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WO2015102802A1 - Procédés d'entretien de puits de forage et compositions comprenant des polymères dégradables - Google Patents

Procédés d'entretien de puits de forage et compositions comprenant des polymères dégradables Download PDF

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Publication number
WO2015102802A1
WO2015102802A1 PCT/US2014/068551 US2014068551W WO2015102802A1 WO 2015102802 A1 WO2015102802 A1 WO 2015102802A1 US 2014068551 W US2014068551 W US 2014068551W WO 2015102802 A1 WO2015102802 A1 WO 2015102802A1
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Prior art keywords
acid
wellbore
polymer
subterranean formation
degradable polymer
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English (en)
Inventor
B. Raghava Reddy
Janette CORTEZ
Andrea Ontiveros
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Halliburton Energy Services Inc
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Halliburton Energy Services Inc
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Priority claimed from US14/146,821 external-priority patent/US9359543B2/en
Application filed by Halliburton Energy Services Inc filed Critical Halliburton Energy Services Inc
Priority to CA2931998A priority Critical patent/CA2931998C/fr
Publication of WO2015102802A1 publication Critical patent/WO2015102802A1/fr
Anticipated expiration legal-status Critical
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    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/02—Well-drilling compositions
    • C09K8/03—Specific additives for general use in well-drilling compositions

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 formation .
  • Natural resources such as gas, oil, and water residing in a subterranean formation or zone are often recovered by drilling a wellbore into the subterranean formation while circulating a drilling fluid in the wellbore.
  • a string of pipe e.g. , casing
  • the drilling fluid may then be circulated through the interior of the pipe and out of the subterranean formation through the annulus formed between the subterranean formation and the pipe.
  • primary cementing may be 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.
  • Secondary cementing operations may also be performed .
  • PHA poly(lactic acid)
  • 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 degrading agent or some other treatment chemical may be coated, encapsulated, or encaged with a degradable polymer and used in a subterranean operation such that the degrading agent may not be substantially exposed to the subterranean environment until the degradable polymer coating the degrading agent substantially degrades.
  • degradation of a water-degradable polymer with suitable chemical composition and physical properties may be most desirably achieved over a time period ranging from about few days to about a few weeks at bottom hole temperatures ("BHT") of above about 60°C ( 140°F) .
  • BHT bottom hole temperatures
  • many well bores have a BHT that may be lower than 60°C.
  • a relatively longer time e.g. , weeks or even months
  • degradable polymers that are stable for desired durations at high temperatures under downhole conditions may be needed .
  • Such materials may be required to be more resistant to hydrolytic degradation (i.e.
  • the percentage of polymer degradation needed may be as low as 20%. If used as a plug or filter cake, the degradable polymer may degrade to an extent sufficient to loosen packed particle density so that a flowing fluid may break up and flow out remaining un-degraded particulate material .
  • the quantities of the degradable polymer required to accomplish a desired objective may depend on, among other things, the type of application .
  • the amounts of degradable polymer needed may be as high as about 250 to about 500 lbs/1000 gal("gal/Mgal"). It may be beneficial to reduce the amount of polymer utilized to accomplish a particular operation without sacrificing the intended performance objectives, which may reduce the cost of the.
  • Figure 1 is a picture of a degradable polymer swelling in the presence of water and materials described in some embodiments herein at 140°F over a 2-day period .
  • FIG. 2A-C depicts various embodiments of the delayed- action construct (“DAC”) compositions described herein.
  • DAC delayed- action construct
  • Figure 3 depicts an embodiment of a system configured for delivering the fluids comprising the DAs and/or DACs of the embodiments described herein to a downhole location.
  • Figure 4 shows the degradation rate of a degradable polymer using after exposure to degrading agents as disclosed in some embodiments herein.
  • 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 formation.
  • the degradable polymers and diverting agents disclosed herein may be used in any subterranean formation operation that may benefit from consolidation of particulates.
  • treatment operations may include, but are not limited to, a drilling operation; a stimulation operation; an acidizing operation; an acid-fracturing operation; a sand control operation; a completion operation; a scale inhibiting operation; a water-blocking operation; a clay stabilizer operation; a fracturing operation; a frac-packing operation; a gravel packing operation; a wellbore strengthening operation; a sag control operation; and any combination thereof.
  • the degradable polymers and diverting agents described herein may be used in any non-subterranean operation that may benefit from their properties. Such operations may be performed in any industry including, but not limited to, oil and gas, mining, chemical, pulp and paper, aerospace, medical, automotive, and the like.
  • compositions and methods are described herein in terms of “comprising” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. When “comprising” is used in a claim, it is open-ended.
  • 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, and the like).
  • 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 material may increase the volume of the degradable polymer by in situ swelling prior to degradation.
  • the DA material may be in a particulate form, which may be included in a pumpable fluid in which it is completely or partially soluble.
  • 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 higher than about 140°F (60°C) . In some exemplary embodiments, at least 20% of the degradation of the degradable polymer may take place within a timeframe of less than about three days after the introduction of the DA.
  • the DA comprises an alkanolamine, an oligomer of an aziridine (e.g. , ethyleneimine), a polymer of aziridine, a diamine, any derivative thereof, or any combination thereof.
