concentrate that can rapidly flip when diluted with water to allow the polymer to become completely solubilized in an aqueous treatment fluid, especially a slickwater fluid where the friction reducer is added on the fly.
  • some embodiments of the invention include forming and treating a subterranean formation with a fluid formed of water-in-water emulsions of the invention and such produced waters, river waters, and other difficult waters.
  • Example 1 A low viscosity aqueous suspension of guar with PEG 8000.
  • a series of polymer solutions was created by dissolving 0 - 4 weight percent dry guar and 0 - 4 weight percent dry polyethylene glycol (PEG 8000) in deionized (DI) water.
  • DI deionized
  • 200 ml of DI water were used, and the polymers were measured as dry powders with percentages expressed on a total fluid weight basis.
  • the dry polymers were mixed together and then added together into the DI water while stirring vigorously in a WARING blender. Each sample was stirred rapidly in the blender for a minimum of one hour. After this stirring process, each sample was visually inspected for evidence of phase separation. Samples were monitored for a period of at least 24 hours to check for phase separation. The results were plotted in Figure 1 using filled circles 10 to indicate no phase separation and open circles 12 to indicate the occurrence of phase separation.
  • the low-viscosity concentrates 12 fell within the two-phase region demarcated by the binodal curve 14 approximated in Figure 1. It should be pointed out that although these concentrations had considerable guar, they were not suspensions of dry guar in diesel or some other oil, since the guar was hydrated in water. When the guar concentrate was diluted with additional DI water to approximately 0.5 weight percent, it formed linear gel very rapidly without any fish-eye formation and without requiring an extensive hydration process, unlike a dry polymer addition or a dry polymer-oil slurry addition.
  • one series of fluids was made with 1 weight percent guar based upon total fluid weight, but with different amounts of PEG 8000, i.e. 0, 1, 1.5, 2, 3 and 4 weight percent based on total fluid weight.
  • PEG 8000 i.e. 0, 1, 1.5, 2, 3 and 4 weight percent based on total fluid weight.
  • the samples were seen to phase separate over a period of a few hours, but no phase separation occurred for the lower PEG 8000 concentrations.
  • the phase-separated solutions 12 readily dispersed to provide low viscosity suspensions of guar polymer.
  • the diagonal line 16 thus represents an embodiment of a dilution path for making a 0.5 wt% guar gel from a 1 :1 gua ⁇ PEG 8000 concentrate. It should be noted that the phase diagram in Figure 1 does not suggest an upper limit as to the amount of polymer that can be concentrated in such a way. Pourable water-in-water emulsions with 20 wt% guar concentrations have been successfully formulated.
  • Example 2 Wellsite guar delivery system using low viscosity aqueous suspension.
  • Figure 2 provides a phase diagram for a high molecular weight guar routinely used for wellbore treatment fluids.
  • the guar in this example was again phase separated with PEG 8000.
  • Line 20 on the phase diagram indicates the binodal for phase separation, with compositions to the upper-right of line 20 being low viscosity two- phase solutions of the two polymers in water.
  • Line 22 in the two-phase region indicates the line of compositions having 50/50 phase volume upon phase separation; line 24 a 60/40 phase volume of guar:PEG 8000; and line 26 a 40/60 phase volume of guar: PEG 8000.
  • compositions above 60 to about 80 volume percent guar phase are borderline pumpable, generally resembling applesauce in texture; and compositions above 80 volume percent guar phase generally have a paste-like consistency.
  • Limit line 28 represents an embodiment of the maximum PEG 8000 concentration where the mixture can be safely diluted to 0.5 wt% guar without rheological changes due to the PEG 8000, corresponding to a weight ratio of gua ⁇ PEG 8000 of approximately 5:8.
  • composition 30 at 10% guar, 6% PEG 8000 was selected as an example point for demonstrating how an aqueous polymer concentrate can be used in a delivery system for making an exemplary treatment fluid.
  • Composition 30 can be prepared offsite, delivered to the wellsite, and diluted approximately 20: 1 with water to 0.5 weight percent guar and 0.3 weight percent PEG 8000.
