EP2943551A1 - Procédés et compositions comprenant des polymères dégradables pour l'entretien de puits de forage - Google Patents

Procédés et compositions comprenant des polymères dégradables pour l'entretien de puits de forage

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Publication number
EP2943551A1
EP2943551A1 EP14761514.0A EP14761514A EP2943551A1 EP 2943551 A1 EP2943551 A1 EP 2943551A1 EP 14761514 A EP14761514 A EP 14761514A EP 2943551 A1 EP2943551 A1 EP 2943551A1
Authority
EP
European Patent Office
Prior art keywords
polymer
poly
degradable
degradable polymer
wellbore
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Withdrawn
Application number
EP14761514.0A
Other languages
German (de)
English (en)
Inventor
B. Raghava Reddy
Janette CORTEZ
James William OGLE
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Halliburton Energy Services Inc
Original Assignee
Halliburton Energy Services Inc
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 US14/065,701 external-priority patent/US9410076B2/en
Application filed by Halliburton Energy Services Inc filed Critical Halliburton Energy Services Inc
Publication of EP2943551A1 publication Critical patent/EP2943551A1/fr
Withdrawn legal-status Critical Current

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Classifications

    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/02—Well-drilling compositions
    • C09K8/03—Specific additives for general use in well-drilling compositions
    • C09K8/035—Organic additives
    • C—CHEMISTRY; METALLURGY
    • C08—ORGANIC MACROMOLECULAR COMPOUNDS; THEIR PREPARATION OR CHEMICAL WORKING-UP; COMPOSITIONS BASED THEREON
    • C08G—MACROMOLECULAR COMPOUNDS OBTAINED OTHERWISE THAN BY REACTIONS ONLY INVOLVING UNSATURATED CARBON-TO-CARBON BONDS
    • C08G73/00—Macromolecular compounds obtained by reactions forming a linkage containing nitrogen with or without oxygen or carbon in the main chain of the macromolecule, not provided for in groups C08G12/00 - C08G71/00
    • C08G73/02—Polyamines
    • C08G73/0206—Polyalkylene(poly)amines
    • C—CHEMISTRY; METALLURGY
    • C08—ORGANIC MACROMOLECULAR COMPOUNDS; THEIR PREPARATION OR CHEMICAL WORKING-UP; COMPOSITIONS BASED THEREON
    • C08L—COMPOSITIONS OF MACROMOLECULAR COMPOUNDS
    • C08L67/00—Compositions of polyesters obtained by reactions forming a carboxylic ester link in the main chain; Compositions of derivatives of such polymers
    • C—CHEMISTRY; METALLURGY
    • C08—ORGANIC MACROMOLECULAR COMPOUNDS; THEIR PREPARATION OR CHEMICAL WORKING-UP; COMPOSITIONS BASED THEREON
    • C08L—COMPOSITIONS OF MACROMOLECULAR COMPOUNDS
    • C08L69/00—Compositions of polycarbonates; Compositions of derivatives of polycarbonates
    • 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
    • C—CHEMISTRY; METALLURGY
    • C08—ORGANIC MACROMOLECULAR COMPOUNDS; THEIR PREPARATION OR CHEMICAL WORKING-UP; COMPOSITIONS BASED THEREON
    • C08L—COMPOSITIONS OF MACROMOLECULAR COMPOUNDS
    • C08L79/00—Compositions of macromolecular compounds obtained by reactions forming in the main chain of the macromolecule a linkage containing nitrogen with or without oxygen or carbon only, not provided for in groups C08L61/00 - C08L77/00
    • C08L79/02—Polyamines
    • 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
    • C09K2208/26—Gel breakers other than bacteria or enzymes

Definitions

  • This disclosure relates to methods and compositions for servicing a wellbore. More specifically, it relates to methods and compositions for use in a wellbore penetrating a subterranean formations.
  • Natural resources such as gas, oil, and water residing in a subterranean formation or zone are usually recovered by drilling a wellbore down to the subterranean formation while circulating a drilling fluid in the wellbore. After terminating the circulation of the drilling fluid, a string of pipe, e.g., casing, is run in the wellbore. The drilling fluid is then usually circulated downward through the interior of the pipe and upward through the annulus, which is located between the exterior of the pipe and the walls of the wellbore.
  • a string of pipe e.g., casing
  • primary cementing is typically performed whereby a cement slurry is placed in the annulus and permitted to set into a hard mass (i.e., sheath) to thereby attach the string of pipe to the walls of the wellbore and seal the annulus.
  • a hard mass i.e., sheath
  • Degradable polymers are increasingly becoming of interest in various subterranean applications based, at least in part, on their ability to degrade and leave voids, act as a temporary restriction to the flow of a fluid, or produce desirable degradation products (e.g., acids).
  • desirable degradation products e.g., acids.
  • One particular degradable polymer that has received recent attention is poly(lactic acid) because it is a material that will degrade downhole in aqueous media after it has performed a desired function or because its degradation products will perform a desired function (e.g., degrade an acid soluble component, or lower fluid pH to breakdown borate crosslinked fluids).
  • Degradable polymers may be used to leave voids behind upon degradation to improve or restore the permeability of a given structure.
  • a proppant pack may be created that comprises proppant particulates and degradable polymers so that, when the degradable polymer degrades, voids are formed in the proppant pack.
  • voids also may be created in a set cement in a subterranean environment.
  • degradable polymers may be used as a coating to temporarily protect a coated object or chemical from exposure to the subterranean environment.
  • a breaker or some other treatment chemical may be coated, encapsulated, or encaged in poly(lactic acid) and used in a subterranean operation such that the breaker may not be substantially exposed to the subterranean environment until the poly(lactic acid) coating substantially degrades.
  • Still another use for degradable polymers in subterranean operations involves creating downhole tools or parts of downhole tools out of solid masses of a degradable polymer. In such operations, the degradable polymer may be designed such that it does not substantially degrade until the tool has completed its desired function. In some operations, a tool function may be temporarily delayed by coating with polylactic acid.
  • Still other uses for degradable polymers in subterranean operations include their use as diverting agents, bridging agents, and fluid loss control agents.
  • Such materials will be required to be more resistant to hydrolytic degradation (i.e., polymer chain scission due to reactions with water). In such cases, methods to accelerate the reactions with water to break the polymer down at the end of an operation in a controlled and predictable manner will be of use.
  • BHT hydrolytic degradation
  • the percentage of polymer degradation needed may be as low as 20%.
  • the polymer plug or filter cake should degrade to an extent sufficient to loosen its packed particle density so that a flowing fluid can break up and flow out the remaining undegraded particulate material.
  • the quantities of the degradable polymer required to accomplish a desired objective depend on the type of application. For example, in a diversion operation during multistage fracturing, the amounts of degradable polymer needed may be as high as 250 to 500 lbs/1000 gal. It would be beneficial to reduce the amount of polymer utilized to accomplish a particular operation without sacrificing the intended performance objectives. This would reduce the cost of the operation as well as reduce the amount of breakers needed.
  • breakers into the degradable material compositions in amounts sufficient to achieve a predefined degradation rate and duration at the time of introducing degradable material into the formation. Accordingly, an ongoing needs exists for wellbore servicing fluids comprising degradable polymers and methods of making and using same.
  • a method of servicing a wellbore comprising providing a degradable polymer and a delayed action construct within a portion of a wellbore, a subterranean formation or both; wherein the delayed action construct comprises (i) a degradation accelerator comprising an alkanolamine, an oligomer of aziridine, a polymer of azridine, a diamine, or combinations thereof, (ii) a solid support, and (iii) an encapsulating material; and placing the wellbore servicing fluid comprising the degradable polymer and delayed action construct into the wellbore, the subterranean formation or both.
  • Figure 1 is a picture of polymer swelling in the presence of water and materials of the present disclosure at 140 °F over a 2-day period.
  • Figures 2A-2C depict various embodiments of the compositions and methods of this disclosure.
  • the methods of the present disclosure generally comprise providing a degradable aliphatic polymer, comprising carboxy functional groups in the polymer backbone derived from hydroxyalkanoic acid monomers, within a portion of a wellbore and/or subterranean formation, introducing a degradation accelerator (DA) to the portion of the wellbore and/or subterranean formation, and allowing the DA to degrade or accelerate the degradation of the degradable polymer.