  • these DAs may be liquids ("DA solution”) at room temperature in their pure state.
  • the DA is a particulate salt DA (i.e. , a "particulate salt degradation accelerator"), which may be referred to herein simply as "particulate DA,” formed by creating a solid form by chemical derivatization of an alkanolamine, an oligomer of an aziridine (e.g.
  • DA ethyleneimine
  • a polymer of aziridine a diamine
  • any derivative thereof any combination thereof.
  • DA will collectively refer to both the DA solution and the particulate DA materials described herein .
  • 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 :
  • Rl and R2 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 may comprise 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 form 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 .
  • Rl and R2 may both be hydrogen, creating a primary amine; either Rl or R2 may be a hydrogen, creating a secondary amine; or Rl and R2 may be substituent groups other than hydrogen, creating a tertiary amine.
  • Nonlimiting examples of 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. , ethyleneimine) .
  • aziridine derivatives e.g. , ethyleneimine
  • 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 (-N H-) and/or at least one tertiary (-N ⁇ ) amine group) .
  • the aziridine oligomers may also contain at least one primary nitrogen (i. e. , primary amine groups (-NH2)).
  • 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 : Formula II
  • R3 comprises a primary amine group (-NH2).
  • R3 may comprise 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: 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. In all cases, 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 11, 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 about 100, alternately greater than about 1000, or alternately greater than about 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 11, 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-20TM crosslinker, commercially available from Halliburton Energy Services, Inc. in Houston, Texas.
  • 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: Formula V
  • R5, R6, R7, and R8 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 R5, R6, R7, or R8 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/neutralization, and the like).
  • in situ wellbore conditions e.g. , temperature, pH induced hydrolysis/neutralization, and the like.
  • 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.
  • Any suitable operable functionality or substituent or methods for preparing DAs containing operable functionalities or substituents may be employed .
  • a non-limiting 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 wellbore 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.
  • the DAs may be reacted with acids, which may be organic or inorganic (e.g. , mineral acid), to convert them into salts (i.e. , corresponding ammonium salts).
  • acids may be organic or inorganic (e.g. , mineral acid)
  • salts i.e. , corresponding ammonium salts
  • Such salts may be ineffective in their salt form at degrading the degradable polymers, and require an activation step to function as DAs. That is, reaction of the DAs described herein with an acid may convert to DAs into a deactivated form, requiring later contact with an activator to activate (e.g. , by neutralization of the acid component of the DA salt to release the active base form of the DA material) the DAs, such that they may degrade the degradable polymers described herein.
  • an activator e.g. , by neutral
  • 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 or 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 hydrolytic and/or aminolytic degradation in the presence of DA materials of the type disclosed herein.
  • the terms “degrading,” “degradation,” and “degradable” refer 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 (-C00-) group and another block containing non-carboxy containing polymer segment such as polyamide, poly(alkylene oxide), poly(anhydride), polyacrylamide, or poly(2-acrylamido-2-methylpropane sulfonic acid) .
  • 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 DAs 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 are also suitable for use in the present disclosure.
  • aliphatic polyesters such as poly(lactic acid), poly(anhydrides), and poly(lactide)-co-poly(glycolide) copolymers may be used .
  • the particulate DAs for use in the methods of the present invention may be the solid form of salts of any of the DA solutions (e.g. , liquid DAs) listed above and may thereafter be "activated” to release the active form of the DA solution (e.g. , liquid DAs) to degrade the degradable polymers disclosed herein .
  • Particulate DAs may be formed by reacting one or more amine groups of any of the DAs listed above, including, but not limited to, an alkanolamine, an oligomer of an aziridine, a polymer of aziridine, a diamine, any derivative thereof, and any combination thereof, with an acid capable of causing the DA to form a salt which is a solid or particulate material at room temperature in a dry state.
  • the acid may be any acid capable of causing the DA to adopt a solid or particulate form .
  • the acid may include without limitation an organic acid, an inorganic acid (e.g. , mineral acid), and any combination thereof.
  • Suitable inorganic acids for use in forming the particulate DAs described herein may include, but are not limited to, hydrochloric acid, nitric acid, phosphoric acid, sulfuric acid, boric acid, hydrofluoric acid, hydrobromic acid, perchloric acid, and any combination thereof.
  • Suitable inorganic acids for use in forming the particulate DAs described herein may include, but are not limited to, lactic acid, acetic acid, formic acid, citric acid, oxalic acid, tartaric acid, benzoic acid, phthalic acid, and any combination thereof.
  • the acid necessary to form a particulate DA may be any amount necessary to react with one or more amine groups in forming the DA solution so as to cause the DA to adopt a particulate or solid form .
  • the number of nitrogen atoms in a DA molecule that must be reacted with an acid to convert the DA into particulate form may depend on, among other things, the number of nitrogen atoms in the DA molecule, the chemical composition of the acid, and the like.
  • the number of nitrogen atoms that must be reacted with an acid to convert a DA into particulate form may range from a lower limit of about 10%, 15%, 20%, 25%, 30%, 35%, 40%, and 50% to an upper limit of about 100%, 95%, 90%, 85%, 80%, 75%, 70%, 65%, 60%, 55, and 50% of the nitrogen atoms present.