  • phase diagram yields a critical region in the phase space where linear guar solutions diluted from the concentrate are essentially indistinguishable from the same fluids made from only guar and water, in terms of rheology, stability or crosslinking properties. That is, the presence of a certain amount of PEG 8000 or other partitioning agent in the concentrate may not, upon dilution in the treatment fluid, measurably alter the rheology, stability or crosslinking properties of the guar in solution.
  • the area 32 from zero to 1% for both guar and PEG concentration in Figure 2 indicates such a region.
  • Example 3 Effect of diluted PEG 8000 on viscosity of linear gels.
  • Figure 3 shows the rheology of 0.5 wt% guar solutions with and without addition of PEG 8000, in terms of apparent viscosity versus shear rate. Concentrations of PEG 8000 less than approximately 1 wt% do not measurably alter the rheology of 0.5 wt% guar solutions. Specifically, the data shown in Figure 3 illustrate that addition of PEG 8000 to a 0.5% guar solution (40 lbs/1000 gallons) has negligible impact on the guar solution rheology for PEG 8000 concentrations up to at least 1 wt%.
  • phase-separated, low viscosity concentrate can be used to deliver guar as a treatment fluid, without sacrificing the performance of the guar fluid thus made when the dilution is performed to create a final fluid composition within the area 32 from zero to 1% for both guar and PEG concentration in Figure 2.
  • Examples 4 and 5 Effect of guar concentrates in PEG 8000 on crosslinked treatment fluid properties.
  • a baseline fluid (Example 4) was made from dry guar powder added to the fluid for comparison with the equivalent fluid made from an aqueous two-polymer concentrate.
  • the baseline fluid was made and crosslinked in a standard treatment fluid formulation based upon de-ionized water (100 mL), 50% solution of tetramethyl ammonium chloride (0.2 mL), solution of 60% of sodium gluconate and 32% of boric acid (0.12 mL), and 30% solution of sodium hydroxide (0.08 ml).
  • the second fluid contained 0.18 wt% PEG 8000, as well as 0.3 wt% guar, thereby placing it well within area 32 for dilution as identified in Figure 2.
  • this second fluid was crosslinked with a combination sodium gluconate, boric acid, and sodium hydroxide at a pH of approximately 10.
  • Example 6 A low-viscosity aqueous suspension of diutan.
  • a low-viscosity concentrated solution of diutan was formulated by combining diutan at 10 weight percent in DI water with 20 weight percent water soluble polymer comprising the sodium salt of polynaphthalene sulfonate- formaldehyde condensate, mol wt 8000, and 3 weight percent of a PEG-PPO-PEG triblock nonionic surfactant. This multi-polymer solution was mixed by first dissolving the water soluble polymer and surfactant in water for several minutes and then slowly adding the diutan polymer.
  • the solution was mixed vigorously in a WARING blender for 1 hour to assure complete mixing and dissolution of the polymers.
  • the final solution had a very low viscosity, was easily pourable, and slowly phase separated into diutan-rich and diutan-lean phases after sitting for approximately twelve hours.
  • the phase-separated solution was easily resuspended, however, with gentle stirring.
  • the 10 weight percent diutan solution was diluted into fresh water to rapidly make a viscous 1 weight percent diutan gel.
  • Examples 7 - 10 Rapidly viscosifying a heavy brine fluid with a pre-hydrated suspension of hydroxypropyl guar (HPG).
  • HPG hydroxypropyl guar
  • Example 7 and 8 baseline runs using dry guar, 0.5 wt% HPG was measured as a dry powder and dispersed into CaC ⁇ brine having a density of 1.318 g/mL (11.0 lb/gal or ppg) in a stirred WARING blender.
  • the HPG had 0.6 molar substitution, JAGUAR HP-60; and in Example 8, HPG with 0.4 molar substitution, ECOPOL 400DS, was used.
  • Mixing with HPG started at time 0 on the plot of Figure 6 and continued for 2.5 minutes. Viscosity was measured with a Fann 35 viscometer at room temperature beginning at 5 minutes.
  • a prehydrated HPG mixture was first prepared from 100 g DI water, 0.025 ml 50% aqueous solution of alkyl (C 12 - C ⁇ ) dimethyl benzyl ammonium chloride, 10 g PEG 10K, and 4 g HPG.
  • the HPG had 0.6 molar substitution, JAGUAR HP-60; and in Example 10, HPG with 0.4 molar substitution, ECOPOL 400DS, was used. These solutions were stirred until complete dissolution of the components created a pre-hydrated concentrate.
  • Figure 6 compares the viscosity development of the two HPG guars injected into brine as dry and pre-hydrated concentrates.
  • Each of the pre-hydrated concentrate formulations in Examples 9 and 10 generated viscosity rapidly and showed appreciable viscosification within 5 minutes of initial mixing.