  • the DA may be in the form of a pumpable fluid (e.g., present in an aqueous carrier fluid, a liquid additive, component of a wellbore servicing fluid, etc).
  • the DA is a component of a solution.
  • the term "solution” does not connote any particular degree of dissolution or order of mixing of the substances present in the solution.
  • the DA is a component of an assembly of materials which functions to accelerate the degradation of one or more of the degradable polymers disclosed herein.
  • the DA material may increase the volume of the degradable polymer by in situ swelling prior to degradation.
  • the portion of the wellbore and/or subterranean formation where the degradable polymer is located may have a temperature of about 140 °F (60 °C) or less.
  • the portion of the wellbore and/or subterranean formation where the degradable polymer is located may have a temperature of greater than about 140 °F (60 °C).
  • at least 20% of the degradation of the degradable polymer may take place within a time frame of less than about three days after the introduction of the DA solution.
  • the DA comprises an alkanolamine, an oligomer of aziridines (e.g., ethyleneimine), a polymer of aziridine, a diamine, derivatives or combinations thereof.
  • the term "derivative" is defined herein to include any compound that is made from one or more of the DAs, for example, by replacing one atom in the DA with another atom or group of atoms, rearranging two or more atoms in the DA, ionizing one of the DAs, or creating a salt of one of the DAs.
  • the DA comprises an alkanolamine.
  • Alkanolamines are chemical compounds that contain a hydroxyl group (i.e., -OH) and an amine group, which may be a primary amine group, a secondary amine group or a tertiary amine group.
  • An alkanolamine suitable for use in the present disclosure is a compound characterized by general Formula I:
  • Ri and R 2 may each independently be hydrogen, an unsubstituted alkyl chain comprising from about 1 to about 6 carbon atoms, or a substituted alkyl chain comprising from about 3 to about 6 carbon atoms.
  • X comprises a substituted or unsubstituted alkylene chain having from about 1 to about 4 carbon atoms.
  • alkyl group is used herein in accordance with the definition specified by IUPAC: a univalent group formed by removing a hydrogen atom from an alkane.
  • alkylene is used herein in accordance with the definition specified by IUPAC: the divalent groups formed from alkanes by removal of two hydrogen atoms from the same carbon atom.
  • substituted when used to describe a group is intended to describe any non-hydrogen moiety that formally replaces a hydrogen in that group and is intended to be non-limiting.
  • Ri and R 2 may both be hydrogen, creating a primary amine; either Ri or R 2 may be a hydrogen, creating a secondary amine; or Ri and R 2 may be substituent groups other than hydrogen, creating a tertiary amine.
  • alkanolamines suitable for use in the present disclosure include monoethanolamine, triethanolamine, diethanolamine, triisopropanolamine, diglycolamine, di-2-propanolamine, N-methyldiethanolamine, 2-amino-2-methyl-l-propanol, 2-piperidineethanol, aminopropanediol and the like.
  • the DA comprises an alkanolamine in the form of an aqueous solution with a concentration of from about 10 weight percent (wt.%) to about 99 wt.%, alternatively from about 40 wt.% to about 85 wt.%, or alternatively from about 50 wt.% to about 80 wt.% based on the total weight of the solution.
  • the alkanolamine solution may have a pH of less than about 11 , alternatively less than about 10, or alternatively less than about 9.
  • the DA comprises oligomers of aziridine or of aziridine derivatives (e.g., ethyl eneimine).
  • aziridine derivatives e.g., ethyl eneimine
  • the disclosure may refer to an oligomer of aziridine and/or an oligomer of an aziridine derivative. It is to be understood that the terms aziridine oligomer and aziridine derivative oligomer herein are used interchangeably.
  • the aziridine oligomers may comprise amines containing at least one secondary and/or at least one tertiary nitrogen, i.e., at least one secondary (-NH-) and/or at least one tertiary (-N ⁇ ) amine group.
  • the aziridine oligomers may also contain primary nitrogens, i.e., primary amine groups (-NH 2 ).
  • the number of monomers in the aziridine oligomer is less than about 100, alternatively less than about 10, or alternatively less than about 5.
  • the aziridine oligomer comprises a linear aziridine oligomer characterized by general Formula II:
  • R 3 comprises a primary amine group (-NH 2 ).
  • R 3 comprises the aziridine ring connected to the repeating oligomer unit through the aziridine ring nitrogen.
  • the aziridine oligomer comprises an aziridine oligomer characterized by general Formula III:
  • m ranges from about 2 to about 100, alternatively from about 2 to about 10, alternatively from about 2 to about 5, or alternatively from about 2 to about 4. While the structure depicted by Formula III only shows one of the hydrogens from the methylene groups of the aziridine ring being substituted with a R4 group, both of the aziridine methylene groups may be substituted. In an embodiment, R4 and any of the other aziridine methylene group substituents comprise methyl groups.
  • the aziridine oligomer comprises a branched aziridine oligomer.
  • the branched aziridine oligomer comprises a branched oligo-ethyleneimine characterized by general Formula IV:
  • repeating units may occur in a total amount of about (x+y) with the total value of (x+y) ranging from about 2 to about 50, alternatively from about 2 to about 30, alternatively from about 2 to about 10, or alternatively from about 2 to about 5.
  • x or y is greater than or equal to 1.
  • the DA comprises an aziridine oligomer in the form of an aqueous solution with a concentration of from about 10 wt.% to about 99 wt.%, alternatively from about 40 wt.% to about 85 wt.%, or alternatively from about 50 wt.% to about 80 wt.% based on the total weight of the solution.
  • the aziridine oligomer solution may have a pH of less than about 1 1, alternatively less than about 10, or alternatively less than about 9.
  • the DA comprises an aziridine polymer, wherein the n and m values in Formula II and Formula III respectively or (x+y) value in Formula IV are greater than 100, alternately greater than 1000, or alternately greater than 10000.
  • the DA comprises an aziridine polymer in the form of an aqueous solution with a concentration of from about 10 wt.% to about 99 wt.%, alternatively from about 40 wt.% to about 85 wt.%, or alternatively from about 50 wt.% to about 80 wt.% based on the total weight of the solution.
  • the aziridine polymer solution may have a pH of less than about 1 1 , alternatively less than about 10, or alternatively less than about 9.
  • An example of an aziridine polymer suitable for use in the present disclosure is HZ-20 crosslinker which is commercially available from Halliburton Energy Services, Inc.
  • the DA comprises a diamine.
  • Diamines are chemical compounds that contain two amine groups.
  • a diamine suitable for use in the present disclosure is a compound characterized by general Formula V:
  • R 3 ⁇ 4 , R 6 , R 7 , and R 8 may each independently be hydrogen, an unsubstituted alkyl chain having from about 1 to about 3 carbon atoms, or a substituted alkyl chain having from about 3 to about 4 carbon atoms and Z comprises an unsubstituted alkylene chain having from about 2 to about 6 carbon atoms, or a substituted alkylene chain having from about 2 to about 6 carbon atoms.
  • Z comprises 2 carbon atoms resulting in an unsubstituted alkylene chain (i.e., ethylene group).
  • at least one of R 5 , R 6 , R 7 , or R 8 is not a hydrogen.
  • the diamine DA does not comprise ethylenediamine.
  • the DA comprises a diamine in the form of an aqueous solution with a concentration of from about 10 wt.% to about 99 wt.%, alternatively from about 40 wt.% to about 85 wt.%), or alternatively from about 50 wt.%> to about 80 wt.%> based on the total weight of the solution.
  • the diamine solution comprises an aqueous fluid (e.g., water) and may have a pH of less than about 11 , alternatively less than about 10, or alternatively less than about 9.
  • the DA comprises amine nitrogens and/or groups which are chemically derivatized to contain an operable functionality or substituent.
  • the operable functionality or substituent may be acted upon in any fashion (e.g., chemically, physically, thermally, etc.) and under any conditions compatible with the process in order to release the DA at a desired time and/or under desired conditions such as in situ wellbore conditions (e.g., temperature, pH induced hydrolysis).
  • in situ wellbore conditions e.g., temperature, pH induced hydrolysis
  • the active form of the DA can be released and made available for polymer degradation.