  • suitable particulate DAs for use in the methods of the present disclosure may include, but are not limited to, ethylenediamine dihydrochloride, triethanolamine hydrochloride, dietheylene triamine citrate, and any combination thereof.
  • the DA may be in particulate form to, among other things, facilitate storage and shipping of the DA.
  • the DA solutions provided herein are effective degradation accelerators, but may be corrosive or otherwise toxic or disfavored for use in certain geographical locations, in certain subterranean operations, or by certain operators.
  • EDA ethylenediamine
  • HSE health, safety, and environmental
  • EDA-2HCI salt Information for both EDA and EDA-2HCI salt is shown in Table 1, based on data by the National Fire Protection Association (“NFPA”) rating for flammability, health, and reactivity; by the Occupational Safety and Health Administration (“OSHA”) Globally Harmonized System of classification and labeling of Chemicals (“GHS”) pictogram results; the LD 50 toxicity rating; and the Department of Transportation (“DOT”) class and packaging group rating . It is evident that EDA-2HCI presents less HSE concerns than EDA.
  • NFPA National Fire Protection Association
  • OSHA Occupational Safety and Health Administration
  • GLS Globally Harmonized System of classification and labeling of Chemicals
  • DOT Department of Transportation
  • the particulate DA may be introduced in into the wellbore in the form of a delayed-action construct ("DAC") of the type depicted in Figure 2.
  • the DAC 100 may comprise a DA 20 on a solid support 30, which may be encapsulated by an encapsulating material 10.
  • the particulate DA i.e. , salt
  • the solid support and encapsulation material are discussed in further detail below.
  • the particulate salts of the DAs must be activated by neutralization of the acid component (e.g. , mineral acid or organic acid) of the salt with a base and convert the particulate DA into liquid form (i.e. , converting to the free base form of the DA), referred to herein as a "neutralized degradation accelerator" or "neutralized DA.”
  • the acid component e.g. , mineral acid or organic acid
  • neutralized DA converting to the free base form of the DA
  • neutralized DA neutralized degradation accelerator
  • the particulate DA/DAC may be included in the aqueous fluid (e.g.
  • the particulate DA may be neutralized either on-site or in situ.
  • the particulate DA/DAC and the degradable polymer may be introduced into a wellbore and/or a subterranean formation, and may be made to contact a target zone therein, followed by introduction of the neutralizer activator, which may activate the particulate DA/DAC and cause it to degrade the degradable polymer.
  • the degradable polymer may be first introduced into a wellbore and/or subterranean formation followed by introduction of the particulate DA/DAC and/or the neutralizer activator in any order or simultaneously.
  • the neutralizer activator may be placed within the wellbore and/or subterranean formation followed by introduction of the degradable polymer and/or the particulate DA/DAC in any order or simultaneously.
  • the degradable polymer, particulate DA/DAC, and the neutralizer activator may be introduced simultaneously into a wellbore and/or subterranean formation in a single wellbore servicing fluid.
  • the basic neutralizer activator may be included within the aqueous fluid comprising the particulate DA/DAC in the amount necessary to convert substantially all of the particulate DA/DAC into its free base form (i.e. , neutralized degradation accelerator form), i.e. , in the stoichiometric amount.
  • the term "stoichiometric amount" in all of its variants refers to an optimum amount of basic neutralizer activator such that substantially all of the particulate DA salt is converted into its free base form .
  • the "stoichiometric amount" of basic neutralizer activator may range from the calculated molar equivalent of the basic neutralizer activator (hereinafter referred to as the "calculated stoichiometric amount") required to neutralize the moles of acid used to form the particulate DA salt, such as in the case of strongly basic neutralizer activators (e.g. , alkali metal hydroxides), to substantially larger than the calculated stoichiometric amount, such as in the case of weak basic neutralizer activators.
  • an excess of neutralizer activator may be used to further enhance the degradation of the degradable polymer by the particulate DA/DAC (e.g.
  • the neutralizer activator may be at least 11, alternatively at least 12, or alternatively at least 13. In some embodiments, the neutralizer activator may be present in at least the calculated stoichiometric amount.
  • the neutralizer activator may be present in an amount in excess of the calculated stoichiometric amount in the range of from about 0.1% to greater than about 200%, alternatively from about 20% to greater than about 175%, or alternatively from about 50% to greater than about 150% of the calculated stoichiometric amount.
  • Suitable neutralizer activators for use in the methods of the present disclosure may include, but are not limited to, oxides of alkali metals, hydroxides of alkali metals, oxides of alkaline earth metals, hydroxides of alkaline earth metals, and any combination thereof.
  • suitable oxides and hydroxides of alkali metals and alkaline earth metals may include without limitation sodium hydroxide, sodium oxide, ammonium hydroxide, ammonium oxide, magnesium hydroxide, magnesium oxide, calcium hydroxide, calcium oxide, lithium hydroxide, lithium oxide, barium hydroxide, barium oxide, and any combination thereof.
  • alkali metal carbonates, alkaline earth metal carbonates, ammonium carbonates, alkali metal bicarbonates, and any combination thereof may be used as neutralizer activators according to some embodiments described herein, although it may be less effective than oxides and hydroxides of alkali metals and alkaline earth metals, depending on the particular application .