  • addition of dry HPG to the brine in Examples 7 and 8 showed very little viscosity development after five minutes, and even after 30 minutes.
  • the viscosity of the dry guar formulations was an order of magnitude less than the viscosity of the formulations mixed from aqueous concentrates.
  • An advantage of the prehydrated embodiments of Examples 9 and 10 is that the pre-hydrated concentrates rapidly viscosity heavy brines that otherwise would require the use of slow polymer hydration processes. Pre-hydration yields significant viscosity within 5 min, while direct hydration of dry guar into the brine may not yield significant viscosity even after 30 minutes.
  • Examples 11 - 16 Test procedure for determining percent hydration vs. rpm.
  • a WARING blender equipped with a tachometer to read the blender blade rotational speed 500 mL of water were charged.
  • the rpm were set to a level to create a deep vortex but not so deep as to entrap too much air, which was determined to be in the range of between 1500-1600 rpm, and this setting was used throughout the following examples.
  • Example 12 this hydration procedure was repeated with the same amount of polymer in the form of a water-in-water emulsion which was first prepared separately in a WARING blender based on composition 30 in Figure 2 and Example 2 described above, i.e. a mixture of 10% polymer and 6% PEG 8000.
  • a WARING blender based on composition 30 in Figure 2 and Example 2 described above, i.e. a mixture of 10% polymer and 6% PEG 8000.
  • Example 13 the water-in-water emulsion of composition 30 was processed with a SILVERSON high shear mixer for 10 minutes and 20 minutes, respectively.
  • Example 15 the guar concentrate of composition 30 was processed by wet grinding with an electric mortar for 10 minutes. These processed water-in-water emulsion samples were then used to develop hydration curves using the procedure of Example 12.
  • Figure 9 shows the hydration curves for Examples 11 - 15. As indicated, the hydration rate of the base water-in-water emulsion (Example 12) was equivalent to or improved slightly over the dry polymer (Example 11).
  • Example 16 the guar concentrate of composition 30 was heated to 65.6°C (150 0 F) just before addition to the room temperature water (500 ml) in the blender.
  • Figure 7 shows the improvement on hydration of Example 16 achieved by heating the water- in-water emulsion before the hydration test, compared to the base emulsion without preheating (Example 12). Note the heating was with a highly concentrated slurry, which accounted for about 5 wt% of the total final hydrated gel, i.e. a 95% reduction in heating requirements compared to heating the entire mixture of the pre-gel components.
  • Example 17 Wellsite hydration process using water-in-water emulsion.
  • Figure 11 shows an example of a flow diagram for equipment to implement a hydration process 100 using water-in-water emulsion technique.
  • Dry guar 102 and PEG 8000 104 which can be a dry powder, aqueous solution or slurry, are supplied together with a first stream 106 of water 108 to mixing zone 110, which can be an inline, batch or continuous mixer for mixing liquids and solids.
  • the water-in-water emulsion can be optionally stored in an emulsion holding tank 112.
  • the emulsion is then processed in grinding zone 114 and/or heating zone 116 for prehydration enhancement.
  • the processed emulsion is then supplied to dilution zone 118 where it is diluted with second water stream 120 to form the gel which is then received in optional header tank 122 and with sufficient residence time in the line 124 and/or tank 122 for complete hydration, supplied to an otherwise conventional POD metering system operatively associated with additive pumps 128 and wellhead 130.
  • the ratio of the first water stream 106 to the second water stream 120 is about 1 :20 in one embodiment.
  • Examples 18 - 19 Polyacrylamide friction reducer concentrates. A solution was made by adding 2% by weight KCL to distilled water. For Example 18, 7.5 weight percent of 7000 molecular weight polyethylene glycol was then added to the KCl solution. Then 20% by weight of high molecular weight polyacrylamide was added to the solution. The solution was stirred. The resulting mixture had water like viscosity. For Example 19, 7.5 weight percent of BRIJ 38 polyoxyethylene was added to the 7.5 wt% KCl solution, followed by 20% by weight of the high molecular weight polyacrylamide was added to the solution. The solution was stirred and the resulting mixture again had water like viscosity.