  • a DA of the type disclosed herein is utilized in high temperature applications (e.g., at temperatures greater than about 90 °C, alternatively greater than about 120 °C, or alternatively greater than about 150 °C).
  • Any suitable operable functionality or substituent or methods for preparing DAs containing operable functionalities or substituents may be employed.
  • a nonlimiting example of such methodologies include acylation of primary or secondary nitrogen atoms or the alcohol groups of the DA molecules utilizing any suitable acylating agent such as acid anhydrides, esters, anhydrides and acid chlorides.
  • An example of a chemically derivatized DA comprising amine nitrogens is tetracetyl ethylene diamine, which upon in situ hydrolysis in a well bore or formation can generate a mixture of amines which function as DAs of the type disclosed herein.
  • a chemically derivatized DA is insoluble in the aqueous fluid.
  • Degradable aliphatic polymers suitable for use in the methods of the present disclosure are those capable of being degraded by water in an aqueous solution through a mechanism described herein or any other suitable mechanism, and comprise carboxy (-COO-) functional groups in the polymer backbone.
  • functional groups that comprise -COO- groups include esters (C-COO-C), carbonates (C-O-COO-C), and carbamates (C-N-COO-C).
  • This degradation may be the result of a chemical reaction with water under neutral pH conditions, acid or base- catalyzed conditions, under thermally- activated conditions, or a combination thereof, and the degradation may occur over time as opposed to immediately.
  • degradation of the degradable polymers may be the result of hydro lytic and/or amino lytic degradation in the presence of DA materials of the type disclosed herein.
  • degradation refers to both the relatively extreme cases of hydrolytic or aminolytic degradation that the degradable polymer may undergo, i.e., heterogeneous (or bulk erosion) and homogeneous (or surface erosion) down to the monomer level, and any stage of degradation in between.
  • polymer or “polymers” as used herein do not imply any particular degree of polymerization; for instance, oligomers are encompassed within this definition provided that such materials are solid particulates, and remain substantially insoluble in an aqueous medium for at least 3 to 8 hours at BHT.
  • the degradable polymer may be capable of releasing a desirable degradation product, e.g., an acid or a base or a neutral molecule, during its degradation.
  • a desirable degradation product e.g., an acid or a base or a neutral molecule
  • the degradable polymers capable of releasing an acid may degrade after a desired time to release an acid, for example, to degrade a filter cake, to lower pH or to reduce the viscosity of a treatment fluid.
  • the degradable polymers capable of releasing acidic, neutral or basic materials may degrade after a desired time to release such materials, for example, to chelate metal ions capable of forming soluble materials to prevent scale depositions in the permeable portions of the formation.
  • the degradable polymer comprises carboxylic acid-derived (i.e., -COO-) functional groups on the polymer backbone.
  • suitable degradable polymers include, but are not limited to, aliphatic polyesters, poly(lactides), poly(glycolides), poly(s-caprolactones), poly(hydroxy ester ethers), poly(hydroxybutyrates), poly( anhydrides), poly(carbonates), poly( ether esters), poly(ester amides), poly(carbamates) and copolymers, blends, derivatives, or combinations of any of these degradable polymers.
  • derivative is defined herein to include any compound that is made from one of the listed compounds, for example, by replacing one atom in the listed compound with another atom or group of atoms, rearranging two or more atoms in the listed compound, ionizing one of the listed compounds, or creating a salt of one of the listed compounds.
  • copolymer as used herein is not limited to copolymerization of a combination of two monomers, but includes any combination of any number of monomers, e.g., graft polymers, terpolymers and the like.
  • suitable copolymers may include an aliphatic polyester that is grafted with polyethylene oxide or polyacrylamide, or block polymers containing one or more blocks containing a carboxy (-COO-) group and another block containing a non-carboxy containing polymer segment such as polyamide, poly(alkylene oxide), poly(anhydride) polyacrylamide or poly(AMPS).
  • Degradable polymers comprising an anhydride bond may be the most reactive of the degradable polymers, e.g., they may have faster degradation rates, even at low temperatures. Suitable DA solutions may enhance the rate of a degradation reaction.
  • the degradable polymer used may be an anhydride, as such degradable polymers are thought to hydrolyze more readily.
  • the degradable polymer may be made to hydrolyze at a higher temperature by increasing the hydrophobicity of the degradable polymer so that water does not reach the hydrolyzable group as readily.
  • the hydrophobicity of a polyanhydride may be increased by increasing the size or carbon number of hydrocarbon groups in these polymers.
  • Degradable polymers that contain an ester bond e.g. polylactide, polyglycolide, etc.
  • Simple melt blends of degradable polymers of different degradation rates and/or physical properties may be utilized (e.g., glass transition temperatures, melting temperature, crystallization temperatures, and crystalline content) provided at least one component of such blends comprises an aliphatic degradable polymer comprising carboxy (-COO) groups in the polymer backbone.
  • aliphatic polyesters such as poly(lactic acid), poly(anhydrides), and poly(lactide)-co-poly(glycolide) copolymers may be used.
  • degradable polymers may depend on the particular application and the conditions involved.
  • degradable polymers may include those degradable materials that release useful or desirable degradation products, e.g., an acid, base or neutral compound(s).
  • useful or desirable degradation products e.g., an acid, base or neutral compound(s).
  • Such degradation products may be useful in a downhole application, e.g., to break a viscosified treatment fluid or an acid soluble component present therein (such as in a filter cake), to lower the pH or to act as scale inhibitors.
  • Other guidelines to consider in selecting a degradable polymer include the time required for the requisite degree of degradation and the desired result of the degradation (e.g., voids).
  • the degradable polymer is an aliphatic polyester, such as poly(lactic acid) (PL A).
  • PL A poly(lactic acid)
  • Other degradable polymers comprising carboxy groups (-COO-) that are subject to hydrolytic and/or aminolytic degradation may also be suitable for use in the present disclosure.
  • the degradable polymer is poly(lactic acid)
  • the poly(lactic acid) may have been synthesized from lactic acid by a condensation reaction or, more commonly, by ring-opening polymerization of cyclic lactide monomer.
  • poly(lactic acid) refers to a polymer made from lactides, lactic acid, or oligomers, without reference to the degree of polymerization.
  • the lactide monomer exists generally in three different forms: two stereoisomers L- and D-lactide and racemic D,L-lactide (meso-lactide).
  • the chirality of the lactide units provides a means to adjust, among other things, degradation rates, as well as physical and mechanical properties.
  • Poly(L-lactide), for instance, is a semicrystalline polymer with a relatively slow hydrolysis rate. This could be desirable in applications of the present disclosure where a slower degradation of the degradable polymers is desired.
  • Poly(D,L-lactide) may be a more amorphous polymer with a resultant faster hydrolysis rate. This may be suitable for other applications where a more rapid degradation may be appropriate.
  • the stereoisomers of lactic acid may be used individually or combined to be used in accordance with the present disclosure.
  • lactic acid stereoisomers can be modified to be used in the present disclosure by, among other things, blending, copolymerizing or otherwise mixing the stereoisomers, by blending, copolymerizing or otherwise mixing high and low molecular weight poly(lactic acid), or by blending, copolymerizing or otherwise mixing a poly(lactic acid) with another polyester or polyesters.
  • Plasticizers may be included in the degradable polymers used in the methods of the present disclosure.
  • the plasticizers may be present in an amount sufficient to provide characteristics that may be desired, for example, to provide tackiness of the generated degradable polymers or to provide improved melt processability.
  • the plasticizers may enhance the degradation rate of the degradable polymers.
  • the plasticizers, if used, are at least intimately incorporated within the degradable polymers.
  • An example of a suitable plasticizer for poly(lactic acid) would include oligomeric lactic acid.
  • plasticizers examples include, but are not limited to, polyethylene glycol (PEG); polyethylene oxide; oligomeric lactic acid; citrate esters (such as tributyl citrate oligomers, triethyl citrate, acetyltributyl citrate, and acetyltriethyl citrate); glucose monoesters; partially hydrolyzed fatty acid esters; PEG monolaurate; triacetin; poly(s-caprolactone); poly(hydroxybutyrate); glycerin- l-benzoate-2,3-dilaurate; glycerin-2-benzoate-l,3-dilaurate; bis(butyl diethylene glycol)adipate; ethylphthalylethyl glycolate; glycerin diacetate monocaprylate; diacetyl monoacyl glycerol; polypropylene glycol (and epoxy derivatives thereof); poly(propylene glycol (and epoxy derivatives thereof); poly(
  • an appropriate plasticizer will depend on the particular degradable polymer utilized. It should be noted that, in certain embodiments, when initially formed, the degradable polymer may be somewhat pliable. But once substantially all of the solvent has been removed, the particulates may harden. More pliable degradable polymers may be beneficial in certain chosen applications.