  • neutralizer activators may be used as neutralizer activators according to some embodiments described herein, although it may be less effective than oxides and hydroxides of alkali metals and alkaline earth metals, depending on the particular application .
  • neutralizer activator to activate the particulate DA(s) selected .
  • 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, for example, 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 PLA.
  • 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 PLA
  • the PLA may have been synthesized from lactic acid by a condensation reaction or, more commonly, by ring-opening polymerization of cyclic lactide monomer. Since both lactic acid and lactide can achieve the same repeating unit, the general term "poly(lactic acid)" as used herein 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 may 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 PLA, or by blending, copolymerizing or otherwise mixing a PLA 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 to degrade the degradable polymer at low temperatures.
  • the DA provides a nucleophile capable of participating in the degradation of the 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 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.
  • 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 may take place within a timeframe 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 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 pH of the aqueous solution comprising the DA, the nucleophilicity of nucleophiles present, the type degradable polymer, the temperature of the subterranean formation, the nature of the subterranean formation, the desired time and/or rate of degradation, and the like.
  • the molar ratio of the DA to the degradable polymer is equivalent (i. e.
  • the amount of DA is in 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 DA may be present in amounts not less than about 20% of the calculated stoichiometric amounts in relation to the molar amounts of the ester groups present in the degradable polymer it is intended to degrade.
  • the molar amounts of the ester groups may be calculated by dividing the estimated weight of the degradable polymer by the estimated molecular weights of the monomers present in the degradable polymer.
  • the molar amounts of the DAs may be calculated by dividing the estimated weight of the active DA content by the molecular weight of the monomer (e.g., aziridine) or the DA molecule (e.g., triethanolamine).
  • 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.
  • 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 take place simultaneously.
  • the DA may swell but not degrade the degradable polymer, and vice versa.
  • the degradable polymer swells at least about 2 times its volume, alternately at least about 5 times, or alternately at least about 10 times in the presence of the DA.
  • the degradable polymer increases in weight, in the presence of DA, by at least about 2 times its mass, alternately at least about 3 times or alternately at least about 10 times its mass prior to the reduction in weight as a result of degradation of the degradable polymer.
  • the DAs 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 e.g. , an amine
  • a neutral oxygen atom in a neutral molecule e.g. , in water, alcohol or ether.
  • the nucleophiles of the present disclosure may be neutral or negatively charged Lewis bases. In general, the more basic the ion (i.e.
  • the electrophile is the carbon of a carbonyl group of the -COO- functional group in the polymer backbone.
  • the DAs 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 shown 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.
  • aminolysis of a degradable polymer in an aqueous environment may be expressed by the following exemplary pathway in Scheme II :
  • 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. , molecular weights lower than about 500) in the degradable polymer.
  • low molecular weight compounds e.g. , molecular weights 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 DAs 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 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 triethylenetetraamine 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 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 DAs, 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 a wellbore comprises introducing into the wellbore a degradable polymer ("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 polymer
  • the DA comprises an amine of the type disclosed herein (e.g. , alkanolamine, aziridine, etc.).
  • the DA may be introduced into 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 further be characterized as hydrophobic, alternatively the support may be 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 (e.g., silica, alumina, aluminaphosphates, and the like), and any combination thereof.
  • the solids support comprises clay.
  • clay refers to aggregates of hydrous silicate particles either naturally-occurring or synthetically-produced, less than 4 micrometers (prn) 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 may be replicated in industrial chemical processes.
  • Examples of clays that may be suitable for use in this disclosure may include without limitation clays from the following groups : kaolinite, serpentine, illite, chlorite, smectite, and any combination thereof.
  • Examples of suitable kaolinite group clays may include without limitation kaolinite, dickite, halloysite, nacrite, and any combination thereof.
  • Examples of suitable illite group clays may include without limitation clay-mica, illite, and any combination thereof.
  • the solid support comprises a zeolite.
  • Zeolites are three-dimensional, microporous, crystalline solids with well-defined porous structures.
  • Zeolites which may 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 may include without limitation analcrime, chabazite, heulandite, natrolite, phillipsite, stilbite, and any combination 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.
  • Suitable commercially available ion-exchange resins for use in the present disclosure may include without limitation MONO-Q ® and MONO-S ® , available from Pharmacia Biotech in Piscataway, New Jersey.
  • the solid support comprises a lignite.
  • Lignite is a brownish black coal that has a high inherent moisture content and high ash content compared to bituminous coal . It is a heterogeneous 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 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 may occur 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 a 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, for example, wellbore temperature, the presence of materials that decrease the structural integrity of the encapsulating material, and the like.
  • 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 may include without limitation ethylene propylene diene monomer (EDPM) rubber, polyvinyldichloride, nylon, waxes, polyurethanes, cross-linked partially hydrolyzed acrylics, cross-linked polyurethane, a drying oil (e.g. , tung oil, linseed oil, and the like), and any combination thereof.
  • EDPM ethylene propylene diene monomer
  • polyvinyldichloride nylon
  • waxes polyurethanes
  • polyurethanes cross-linked partially hydrolyzed acrylics
  • cross-linked polyurethane e.g. , tung oil, linseed oil, and the like
  • the encapsulating material may comprise without limitation biopolymers, polysaccharides, hydrocolloids, gums, and any combination thereof.