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Abstract

Cette invention porte sur des compositions et des procédés pour traiter des formations souterraines, en particulier des compositions et procédés de stimulation de champ pétrolifère utilisant des émulsions polymères eau-dans-eau pour dissoudre de façon uniforme un polymère à activité rhéologique, tel qu'un épaississant ou un agent de réduction de frottement, dans le fluide de traitement. Les émulsions ont une faible viscosité et sont facilement pompées en vue d'une incorporation par mélange dans un fluide de traitement, où, lors de la dilution avec un milieu aqueux, le polymère est facilement hydraté sans former d'yeux de poisson. L'agent de partage dans l'émulsion eau-dans-eau n'affecte généralement pas la rhéologie du fluide de traitement. L'invention porte également sur un nouveau traitement de l'émulsion par broyage à l'état humide, mélange à cisaillement élevé et/ou chauffage pour augmenter le taux d'hydratation dans la préparation du fluide de traitement de puits.
PCT/IB2008/052866 2007-07-17 2008-07-16 Distribution de polymère dans des applications de traitement de puits WO2009010932A2 (fr)

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CA2693246A CA2693246A1 (fr) 2007-07-17 2008-07-16 Distribution de polymere dans des applications de traitement de puits
EA201070153A EA020002B1 (ru) 2007-07-17 2008-07-16 Способ обработки подземного пласта, пронизанного буровой скважиной

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US95983607P 2007-07-17 2007-07-17
US60/959,836 2007-07-17
US5427708P 2008-05-19 2008-05-19
US61/054,277 2008-05-19
US12/166,804 US9574128B2 (en) 2007-07-17 2008-07-02 Polymer delivery in well treatment applications
US12/166,804 2008-07-02
US12/166,774 2008-07-02
US12/166,774 US8044000B2 (en) 2007-07-17 2008-07-02 Polymer delivery in well treatment applications

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Cited By (11)

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WO2010082158A1 (fr) * 2009-01-14 2010-07-22 Schlumberger Canada Limited Stabilisation de concentrés biphasiques grâce à l'ajout de petites quantités de polyélectrolytes de masse moléculaire élevée
WO2010082168A1 (fr) * 2009-01-16 2010-07-22 Schlumberger Canada Limited Rupture de la rhéologie d'un fluide de traitement de puits de forage par création d'une séparation de phases
WO2010082165A1 (fr) * 2009-01-15 2010-07-22 Schlumberger Canada Limited Utilisation d'une solution biphasique comme fluide de nettoyage de tube spiralé recyclable
WO2010082167A1 (fr) * 2009-01-15 2010-07-22 Schlumberger Canada Limited Systèmes chargés à partir de fluides biphasiques
US8517102B2 (en) 2007-11-26 2013-08-27 Schlumberger Technology Corporation Provision of viscous compositions below ground
WO2014146064A3 (fr) * 2013-03-15 2015-06-04 Kemira Oyj Polymères réduisant les frottements
US9334438B2 (en) 2007-07-17 2016-05-10 Schlumberger Technology Corporation Polymer delivery in well treatment applications
US9475974B2 (en) 2007-07-17 2016-10-25 Schlumberger Technology Corporation Controlling the stability of water in water emulsions
WO2020079149A1 (fr) 2018-10-18 2020-04-23 Basf Se Procédé de fourniture de concentrés de polyacrylamide aqueux homogènes et leur utilisation
WO2021236096A1 (fr) * 2020-05-22 2021-11-25 Halliburton Energy Services, Inc. Réducteurs de frottement améliorés pour fluides de fracturation à base d'eau
CN116285924A (zh) * 2020-11-16 2023-06-23 西安石油大油气科技有限公司 一种油田采油地层中性解堵剂组合物及其制备方法