  • the addition of a plasticizer can affect the relative degree of pliability. Also, the relative degree of crystallinity and amorphousness of the degradable polymer can affect the relative hardness of the degradable polymers. In turn, the relative hardness of the degradable polymers may affect the ability of the DA solutions to degrade the degradable polymer at low temperatures.
  • the DA solution provides a nucleophile capable of participating in the degradation of a degradable polymer in low temperature subterranean environments, for example, at a BHT of less than about 180 °F (82.2 °C), alternatively less than about 160 °F (71.1 °C), or alternatively less than about 140 °F (60 °C).
  • the degradable polymer is designed for high temperature applications by suitably modifying the structure of the polymer.
  • the DA solution may provide a nucleophile to accelerate the degradation rate that would be possible when the polymer is allowed to degrade in the presence of an aqueous fluid not containing the DA solution.
  • a derivatized DA can be used to delay the release of active form DA at high temperatures.
  • high temperatures may be greater than about 180 °F (82.2 °C), alternatively greater than about 250 °F (121.1 °C) or alternatively greater than about 300 °F (148.9 °C).
  • the degradation of the degradable polymer in the presence of the DA solution may take place within a time frame of less than about 1 month, alternatively less than about 2 weeks, alternatively less than about 1 week, or alternatively less than about 3 days.
  • the amount of DA solution that may be used to degrade a degradable polymer in the present disclosure will depend on several factors including, but not limited to, the pH of the DA solution, the nucleophilicity of nucleophiles present in the solution, the degradable polymer, the temperature of the subterranean formation, the nature of the subterranean formation, and the desired time and/or rate of degradation.
  • the molar ratio of the DA solution to the degradable polymer is equivalent (calculated based on the molar quantities of -COO- units in the polymer, and the molar quantities of nucleophilic centers in the DA molecules) or slightly greater than (e.g., about 10%) the stoichiometric ratio.
  • the amount of DA solution is an amount sufficient to degrade equal to or greater than about 20% of the degradable polymer, alternatively equal to or greater than about 50% of the degradable polymer, or alternatively equal to or greater than about 70% of the degradable polymer wherein polymer degradation is measured by degradable polymer weight loss under wellbore conditions over a specified duration.
  • the degradable polymer may swell and absorb water in an aqueous media comprising the DA to a greater extent than the swelling of the degradable polymer observed in the aqueous media without the DA solution.
  • the DA functions initially to swell the degradable polymer and later to degrade the degradable polymer.
  • both swelling and degradation of the degradable polymer in the presence of the DA solution take place simultaneously.
  • the DA may swell but not degrade the degradable polymer, and vice versa.
  • the degradable polymer swells to at least about 2 times its volume, alternatively at least about 5 times, or alternatively at least about 10 times in the presence of the DA solution.
  • the degradable polymer increases in weight, in the presence of DA solution, by at least about 2 times its mass, alternatively at least about 3 times or alternatively at least about 10 times its mass prior to the reduction in weight as a result of degradation of the degradable polymer.
  • the DA solutions disclosed herein may degrade a degradable polymer by way of, inter alia, a nucleophilic substitution reaction at the carbonyl carbon of the -COO- group.
  • Nucleophilic substitution reactions at the carbonyl carbon of a carboxy group are generally thought to follow a nucleophilic addition-elimination mechanism.
  • a nucleophilic substitution reaction occurs when a nucleophile becomes attracted to a full or partial positive charge on an electrophile.
  • the nucleophile forms a chemical bond to the electrophile by donating both bonding electrons and displacing another functional group that was previously bonded to the electrophile.
  • all molecules or ions with a free pair of electrons can act as nucleophiles, however, negative ions (anions) may be more potent than neutral molecules.
  • a neutral nitrogen atom in a molecule (for example, an amine) is more nucleophilic than a neutral oxygen atom in a neutral molecule (for example, in water, alcohol or ether).
  • the nucleophiles of the present disclosure may be neutral or negatively charged Lewis bases.
  • the more basic the ion (the higher the pK a of the conjugate acid), the more reactive the ion may be as a nucleophile.
  • the electrophile is the carbon of a carbonyl group of the -COO- functional group in the polymer backbone.
  • the DA solutions may degrade the degradable polymer through a hydrolytic or aminolytic pathway.
  • the lone electron pair of any of the amine groups or any of the lone electron pairs of any hydroxyl or otherwise oxygen-containing groups in the DA may act as a nucleophile.
  • hydrolysis of a degradable polymer may be expressed by the following exemplary pathway in Scheme I:
  • the DA may serve to provide a more reactive hydroxide ion nucleophile that increases the rate of polymer degradation compared to when the degradation is dependent on reaction with a neutral water molecule.
  • R may be any of the DAs that contain a primary amine group. While Scheme II only depicts the nucleophilic attack by a primary amine group, the same aminolysis pathway may occur via a nucleophilic attack by any secondary amine group of the degradation accelerators described herein.
  • the rate of degradation of the degradable polymers suitable for use in the present disclosure may be influenced by several factors including temperature, the type of chemical bond in the polymer backbone, hydrophilicity or hydrophobicity of the degradable polymer, the molecular weight of the degradable polymer, particle size and shape, porosity, crystallinity, and the presence of low molecular weight compounds (e.g., MW lower than about 500) in the degradable polymer.
  • low molecular weight compounds e.g., MW lower than about 500
  • the degradation of the degradable polymer may be caused by the reaction of water (i.e., hydrolysis) with a labile -COO-bond of the degradable polymer, such as an ester or anhydride bond in a polylactide chain.
  • the reaction rate may be closely related to the ability of the degradable polymer to absorb water.
  • hydrophilic polymers are capable of absorbing a larger quantity of water than a hydrophobic matrix, and therefore, hydrophilic polymers usually degrade more quickly than hydrophobic matrices.
  • a degradable polymer with a greater amorphous content may be attacked more readily by the DA solutions of the present disclosure, and therefore may hydrolyze more readily than crystalline materials.
  • hydrolytic polymer degradation reactions by hydrolysis with water or hydroxide ion (as shown in Scheme I)
  • aminolytic polymer degradation reactions by amine containing groups (as shown in Scheme II) may be taking place simultaneously at different rates of which aminolytic reactions are expected to be fastest followed by hydrolytic reactions with hydroxide ion.
  • Hydrolytic reaction rates with neutral water are expected to be slowest.
  • DA molecules are presumed to increase the rates of polymer degradation by providing the faster degradation pathways.
  • inorganic bases such as alkali metal hydroxides or other pH-increasing inorganic material may increase the rates of degradation by the hydroxide ion pathway described in Scheme I, but the amine DA materials provide faster aminolytic pathways as described in Scheme II, as well as by the hydrolytic pathway described in Scheme 1 due to increased levels of hydroxide ion in the aqueous fluid in the presence of amines.
  • the degradable polymer comprises amorphous PLA.
  • PLA is degraded by contact with an aqueous solution of propylenediamine at temperatures ranging from about 60 °F (15.6 °C) to about 120 °F (48.9 °C).
  • the degradable polymer comprises semi-crystalline PLA.
  • PLA is swollen first by contact with an aqueous solution of triethanolamine and then degraded with another DA solution at temperatures ranging from about 120 °F (48.9 °C) to about 250 °F (121.1 °C).
  • the degradable polymer comprises poly(glycolic acid).
  • poly(glycolic acid) is degraded by contact with an aqueous solution of propylenediamine at temperatures ranging from about 80 °F (26.7 °C) to about 150 °F (65.6°C).
  • the degradable polymer comprises semi-crystalline PLA with a melting point of about 140 °F (60°C).
  • PLA is degraded by contact with an aqueous solution of propylenediamine at temperatures ranging from about 100 °F (37.8°C) to about 200 °F (93.3 °C).