  • 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, and any combination thereof.
  • a DAC of the type disclosed herein may be 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 the 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 DA/solid support may 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 may include without limitation crushed nut shells (e.g.
  • an external coating of an encapsulating material through which a DA slowly diffuses can be placed on the particulate porous solid material .
  • a DAC 100 placed in a wellbore may have encapsulation material 10 whose structural integrity is compromised, allowing the DA 20 to dissociate from the solid support 30.
  • the DAC may comprise the encapsulation material 10 and the DA 20 associated with the solid support 30.
  • the DA 20 may dissociate from the solid support 30 and migrate through the encapsulation material 10 into a wellbore servicing area .
  • a "wellbore servicing fluid” or “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, acidizing fluids, drill-in 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), seawater, and any combination thereof.
  • 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 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 may include carbon black, lignite, brown coal, humic acid, styrene-butadiene rubber latexes, polyvinyl alcohol latexes, acetate latexes, acrylate latexes, precipitated silica, fumed/pyrogenic silica, viscoelastic surfactant micelles, and any combination thereof.
  • Nonlimiting examples of clays suitable for use in the present disclosure may include bentonite, attapulgite, kalonite, meta kalonite, laponite, hectorite, sepiolite, and any combination thereof.
  • Nonlimiting examples of viscosifying or gel forming polymers suitable for use in the present disclosure may 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, ⁇ , ⁇ -dimethylacrylamide, acrylic acid, vinyl acetate, and any combination thereof.
  • the suspending agent may be 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 may 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, and any combination thereof.
  • Nonlimiting examples of such additives are also described in U .S. Patent Publication No. 20100273685 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 or otherwise breakdown .
  • 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, a bridging agent, 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 formation, may also be used to introduce a DA or a DAC into the wellbore and/or subterranean formation .
  • a WSF comprising a DA or a DAC may place the DA or DAC proximate to or in contact with the DM present in the wellbore and/or subterranean formation .
  • a WSF may comprise a DA or a 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 may be present in amounts not less than about 20% of the calculated stoichiometric amounts in relation to the molar amounts of the ester groups present in the degradable polymer it is intended to degrade.
  • the molar amounts of the ester groups may be calculated by dividing the estimated weight of the degradable polymer by the estimated molecular weights of the monomers present in the degradable polymer.
  • the molar amounts of the DAs may be calculated by dividing the estimated weight of the active DA content by the molecular weight of the monomer (e.g. , aziridine) or the DA molecule (e.g. , triethanolamine).
  • the DA 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 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 the DM, and the amount of DAC may be dependent on the amount of DA present in the DAC, the desired rate of DM degradation, the desired duration of DM degradation, and the like.
  • the DA and/or the DAC may be placed in the formation prior to the placement of the DM .
  • the term "DA" refers to both the DA solutions (non-particulate form) and the particulate DAs as described in some embodiments herein .
  • the DA and/or the DAC may be made to contact the DMs by drawing down the pressure on the wellbore, for example by putting the well back on production .
  • the DA and/or the DAC and the DM may be pumped together along with the well treatment fluid (e.g. , a fracturing fluid) .
  • the DA and/or the DAC may be placed in the wellbore to contact the DM already placed in the wellbore. Accordingly, the DM and DA and/or the DAC 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 and/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 and/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 pumped ahead or behind a second WSF comprising one or more DAs and/or DACs, for example, as one or more slugs of material that may
  • a WSF comprising a degradable polymer may be introduced to a wellbore and/or subterranean formation simultaneously with the introduction of a DA and/or a DAC that does not adversely react with or otherwise interfere with any aspect of the WSF.
  • a DA and/or DAC 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 and/or a DAC subsequent to the introduction of the degradable polymer into the wellbore and/or subterranean formation .
  • 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 and/or a DAC, and introducing the WSF into the wellbore and/or subterranean formation .
  • the DA and/or the DA forming part of the DAC hydrolyzes the degradable polymer so as to release an acid that facilitates a reduction in the WSFs 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 may be compromised sufficiently to allow release of the DA.
  • the released DA may contact and accelerate 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 .
  • the filter cake should be removed .
  • a DA and/or a 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 and/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 SM Stimulation Service is an example of such a stimulation service commercially available from Halliburton Energy Services, Inc. in Houston, Texas.
  • 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. in Houston, Texas.
  • the degradable polymers may comprise a multimodal particle size distribution, for example, bimodal or trimodal particle size distributions.
  • the degradable polymer comprising a 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 1mm to about 100 microns.
  • the degradable polymers after placement may be treated with a swelling DA which will swell the degradable polymer particles forming a continuous mass of diverting plug before the degradation process sets in .
  • the DA or the 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 the 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 conditions.
  • 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.
  • the degradable polymer may be advantageously soaked and/or immersed in a DA solution or in an aqueous fluid comprising a particulate DA and then pumped downhole, thereby removing the need to place the DA solution or the aqueous fluid comprising the particulate DA separately.