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US20040256106A1 (en) * 2003-06-19 2004-12-23 Phillippi Max L. Method and apparatus for hydrating a gel for use in a subterranean well field of the invention
US20070114035A1 (en) * 2005-11-22 2007-05-24 Parris Michael D Method and composition of preparing polymeric fracturing fluids
WO2007085983A1 (fr) * 2006-01-25 2007-08-02 Schlumberger Canada Limited Procédés de traitement de formations souterraines à l'aide de fluides à base d'hétéropolysaccharides

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EP0846747A1 (fr) * 1996-12-09 1998-06-10 Wolff Walsrode Ag Procédé de préparation et utilisation de gels comme additifs pour bouclier d'avancement mécanique
US20040256106A1 (en) * 2003-06-19 2004-12-23 Phillippi Max L. Method and apparatus for hydrating a gel for use in a subterranean well field of the invention
US20070114035A1 (en) * 2005-11-22 2007-05-24 Parris Michael D Method and composition of preparing polymeric fracturing fluids
WO2007085983A1 (fr) * 2006-01-25 2007-08-02 Schlumberger Canada Limited Procédés de traitement de formations souterraines à l'aide de fluides à base d'hétéropolysaccharides

Cited By (18)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US9334438B2 (en) 2007-07-17 2016-05-10 Schlumberger Technology Corporation Polymer delivery in well treatment applications
US8043999B2 (en) 2007-07-17 2011-10-25 Schlumberger Technology Corporation Stabilizing biphasic concentrates through the addition of small amounts of high molecular weight polyelectrolytes
US9475974B2 (en) 2007-07-17 2016-10-25 Schlumberger Technology Corporation Controlling the stability of water in water emulsions
US8517102B2 (en) 2007-11-26 2013-08-27 Schlumberger Technology Corporation Provision of viscous compositions below ground
WO2010082158A1 (fr) * 2009-01-14 2010-07-22 Schlumberger Canada Limited Stabilisation de concentrés biphasiques grâce à l'ajout de petites quantités de polyélectrolytes de masse moléculaire élevée
WO2010082165A1 (fr) * 2009-01-15 2010-07-22 Schlumberger Canada Limited Utilisation d'une solution biphasique comme fluide de nettoyage de tube spiralé recyclable
WO2010082167A1 (fr) * 2009-01-15 2010-07-22 Schlumberger Canada Limited Systèmes chargés à partir de fluides biphasiques
US7950459B2 (en) 2009-01-15 2011-05-31 Schlumberger Technology Corporation Using a biphasic solution as a recyclable coiled tubing cleanout fluid
WO2010082168A1 (fr) * 2009-01-16 2010-07-22 Schlumberger Canada Limited Rupture de la rhéologie d'un fluide de traitement de puits de forage par création d'une séparation de phases
GB2527459A (en) * 2013-03-15 2015-12-23 Kemira Oyj Friction reducing polymers
CN105247009A (zh) * 2013-03-15 2016-01-13 凯米罗总公司 摩擦降低聚合物
WO2014146064A3 (fr) * 2013-03-15 2015-06-04 Kemira Oyj Polymères réduisant les frottements
WO2020079149A1 (fr) 2018-10-18 2020-04-23 Basf Se Procédé de fourniture de concentrés de polyacrylamide aqueux homogènes et leur utilisation
US20210347977A1 (en) * 2018-10-18 2021-11-11 Basf Se Method of providing homogeneous aqueous polyacrylamide concentrates and use thereof
US11725102B2 (en) 2018-10-18 2023-08-15 Basf Se Method of providing homogeneous aqueous polyacrylamide concentrates and use thereof
WO2021236096A1 (fr) * 2020-05-22 2021-11-25 Halliburton Energy Services, Inc. Réducteurs de frottement améliorés pour fluides de fracturation à base d'eau
US11479715B2 (en) 2020-05-22 2022-10-25 Halliburton Energy Services, Inc. Enhanced friction reducers for water-based fracturing fluids
CN116285924A (zh) * 2020-11-16 2023-06-23 西安石油大油气科技有限公司 一种油田采油地层中性解堵剂组合物及其制备方法

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