  • the degradable polymer comprises a degradable semi-crystalline copolymer with a melting point of about 300 °F (148.9 °C) having lactic acid as one of the monomers.
  • the PLA copolymer is degraded by contact with an aqueous solution of ethanolamine at temperatures ranging from about 100 °F (37.8 °C) to about 180 °F (82.2 °C).
  • the degradable polymer comprises a degradable semi-crystalline copolymer with a melting point of about 300 °F (148.9 °C) having lactic acid as one of the monomers.
  • the PLA copolymer is degraded by contact with an aqueous solution of tri ethyl enetetraamine at temperatures ranging from about 140 °F (60°C) to about 300 °F (148.9 °C).
  • the degradable polymer comprises a physical blend of degradable semi-crystalline polymers with melting points of 140 °F (60 °C) and 240 °F (115.6°C) and having PLA as one of the blend components.
  • the degradable polymer blend is degraded by contact with an aqueous solution of ethanolamine at temperatures ranging from about 180 °F (82.2 °C) to about 320 °F (160 °C).
  • the degradable polymer is used in combination with a DA solution that causes initial swelling of the polymer, followed by degradation of the degradable polymer.
  • the degradable polymer is used in the presence of more than one DA solution, of which one DA is added for the purpose of swelling the polymer, and the other DA is for the purpose of degrading the polymer.
  • a method of servicing the wellbore comprises introducing to the wellbore a degradable material (DM) and at least a first and a second DA of the type disclosed herein where the first and the second DA differ and where the first and second DAs may be added sequentially or simultaneously.
  • DM degradable material
  • the DA comprises an amine of the type disclosed herein (e.g., alkanolamine, aziridine).
  • the DA may be introduced to the wellbore in the form of a delayed- action construct (DAC) of the type depicted in Figure 2.
  • DAC delayed- action construct
  • the DAC 100 comprises a DA 20 on a solid support 30 which is encapsulated by an encapsulating material 10.
  • the solid support comprises any material that can associate with the DA and is compatible with the other materials of this disclosure.
  • the solid support may be an organic or an inorganic material.
  • the solid support may be further characterized as hydrophobic, alternatively the solid support is hydrophilic.
  • materials suitable for use as the solid support in the DAC include without limitation crushed nut shells (for example, walnuts) diatomaceous earth, clay, zeolite, polymeric resin, lignite, inorganic oxides such as silica, alumina, aluminophosphates or combinations thereof.
  • the solid support comprises a clay.
  • Clays herein refer to aggregates of hydrous silicate particles either naturally-occurring or synthetically-produced, less than 4 micrometers ( ⁇ ) in diameter and may consist of a variety of minerals rich in silicon and aluminum oxides and hydroxides which include variable amounts of other components such as alkali earth metals and water. Clays are most commonly formed by chemical weathering of silicate-bearing rocks, although some are formed by hydrothermal activity. These clays can be replicated in industrial chemical processes. Examples of clays suitable for use in this disclosure include without limitation clays from the following groups: kaolinite, serpentine, illite, chlorite, smectite or combinations thereof.
  • suitable kaolinite group clays include without limitation kaolinite, dickite, halloysite, nacrite, or combinations thereof.
  • suitable illite groups include clay-micas and illite.
  • the solid support comprises a zeolite.
  • Zeolites are three- dimensional, microporous, crystalline solids with well-defined porous structures. Zeolites, which can be either naturally occurring or synthesized, comprise a group of hydrated alumina silicates that are linked in a three dimensional framework through shared oxygen atoms. Examples of zeolites suitable for use in this disclosure include without limitation analcime, chabazite, heulandite, natrolite, phillipsite, stilbite, or combinations thereof.
  • the solid support comprises a polymeric resin such as for example an ion-exchange resin.
  • Ion exchange resins are polymeric resins that contain charged functional groups.
  • the base polymer is usually a crosslinked material such as polystyrene that is crosslinked with a vinyl polymer.
  • polymeric resins suitable for use in this disclosure include without limitation diethyl aminoethyl, or quaternary aminoethyl substituted polystyrene, Mono-Q®, Mono-S ® , or combinations thereof, all of which are commercially available from Pharmacia Biotech.
  • the solid support comprises a lignite.
  • Lignite is a brownish black coal that has high inherent moisture content and high ash content compared to bituminous coal. It is a heterogenous mixture and often has a woodlike texture.
  • the solid support may be obtained from natural sources, alternatively the substrate may comprise synthetic analogs of the materials described herein.
  • the solid support may be present in amount the DAC of from about 30 wt.% to about 80 wt.%, alternatively from about 40 wt.% to about 70 wt.%, or alternatively from about 50 wt.% to about 60 wt.% based on the dry weight of DAC.
  • the DAC comprises an encapsulating material.
  • the encapsulating material may function as a barrier that inhibits disassociation of the DA from the solid support.
  • the encapsulating material functions as a substantially impenetrable barrier that prevents disassociation of the DA from the solid support.
  • disassociation of the DA from the solid support occurs subsequent to a reduction in structural integrity of the encapsulating material that removes some portion of the substantially impenetrable barrier.
  • the function of the DAC is delayed for the time period necessary to affect the structural integrity of the encapsulating material.
  • the structural integrity of the encapsulating material may be affected by any number of factors such as wellbore temperature and the presence of materials that decrease the structural integrity of the encapsulating material.
  • the encapsulating material functions as an external coating through which the encapsulated material (e.g., DA) diffuses.
  • the function of the DAC is delayed for the time period necessary for the DA to pass through the encapsulating material and into the wellbore and/or wellbore servicing fluids.
  • Examples of other encapsulating materials suitable for use in this disclosure include but are not limited to EDPM rubber, polyvinyldichloride, nylon, waxes, polyurethanes, cross- linked partially hydrolyzed acrylics, cross-linked polyurethane, a drying oil such as tung oil and linseed oil, or combinations thereof.
  • the encapsulating material comprises biopolymers, polysaccharides, hydrocolloids, or gums.
  • the encapsulating material upon contact with water, may hydrate the outer surface forming a gel layer that encloses the encapsulated material (e.g., DA).
  • the encapsulating material may comprise cellulose-based polymers, cellulose ethers, methylcellulose, hydroxypropyl methylcellulose, ethylhydroxyethylcellulose, methylhydroxyethylcellulose, bacterial and plant based gums, xanthan, diutan, gellan, gum tragacanth, pestan, and the like, or combinations thereof.
  • a DAC of the type disclosed herein is prepared using any suitable methodology.
  • the DA may be associated with the solid support such as by spray- coating the DA onto the solid support or by impregnating the solid support with a DA.
  • the resulting material is termed a DA/solid support.
  • the DA/solid support can be further associated with an encapsulating material, all of the type disclosed herein.
  • the DAC/solid support can be encapsulated by spray coating a variety of materials thereon.
  • the liquid DA may be encapsulated in a particulate porous solid material that remains dry and free flowing after absorbing the liquid DA and through which the DA slowly diffuses.
  • particulate porous solid materials include but are not limited to crushed nut shells (for example, walnuts) diatomaceous earth, zeolites, silica, alumina, metal salts of alumino-silicates, clays, hydrotalcite, styrenedivinylbenzene-based materials, cross-linked polyalkylacrylate esters, cross-linked modified starches, or combinations thereof.
  • an external coating of an encapsulating material through which a DA slowly diffuses can be placed on the porous solid material.
  • a DAC 100 placed in the wellbore may have encapsulation material 10 whose structural integrity is comprised allowing the DA 20 to disassociate from the solid support 30.
  • the DAC comprises an encapsulation material 10 and DA 20 associated with the solid support 30.
  • the DA 20 may dissociate from the solid support 30 and migrate through the encapsulation material 30 into the wellbore servicing area.
  • DAs and/or DMs disclosed herein may be included in or in combination with any suitable wellbore servicing fluid (WSF).
  • WSF wellbore servicing fluid
  • a "servicing fluid” refers to a fluid used to drill, complete, work over, fracture, repair, or in any way prepare a wellbore for the recovery of materials residing in a subterranean formation penetrated by the wellbore.
  • servicing fluids include, but are not limited to, cement slurries, drilling fluids or muds, spacer fluids, fracturing fluids or completion fluids. It is to be understood that "subterranean formation” encompasses both areas below exposed earth and areas below earth covered by water such as ocean or fresh water.