  • the degradable polymer may be soaked in a DA solution or in the aqueous fluid comprising a particulate DA 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 or the aqueous fluid comprising a particulate DA will concurrently degrade the polymer in an advantageously shorter timeframe of less than about 1 week, alternatively less than about 3 days. In such an embodiment, the degradable polymer (e.g. , PLA) 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 0.5mm 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, DA particulate, or DAC of the type disclosed herein .
  • the DA solution may have a pH of less than about 12, alternatively less than about 11, or alternatively less than about 10.
  • the degradable filter cake may comprise a DAC comprising a particulate salt DA.
  • the DA in the filter cake may be activated by contacting the filter cake with a neutralizer activator.
  • the DAC may comprise a particulate salt DA that may be pre- contacted with a neutralizer activator prior to assembling the filter cake with the degradable polymer.
  • the systems can comprise a pump fluidly coupled to a tubular, the tubular containing a fluid comprising the DAs and/or DACs described herein .
  • the pump may be a high pressure pump in some embodiments.
  • the term "high pressure pump” will refer to a pump that is capable of delivering a fluid downhole at a pressure of about 1000 psi or greater.
  • a high pressure pump may be used when it is desired to introduce the fluid to a subterranean formation at or above a fracture gradient of the subterranean formation, but it may also be used in cases where fracturing is not desired .
  • the high pressure pump may be capable of fluidly conveying particulate matter, such as proppant particulates, into the subterranean formation .
  • Suitable high pressure pumps will be known to one having ordinary skill in the art and may include, but are not limited to, floating piston pumps and positive displacement pumps.
  • the pump may be a low pressure pump.
  • the term "low pressure pump” will refer to a pump that operates at a pressure of about 1000 psi or less.
  • a low pressure pump may be fluidly coupled to a high pressure pump that is fluidly coupled to the tubular. That is, in such embodiments, the low pressure pump may be configured to convey the fluid to the high pressure pump. In such embodiments, the low pressure pump may "step up" the pressure of the fluid before it reaches the high pressure pump.
  • the systems described herein can further comprise a mixing tank that is upstream of the pump and in which the fluid fluids comprising the DAs and/or DACs described herein is formulated .
  • the pump e.g., a low pressure pump, a high pressure pump, or a combination thereof
  • the pump may convey the fluid from the mixing tank or other source of the fluid to the tubular.
  • the fluids comprising the DAs and/or DACs described herein can be formulated offsite and transported to a worksite, in which case the fluid may be introduced to the tubular via the pump directly from its shipping container (e.g., a truck, a railcar, a barge, or the like) or from a transport pipeline. In either case, the fluid may be drawn into the pump, elevated to an appropriate pressure, and then introduced into the tubular for delivery downhole.
  • its shipping container e.g., a truck, a railcar, a barge, or the like
  • the fluid may be drawn into the pump, elevated to an appropriate pressure, and then introduced into the tubular for delivery downhole.
  • Figure 3 shows an illustrative schematic of a system that can deliver fluids comprising the DAs and/or DACs of the present disclosure to a downhole location, according to one or more embodiments.
  • system 200 may include mixing tank 202, in which a fluid comprising the DAs and/or DACs of the present invention may be formulated .
  • the fluid may be conveyed via line 204 to wellhead 206, where the fluid enters tubular 208, tubular 208 extending from wellhead 206 into subterranean formation 210.
  • system 200 Upon being ejected from tubular 208, the fluid comprising the DAs and/or DACs described herein may subsequently penetrate into subterranean formation 210.
  • Pump 212 may be configured to raise the pressure of the fluid to a desired degree before its introduction into tubular 208.
  • system 200 is merely exemplary in nature and various additional components may be present that have not necessarily been depicted in Figure 3 in the interest of clarity.
  • Non-limiting additional components that may be present include, but are not limited to, supply hoppers, valves, condensers, adapters, joints, gauges, sensors, compressors, pressure controllers, pressure sensors, flow rate controllers, flow rate sensors, temperature sensors, and the like.
  • the fluid may, in some embodiments, flow back to wellhead 206 and exit subterranean formation 210. In some embodiments, the fluid that has flowed back to wellhead 206 may subsequently be recovered and recirculated to subterranean formation 210.
  • the disclosed fluids may also directly or indirectly affect the various downhole equipment and tools that may come into contact with the fluids during operation.
  • equipment and tools may include, but are not limited to, wellbore casing, wellbore liner, completion string, insert strings, drill string, coiled tubing, slickline, wireline, drill pipe, drill collars, mud motors, downhole motors and/or pumps, surface- mounted motors and/or pumps, centralizers, turbolizers, scratchers, floats (e.g., shoes, collars, valves, etc.), logging tools and related telemetry equipment, actuators (e.g.
  • electromechanical devices e.g. , electromechanical devices, hydromechanical devices, etc.
  • sliding sleeves production sleeves, plugs, screens, filters
  • flow control devices e.g. , inflow control devices, autonomous inflow control devices, outflow control devices, etc.
  • couplings e.g. , electro-hydraulic wet connect, dry connect, inductive coupler, etc.
  • control lines e.g. , electrical, fiber optic, hydraulic, etc.
  • surveillance lines drill bits and reamers, sensors or distributed sensors, downhole heat exchangers, valves and corresponding actuation devices, tool seals, packers, cement plugs, bridge plugs, and other wellbore isolation devices, or components, and the like. Any of these components may be included in the systems generally described above and depicted in Figure 3.
  • Embodiments disclosed herein include :
  • a method of servicing a wellbore comprising : providing a degradable polymer within a portion of a wellbore and/or a subterranean formation; providing a wellbore servicing fluid comprising a particulate salt degradation accelerator and a neutralizer activator, wherein the particulate salt degradation accelerator is formed by reacting a degradation accelerator solution selected from the group consisting of an alkanolamine; an oligomer of aziridine; a polymer of aziridine; a diamine; and any combination thereof, with an acid, and wherein the neutralizer activator is capable of dissociating the acid by neutralization from the particulate salt degradation accelerator so as to form a neutralized degradation accelerator; introducing the wellbore servicing fluid into a wellbore and/or a subterranean formation; contacting the degradable polymer with the neutralized degradation accelerator; and degrading the degradable polymer.
  • a degradation accelerator solution selected from the group consisting of an alkanolamine; an oligomer of azir
  • a method of servicing a wellbore comprising : providing a degradable polymer within a portion of a wellbore and/or a subterranean formation; providing a first wellbore servicing fluid comprising a particulate salt degradation accelerator, wherein the particulate salt degradation accelerator is formed by reacting a degradation accelerator solution selected from the group consisting of an alkanolamine; an oligomer of aziridine; a polymer of aziridine; a diamine; and any combination thereof, with an acid; providing a second wellbore servicing fluid comprising a neutralizer activator; introducing the first wellbore servicing fluid into the wellbore and/or subterranean formation; introducing the second wellbore servicing fluid into the wellbore and/or subterranean formation; contacting the particulate salt degradable accelerator with the neutralizer activator, wherein the neutralizer activator is capable of dissociating the acid from the particulate salt degradation accelerator so as to form a neutralized degradation accelerator; contacting
  • a method of servicing a wellbore comprising : providing a wellbore servicing fluid comprising a degradable polymer, a particulate salt degradation accelerator, and a neutralizer activator, wherein the particulate salt degradation accelerator is formed by reacting a degradation accelerator solution selected from the group consisting of an alkanolamine; an oligomer of aziridine; a polymer of aziridine; a diamine; and any combination thereof, with an acid, and wherein the neutralizer activator is capable of dissociating the acid from the particulate salt degradation accelerator so as to form a neutralized degradation accelerator; introducing the wellbore servicing fluid into a wellbore and/or a subterranean formation; contacting the degradable polymer with the neutralized degradation accelerator; and degrading the degradable polymer.
  • Each of embodiments A, B, and C may have one or more of the following additional elements in any combination :
  • Element 1 Wherein the acid is selected from the group consisting of an organic acid; an inorganic acid ; and any combination thereof.
  • Element 2 Wherein the organic acid is selected from the group consisting of lactic acid ; acetic acid ; formic acid ; citric acid; oxalic acid; tartaric acid ; benzoic acid; phthalic acid; and any combination thereof.
  • Element 3 Wherein the inorganic acid is selected from the group consisting of hydrochloric acid ; nitric acid; phosphoric acid; sulfuric acid ; boric acid ; hydrofluoric acid; hydrobromic acid; perchloric acid; and any combination thereof.
  • Element 4 Wherein the neutralizer activator is selected from the group consisting of an oxide of an alkali metal ; a hydroxide of an alkali metal ; an oxide of an alkaline earth metal; a hydroxide of an alkaline earth metal ; and any combination thereof.
  • Element 5 Wherein at least a calculated stoichiometric amount of the neutralizer activator is included in the wellbore servicing fluid .
  • Element 6 Wherein the neutralizer activator is included in the wellbore servicing fluid in an amount in the range from about 0.1% to about 200% greater than a calculated stoichiometric amount.
  • Element 7 Wherein the step of: introducing the first wellbore servicing fluid into the wellbore and/or subterranean formation, is performed prior to the step of: introducing the second wellbore servicing fluid into the wellbore and/or subterranean formation.
  • Element 8 Wherein the step of: introducing the first wellbore servicing fluid into the wellbore and/or subterranean formation, is performed after the step of: introducing the second wellbore servicing fluid into the wellbore and/or subterranean formation.
  • Element 9 Wherein the step of: introducing the first wellbore servicing fluid into the wellbore and/or subterranean formation, is performed simultaneously with the step of: introducing the second wellbore servicing fluid into the wellbore and/or subterranean formation.
  • Element 10 Wherein the wellbore servicing fluid is introduced into the wellbore and/or the subterranean formation using a pump.
  • Element 11 Wherein at least one of the first wellbore servicing fluid and the second wellbore servicing fluid is introduced into the wellbore and/or the subterranean formation using a pump.
  • exemplary combinations applicable to A, B, and C include: A with 1, 5, and 10; A with 1, 2, and 6; B with 3 and 5; B with 2, 4, 9, and 11; C with 1 and 5; and C with 4 and 6.
  • the crystallinity of the PLA 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 2.
  • 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 100 ml of 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 (e.g.
  • 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.
  • the mixtures were kept in a water bath heated to 140°F (60°C) . Comparative samples using water and ethylenediamine as the degrading agents were also investigated .