  • the aqueous fluids that may be utilized in the WSF may be fresh water, saltwater (e.g., water containing one or more salts dissolved therein), brine (e.g., saturated saltwater), or seawater.
  • an aqueous fluid may be present in the WSF used in the methods of the present disclosure in an amount in the range of from about 40 wt.% to about 99 wt.% based on the total weight of the WSF.
  • an aqueous fluid may be present in the WSF used in the methods of the present disclosure in an amount in the range of from about 20 wt.% to about 80 wt.% based on the total weight of the WSF.
  • the WSF comprises a suspending agent.
  • the suspending agent in the WSF may function to prevent the DA particulates (e.g., aziridine oligomer derivatives) from settling in the suspension during its storage or before reaching its downhole target (e.g., a portion of the wellbore and/or subterranean formation comprising degradable polymer).
  • the suspending agent in the WSF may function to prevent the fully or partially degraded or non-degraded DM from settling during placement or flow back subsequent to treatment with a DA.
  • the suspending agent may comprise microfine particulate materials, (e.g., less than about 1 micron) hereinafter referred to as colloidal materials, clays and/or viscosifying or gel forming polymers.
  • Nonlimiting examples of colloidal materials suitable for use in the present disclosure include carbon black, lignite, brown coal, humic acid, styrene-butadiene rubber latexes, polyvinyl alcohol latexes, acetate latexes, acrylate latexes, precipitated silica, fumed/pyrogenic silica, and viscoelastic surfactant micelles.
  • Nonlimiting examples of clays suitable for use in the present disclosure include bentonite, attapulgite, kalonite, meta kalonite, laponite, hectorite and sepiolite.
  • Nonlimiting examples of viscosifying or gel forming polymers suitable for use in the present disclosure include a copolymer of 2-acrylamido-2-methylpropane sulfonic acid and N,N- dimethylacrylamide, carragenan, scleroglucan, xanthan gum, guar gum, hydroxypropylguar, hydroxyethylcellulose, carboxymethylhydroxyethylcellulose, welan gum, succinoglycan, copolymers or terpolymers of acrylamidomethyl propane sulfonate, N,N-dimethylacrylamide, acrylic acid, and vinyl acetate.
  • the suspending agent is present in the WSF in an amount of from about 0.01 wt.% to about 10 wt.%, alternatively from about 0.1 wt.% to about 5 wt.%, or alternatively from about 0.25 wt.% to about 1.5 wt.% based on the total weight of the WSF.
  • the WSF may further comprise additional additives as deemed appropriate by one of ordinary skill in the art, with the benefit of this disclosure.
  • Additives may be used singularly or in combination.
  • additional additives include, but are not limited to, pH-adjusting agents, pH-buffers, oxidizing agents, enzymes, lost circulation materials, scale inhibitors, surfactants, clay stabilizers, fluid loss control additives, or combinations thereof.
  • Nonlimiting examples of such additives are also described in U.S. Patent Publication No. 2010/0273685 Al , which is incorporated by reference herein in its entirety.
  • the DM may be introduced into a subterranean formation for any of a number of uses.
  • degradable polymers may be used in subterranean operations as fluid loss control particles, diverting agents, filter cake components, drilling fluid additives, cement additives, and the like.
  • the degradable polymer may be in a mechanical form, such as in a downhole tool (e.g., plugs, sleeves, and the like), or as a coating on a metallic tool.
  • the degradable polymer may be present in a filter cake that is present in the subterranean formation.
  • the degradable polymer may be introduced into the formation as part of the fluid that forms the filter cake, such that the filter cake contains the degradable polymer.
  • the degradable polymer may be capable of releasing a desirable degradation product, e.g., an acid, during its hydrolysis.
  • the acid released by certain degradable polymers may be used to facilitate a reduction in the viscosity of a fluid or to degrade a filter cake, as well as for numerous other functions in subterranean operations. Accordingly, the methods of the present disclosure may be used in any subterranean operation in which the degradation of a degradable polymer is desired.
  • a degradable polymer may be introduced into a subterranean formation by including the degradable polymer in the WSF (e.g., a fracturing fluid or an acidizing fluid).
  • a WSF may comprise an aqueous fluid (e.g., an aqueous carrier fluid) and a degradable polymer.
  • the WSF further may comprise one or more of the following: a suspending agent, a crosslinking agent, bridging agents, and a proppant.
  • a degradable polymer may be included in the WSFs in an amount sufficient for a particular application.
  • a degradable polymer may be present in the WSF in an amount sufficient to release a desired amount of acid.
  • the amount of the released acid may be sufficient to reduce the viscosity of the treatment fluid to a desired level.
  • the amount of the released acid may be sufficient to facilitate the degradation of an acid-soluble component, for example, an acid-soluble component of a filter cake, an acid-soluble component adjacent to a filter cake, or an acid-soluble component (e.g., calcium carbonate) of a proppant pack.
  • a degradable polymer may be present in the WSF in an amount in the range of from about 1% to about 30% by weight of the WSF. In certain embodiments, a degradable polymer may be present in the WSF in an amount in the range of from about 3% to about 10% by weight of the WSF.
  • a degradable polymer may be present in the WSF in an amount in the range of from about 3% to about 10% by weight of the WSF.
  • WSFs in addition to introducing degradable polymers into a wellbore and/or subterranean formations, may also be used to introduce a DA solution or a DAC into a wellbore and/or subterranean formation.
  • a WSF comprising a DA or a DAC proximate to or in contact with the degradable material present in the wellbore and/or subterranean formation.
  • a WSF may comprise a DA solution or DAC in addition to or in lieu of a DM.
  • Such WSFs may be used to hydrolyze degradable polymers present in the fluid or present in the wellbore and/or subterranean formation (e.g., in a filter cake, in a proppant pack, or in a downhole tool).
  • the DA solution may be present in the WSF in an amount in the range of from about 0.1 wt.% to about 50 wt.% based on the total weight of the WSF. In some embodiments, the DA solution may be present in an amount in the range of from about 1 wt.%) to about 15 wt.%> based on the total weight of the WSF.
  • the amount of DAC may be in the range of from about 10 wt.% to about 60 wt.% by weight of DM, and the amount of DAC will be dependent on the amount of DA present in DAC, the desired rate of DM degradation and the desired duration of DM degradation.
  • the DA solution or DAC may be placed in the formation prior to the placement of the degradable material.
  • the DA solution or DAC may be made to contact the degradable materials by drawing down the pressure on the wellbore, for example by putting the well back on production.
  • the DA solution (or DAC) and degradable material may be pumped together along with the well treatment fluid (e.g., a fracturing fluid).
  • the DA solution (or DAC) may be placed in the wellbore to contact the degradable material already placed in the wellbore.
  • the DM and DA may be placed into the wellbore in any suitable order or combination necessary to meet the objectives of a given wellbore service, for example simultaneously (including one or more DMs combined with one or more DAs (or DACs) in a common WSF or a first WSF comprising one or more DMs placed simultaneously with a second WSF comprising one or more DAs (or DACs), such as pumping the first WSF down the flowbore of a tubular placed in a wellbore and pumping the second WSF down an annulus between the tubular and the wellbore) or sequentially (e.g., a first WSF comprising one or more DMs or DACs pumped ahead or behind a second WSF comprising one or more DAs (or DACs) , for example as one or more slugs of material that may stay constant or vary in sequence such as DM/DA; DM/DAC; DA/DM; DAC/DM; DM/DA/DM
  • a WSF comprising a degradable polymer may be introduced to a wellbore and/or subterranean formation simultaneously with the introduction of a DA solution (or DAC) that does not adversely react with or otherwise interfere with any aspect of the WSF.
  • a DA solution or DAC
  • a DA solution may be introduced to the wellbore and/or subterranean formation subsequent to the introduction of the degradable polymer.
  • a degradable polymer which may be provided in any of a number of forms, e.g., in a filter cake, may be contacted with a DA solution (or DAC) subsequent to the introduction of the degradable polymer into the wellbore and/or subterranean formation.
  • a DA solution or DAC
  • the present disclosure provides a method of treating at least a portion of a wellbore and/or subterranean formation comprising providing a WSF that comprises an aqueous fluid, a degradable polymer capable of releasing an acid, and a DA solution or DAC solid and introducing the WSF into the wellbore and/or subterranean formation.