  • TETA triethylenetetramine
  • PEI polyethyleneimine
  • PEI is commercially available from Halliburton Energy Services, Inc. in Houston, Texas as HZ-20TM crosslinker.
  • Alkanolamines used in the study included ethanolamine (EA), triethanolamine (TEA) and triisopropanolamine (Formula I). 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.
  • Tables 3 and 4 The results for samples utilizing an aziridine oligomer, aziridine polymer and diamine as the DA are presented in Tables 3 and 4.
  • Table 3 presents the results from measuring remaining polymer weights at 140°F (60°C) after 3, 6 and 9 days.
  • Table 4 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 semi- crystalline 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 DA solutions 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.
  • EDA Ethylenediamie
  • EDA-2HCI ethylenediamine hydrochloride
  • TS1-TS3 tap water
  • EDA-2HCI is in salt form, 0.77% w/w of EDA-2HCI is equivalent to 0.7% w/v of EDA used in the control sample).
  • no neutralizer activator was included, or 1.5x the calculated stoichiometric amount of a strongly basic sodium hydroxide neutralizer activator, or the calculated stoichiometric amount of a weakly basic sodium bicarbonate neutralizer activator was added.
  • the amount of neutralizer activator added to the EDA-2HCL was estimated to match or exceed the pH of EDA (the DA solution in non-particulate form) to completely neutralize the acid component of the particulate DA salt, such that comparison of the effectiveness of degradation using EDA versus EDA-2HCI in the presence of a neutralizer activator could be achieved .
  • the composition of the samples is shown in Table 6. Table 6
  • the strength of the basic neutralizer activator may play an important role in defining the effectiveness of a particulate DA, particularly depending on the particular DA that it is paired with.
  • sodium hydroxide is a better neutralizer activator for use with particulate DE EDA-2HCI .
  • Degradation rates were measured for the samples in Table 6 corresponding to the Control, TS1, TS2, and 100 ml of tap water. To each 100 ml sample, 1 gram of PLA was added to determine the degradation rates. Each sample was kept at 160°F (71.1°C) in a water bath and tested at time points up to approximately 200 hours. The results are shown in Figure 4. As shown, water and EDA-2HCI performed poorly as DAs for use in degrading the degradable polymer PLA.
  • both pure EDA and particulate EDA-2HCI neutralized with sodium hydroxide achieved approximately 95% degradation of PLA after approximately 200 hours, demonstrating that neutralized particulate DAs, as described herein, may be used in place of or in combination with DA solutions (and/or DACs).
  • sodium bicarbonate used at the calculated stoichiometric amount showed significantly lower degradation rates after 200 hours elapsed, demonstrating that weak basic neutralizer activators may not be able to completely neutralize the acid portion of a particulate DA salt, at least when used in calculated stoichiometric amounts, based on the observation that the pH of TS3 was significantly less (9.4) than the pH of the Control of pure EDA ( 11.4) .
  • any number falling within the range is specifically disclosed .
  • 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, 4 percent, 5 percent, , 50 percent, 51 percent, 52 percent, , 95 percent, 96 percent, 97 percent, 98 percent, 99 percent, or 100 percent.
  • any numerical range defined by two R numbers as defined in the above is also specifically disclosed .

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Abstract

La présente invention concerne un polymère dégradable dans une partie d'un puits de forage et/ou d'une formation souterraine ; un fluide d'entretien de puits de forage comprenant un accélérateur de dégradation à base de sel particulaire et un activateur neutralisant, l'accélérateur de dégradation à base de sel particulaire étant formé en faisant réagir une solution d'accélérateur de dégradation choisi dans le groupe constitué par une alcanolamine ; un oligomère d'aziridine ; un polymère d'aziridine ; une diamine ; et une combinaison quelconque de ceux-ci, avec un acide, et l'activateur neutralisant pouvant dissocier l'acide de l'accélérateur de dégradation à base de sel particulaire par neutralisation de sorte à former un accélérateur de dégradation neutralisé ; l'introduction du fluide d'entretien de puits de forage dans un puits de forage et/ou une formation souterraine ; la mise en contact du polymère dégradable avec l'accélérateur de dégradation neutralisé ; et la dégradation du polymère dégradable.
PCT/US2014/068551 2014-01-03 2014-12-04 Procédés d'entretien de puits de forage et compositions comprenant des polymères dégradables Ceased WO2015102802A1 (fr)

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US9359543B2 (en) 2012-10-25 2016-06-07 Halliburton Energy Services, Inc. Wellbore servicing methods and compositions comprising degradable polymers
WO2018218333A1 (fr) * 2017-06-02 2018-12-06 Fluid Energy Group Ltd. Nouvelles compositions d'acides modifiées en tant qu'alternatives à des acides classiques dans l'industrie pétrolière et gazière
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US10472555B2 (en) 2016-04-08 2019-11-12 Schlumberger Technology Corporation Polymer gel for water control applications
WO2018218333A1 (fr) * 2017-06-02 2018-12-06 Fluid Energy Group Ltd. Nouvelles compositions d'acides modifiées en tant qu'alternatives à des acides classiques dans l'industrie pétrolière et gazière

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