  • the DA solution hydrolyzes the degradable polymer so as to release an acid that facilitates a reduction in the WSF's viscosity.
  • the WSF comprises a DAC and the DA is released from the solid support.
  • the DA may migrate through the encapsulating material or the structural integrity of the encapsulating material is compromised sufficiently to allow release of the DA.
  • the released DA may contact and accelerate the degradation of the degradable polymer.
  • a degradable polymer may be provided in a wellbore and/or subterranean formation by a fluid (e.g., a drill-in and servicing fluid) capable of forming a filter cake on the face of a portion of a wellbore and/or subterranean formation.
  • a fluid e.g., a drill-in and servicing fluid
  • Such fluids are used, among other things, to minimize damage to the permeability of the subterranean formation.
  • desirable fluids such as hydrocarbons, may be produced, the filter cake should be removed.
  • a DA solution or DAC may be introduced into a wellbore and/or subterranean formation to facilitate the removal of a filter cake that comprises a degradable polymer.
  • the DA solution or DAC degrades the degradable polymer.
  • a DA or DAC of the type disclosed herein may be used in conjunction with stimulation techniques designed to increase the complexity of fractures by first plugging the pores in existing fractures and then diverting the fracturing fluid to initiate other fractures.
  • ACCESSFRAC service is an example of such a stimulation service commercially available from Halliburton Energy Services, Inc.
  • the pores may be plugged with a diverter material such as the ones described in the present disclosure.
  • BIOVERT NWB diverting system is an example of a temporary polyester-based diverting agent commercially available from Halliburton Energy Services, Inc.
  • the degradable polymers may comprise a multimodal particle size distribution, for example, bimodal or trimodal particle size distributions.
  • the degradable polymer comprising multimodal polymer particle size distribution may contain particles with sizes ranging from about 5 mm to about 20 microns, alternatively from about 3mm to about 50 microns, or alternatively from about lmm to about 100 microns.
  • the particles after placement may be treated with a swelling DA solution which will swell the degradable polymer particles forming a continuous mass of diverting plug before the degradation process sets in.
  • the DA solution or DAC may be advantageously used for removing the diverter plugs under wellbore conditions where the BHT is less than about 320 °F (160 °C) , alternatively less than about 140 °F (60 °C), or alternatively less than about 100 °F (37.8 °C).
  • the wait time for putting the well on production may be advantageously shortened to less than about 1 week, alternatively less than about 3 days.
  • the diverting plug can comprise solid materials comprised of DM and DAC, and plug can be designed to self-degrade at predefined degradation rates, and duration by combining the two solid materials in weight ratios determined in the laboratory based on downhole combinations.
  • the DA or DAC of the type disclosed herein may be used in conjunction with stimulation techniques which are designed to create highly conductive fractures.
  • PILLAR FPvAC stimulation technique is an example of such a technique and is commercially available from Halliburton Energy Services, Inc.
  • the degradable polymer may be advantageously soaked and/or immersed in a DA solution and then pumped downhole, thereby removing the need to place the DA solution separately.
  • the degradable polymer may be soaked in a DA solution for a time period of from about 6 hours to about 72 hours, alternatively from about 12 hours, to about 48 hours or alternatively from about 16 hours to about 24 hours. While the degradable polymer may function as a diverter downhole, the DA solution will concurrently degrade the polymer in an advantageously shorter time frame of less than about 1 week, alternatively less than about 3 days.
  • the degradable polymer e.g., PLA
  • the degradable polymer may be used at a BHT of less than about 140 °F (60 °C).
  • the degradable polymer may be used for assembling a degradable filter cake with drill-in fluids.
  • the degradable polymer comprises multimodal polymer particles with sizes ranging from about 1 mm to about 20 microns, alternatively from about 0.5 mm to about 50 microns, or alternatively from about 500 microns to about 100 microns.
  • the filter cake may perform its intended function and it may be subsequently advantageously removed with a DA solution or DAC of the type disclosed herein having a pH of less than about 1 1 , alternatively less than about 10, or alternatively less than about 9.
  • a first embodiment which is a method of servicing a wellbore comprising providing a degradable polymer and a delayed action construct within a portion of a wellbore, a subterranean formation or both; wherein the delayed action construct comprises (i) a degradation accelerator comprising an alkanolamine, an oligomer of aziridine, a polymer of azridine, a diamine, or combinations thereof, (ii) a solid support, and (iii) an encapsulating material; and placing the wellbore servicing fluid comprising the degradable polymer and delayed action construct into the wellbore, the subterranean formation or both.
  • a second embodiment which is the method of the first embodiment wherein the alkanolamine comprises ethanolamine, triethanolamine, monoethanolamine, diethanolamine, diglycolamine, di-2-propanolamine, N-methyldiethanolamine, 2-amino-2-methyl-l-propanol, 2- piperidineethanol, aminopropane diol, or combinations thereof.
  • a third embodiment which is the method of the second embodiment wherein the alkanolamine comprises a compound characterized by Formula I:
  • Ri and R 2 may each independently be hydrogen, an unsubstituted alkyl chain comprising from about 1 to about 6 carbon atoms, or a substituted alkyl chain comprising from about 3 to about 6 carbon atoms and X comprises a substituted or unsubstituted alkylene having from about 1 to about 4 carbon atoms.
  • a fourth embodiment which is the method of any of the first through third embodiments wherein the oligomer of aziridine comprises a linear aziridine oligomer, a branched aziridine oligomer, any derivatives thereof, or any combinations thereof.
  • a fifth embodiment which is the method of any of the first through fourth embodiments wherein the oligomer of aziridine comprises a compound characterized by Formula II:
  • n may range from about 2 to about 100 and R 3 comprises a primary amine.
  • a sixth embodiment which is the method of any of the first through fourth embodiments wherein the oligomer of aziridine comprises a compound characterized by Formula
  • a seventh embodiment which is the method of any of the first through fourth embodiments wherein the oligomer of aziridine comprises a compound characterized by Formula
  • repeating units occur in a total amount or aoout x+y) wherein the total value of ( x+y) ranges from about 2 to about 50.
  • An eighth embodiment which is the method of any of the first through seventh embodiments wherein the diamine comprises a compound characterized by general Formula V:
  • R 5 , R 6 , R 7 , and R 8 may each independently be hydrogen, an unsubstituted alkyl chain having from about 1 to about 3 carbon atoms, or a substituted alkyl chain having from about 2 to about 4 carbon atoms and Z comprises a substituted or unsubstituted alkylene chain having from about 2 to about 6 carbon atoms.
  • a ninth embodiment which is the method of any of the first through eighth embodiments wherein the degradation accelerator is present in the wellbore servicing fluid in an amount of from about 0.1 wt.% to about 50 wt.% based on the total weight of the wellbore servicing fluid.
  • a tenth embodiment which is the method of any of the first through ninth embodiments wherein the degradable polymer comprises an aliphatic polyester, a poly(lactide), a poly(glycolide), a poly(s-caprolactone), a poly(hydroxy ester ether), a poly(hydroxybutyrate), a poly(anhydride), a polycarbonate, a polyether ester, a polyester amide, a copolymer thereof, or any combinations thereof.
  • An eleventh embodiment which is the method of any of the first through tenth embodiments wherein the degradable polymer comprises a copolymer of lactic and gycolic acid.
  • a twelfth embodiment which is the method of any of the first through eleventh embodiments wherein the degradable polymer further comprises a plasticizer.
  • the plasticizer comprises a polyethylene glycol (PEG); a polyethylene oxide; an oligomeric lactic acid; a citrate ester; a glucose monoester; a partially hydrolyzed fatty acid ester; a PEG monolaurate; a triacetin; a poly(s-caprolactone); a poly(hydroxybutyrate); a glycerin- l-benzoate-2,3-dilaurate; a glycerin-2-benzoate-l ,3-dilaurate; a bis(butyl diethylene glycol)adipate; an ethylphthalylethyl glycolate; a glycerin diacetate monocaprylate; a diacetyl monoacy
  • PEG polyethylene glycol
  • the plasticizer comprises a polyethylene glycol (PEG
  • a fourteenth embodiment which is the method of any of the first through thirteenth embodiments wherein the solid support comprises a clay, zeolite, polymeric resin, lignite, inorganic oxide or combinations thereof.
  • a fifteenth embodiment which is the method of any of the first through fourteenth embodiments wherein the solid support comprises a particulate porous material.
  • a sixteenth embodiment which is the method of the fifteenth embodiment wherein the particulate porous material comprises diatomaceous earth, silica, alumina, metal salts of alumino- silicates, clays, hydrotalcite, styrenedivinylbenzene-based materials, cross-linked polyalkylacrylate esters, cross-linked modified starches, or combinations thereof.
  • a seventeenth embodiment which is the method of any of the first through sixteenth embodiments wherein the encapsulating material comprises cellulose-based polymers, cellulose ethers, methylcellulose, hydroxypropyl methylcellulose, ethylhydroxyethylcellulose, methylhydroxyethylcellulose, bacterial and plant based gums, xanthan, diutan, gellan, gum tragacanth, pestan, or combinations thereof.
  • An eighteenth embodiment which is the method of any of the first through seventeenth embodiments wherein the encapsulating material comprises EDPM rubber, polyvinyldichloride, nylon, waxes, polyurethanes, cross-linked partially hydrolyzed acrylics, cross-linked polyurethane or combinations thereof.
  • a nineteenth embodiment which is the method of any of the first through eighteenth embodiments wherein the encapsulating material comprises tung oil, linseed oil, or combinations thereof.
  • a twentieth embodiment which is the method of any of the first through nineteenth embodiments wherein the degradation accelerator is spray coated onto the solid support.
  • the crystallinity of the polylactic acid containing samples was measured by Differential Scanning Calorimeter (DSC) by heating the sample from room temperature to 392 °F (200 °C), holding the sample at 392 °F (200 °C) for 30 minutes, cooling it to room temperature and reheating to 392 °F (200 °C) at a rate of 10 °C/minute.
  • Glass transition temperatures (T g ), melting temperatures (T m ) and crystallization temperatures (T c ) observed during the second cycle are reported in Table 1.
  • Polyglycolic acid (Sample 5) was not characterized by DSC. A sample for which the area of the melting peak increased substantially during the second heating cycle is deemed to be originally a low crystallinity material. All others are referred to as amorphous or semi-crystalline materials.
  • the degradation tests were performed by first grinding the materials and sieving them. The particles that went through a 20 mesh sieve were collected and used in the degradation studies. A solid sample of 1 gram of the degradable polymer was placed in 100ml tap water and about a stoichiometric amount of DA was added. The stoichiometric amounts of the DA solution required were calculated by dividing the weight of degradable polymer sample by the molecular weight of monomer (lactic acid in the case of PLA based polymer and glycolic acid in the case of polyglycolic acid) to obtain moles of -COO- bonds present in the polymer, and calculating the weight of degrading agent containing equivalent moles of nitrogen atoms.
  • Alkanolamines used in the study included ethanolamine (EA), triethanolamine (TEA) and triisopropanolamine (Formula I).
  • EA ethanolamine
  • TEA triethanolamine
  • Formula I triisopropanolamine
  • the progress of the polymer degradation was measured by determining the remaining weight of degradable polymer at periodic intervals by filtering the polymer mixture, drying the undissolved solid, and measuring its weight.
  • the results for samples utilizing an aziridine oligomer, aziridine polymer and diamine as the DA are presented in Tables 2 and 3.
  • Table 2 presents the results from measuring remaining polymer weights at 140 °F (60 °C) after 3, 6 and 9 days.
  • Table 3 provides results for % polymer degradation of semicrystalline PLA and semicrystalline polymer blends Samples 3 and 4 respectively after 25 days at 140 °F (60 °C).
  • polymers of aziridine may be more suitable for swellable degradable semicrystalline polymers for improved fluid diversion efficiency, fluid loss control and filter cake fluid loss control efficiency.
  • Swollen particles contain minimized interparticle porosity; encourage particle fusion forming a continuous layer of filter cake, or a single fused mass of plug blocking flow of fluid more effectively.
  • Ethylene diamine containing only primary amine groups was more effective as a degradation accelerator than the azidirine oligomer, TETA, which contained the same number of primary amine groups but also contained two secondary amine groups. None of the DAs were effective in accelerating degradation of the most crystalline polymer blend (Sample 4) and they all increased the degradable polymer weight due to swelling even after 9 days.
  • R RL +k* (RU-RL), wherein k is a variable ranging from 1 percent to 100 percent with a 1 percent increment, i.e., k is 1 percent, 2 percent, 3 percent,
  • any numerical range defined by two R numbers as defined in the above is also specifically disclosed.
  • Use of the term "optionally” with respect to any element of a claim is intended to mean that the subject element is required, or alternatively, is not required. Both alternatives are intended to be within the scope of the claim.
  • Use of broader terms such as comprises, includes, having, etc. should be understood to provide support for narrower terms such as consisting of, consisting essentially of, comprised substantially of, etc.

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Abstract

L'invention concerne un procédé permettant d'entretenir un puits de forage, consistant à utiliser un polymère dégradable et une construction à action retardée dans une partie d'un puits de forage, d'une formation souterraine, ou des deux ; la construction à action retardée comprenant (i) un accélérateur de dégradation comprenant une alcanolamine, un oligomère d'aziridine, un polymère d'aziridine, une diamine ou des combinaisons de ces derniers, (ii) un support solide, et (iii) un matériau d'encapsulation ; et à placer le fluide d'entretien de puits de forage comprenant le polymère dégradable et la construction à action retardée dans le puits de forage, dans la formation souterraine ou dans les deux.
EP14761514.0A 2013-10-29 2014-08-25 Procédés et compositions comprenant des polymères dégradables pour l'entretien de puits de forage Withdrawn EP2943551A1 (fr)

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US14/065,701 US9410076B2 (en) 2012-10-25 2013-10-29 Wellbore servicing methods and compositions comprising degradable polymers
PCT/US2014/052546 WO2015065575A1 (fr) 2013-10-29 2014-08-25 Procédés et compositions comprenant des polymères dégradables pour l'entretien de puits de forage

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WO2017176952A1 (fr) 2016-04-08 2017-10-12 Schlumberger Technology Corporation Gel polymère pour applications de régulation d'eau
DE102021202598A1 (de) 2021-03-17 2022-09-22 Fraunhofer-Gesellschaft zur Förderung der angewandten Forschung eingetragener Verein Stabilisator-Zusammensetzung, Verwendung der Stabilisator-Zusammensetzung, Verfahren zur Stabilisierung von Kondensationspolymeren gegen hydrolytischen Abbau sowie hydrolysestabilisierte Zusammensetzung und Formkörper oder Formteil hieraus
CN113773823B (zh) * 2021-07-29 2023-05-02 内蒙古浦景聚合材料科技有限公司 适用于井下压裂作业的可降解暂堵球及其制备方法
DE102022206467A1 (de) 2022-06-27 2023-12-28 Fraunhofer-Gesellschaft zur Förderung der angewandten Forschung eingetragener Verein Stabilisator-Zusammensetzung, Verwendung der Stabilisator-Zusammensetzung, Verfahren zur Stabilisierung von Kondensationspolymeren gegen hydrolytischen Abbau sowie hydrolysestabilisierte Zusammensetzung und Formkörper oder Formteil hieraus

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US20060169448A1 (en) * 2005-02-01 2006-08-03 Halliburton Energy Services, Inc. Self-degrading cement compositions and methods of using self-degrading cement compositions in subterranean formations
US20060169450A1 (en) * 2005-02-02 2006-08-03 Halliburton Energy Services, Inc. Degradable particulate generation and associated methods
US7678745B2 (en) * 2007-09-24 2010-03-16 Schlumberger Technology Corporation Viscosity reduction
AU2012213241B2 (en) * 2011-01-31 2014-10-23 Halliburton Energy Services, Inc. Increasing fracture complexity in ultra-low permeable subterranean formation using degradable particulate

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AU2014342957B2 (en) 2016-06-02
CA2908429C (fr) 2018-06-19
CA2908429A1 (fr) 2015-05-07
WO2015065575A1 (fr) 2015-05-07
AR097745A1 (es) 2016-04-13

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