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US20050059556A1 - Treatment fluids and methods of use in subterranean formations - Google Patents

Treatment fluids and methods of use in subterranean formations Download PDF

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US20050059556A1
US20050059556A1 US10832163 US83216304A US2005059556A1 US 20050059556 A1 US20050059556 A1 US 20050059556A1 US 10832163 US10832163 US 10832163 US 83216304 A US83216304 A US 83216304A US 2005059556 A1 US2005059556 A1 US 2005059556A1
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fluid
treatment
present
degradable
material
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Trinidad Munoz
Larry Eoff
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Halliburton Energy Services Inc
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    • CCHEMISTRY; METALLURGY
    • C09DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; MISCELLANEOUS COMPOSITIONS; MISCELLANEOUS APPLICATIONS OF MATERIALS
    • C09KMATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/50Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
    • C09K8/504Compositions based on water or polar solvents
    • C09K8/5045Compositions based on water or polar solvents containing inorganic compounds
    • CCHEMISTRY; METALLURGY
    • C09DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; MISCELLANEOUS COMPOSITIONS; MISCELLANEOUS APPLICATIONS OF MATERIALS
    • C09KMATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/02Well-drilling compositions
    • C09K8/03Specific additives for general use in well-drilling compositions
    • CCHEMISTRY; METALLURGY
    • C09DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; MISCELLANEOUS COMPOSITIONS; MISCELLANEOUS APPLICATIONS OF MATERIALS
    • C09KMATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/02Well-drilling compositions
    • C09K8/04Aqueous well-drilling compositions
    • C09K8/06Clay-free compositions
    • CCHEMISTRY; METALLURGY
    • C09DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; MISCELLANEOUS COMPOSITIONS; MISCELLANEOUS APPLICATIONS OF MATERIALS
    • C09KMATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/50Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
    • C09K8/504Compositions based on water or polar solvents
    • C09K8/506Compositions based on water or polar solvents containing organic compounds
    • C09K8/508Compositions based on water or polar solvents containing organic compounds macromolecular compounds
    • CCHEMISTRY; METALLURGY
    • C09DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; MISCELLANEOUS COMPOSITIONS; MISCELLANEOUS APPLICATIONS OF MATERIALS
    • C09KMATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/52Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning
    • CCHEMISTRY; METALLURGY
    • C09DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; MISCELLANEOUS COMPOSITIONS; MISCELLANEOUS APPLICATIONS OF MATERIALS
    • C09KMATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K2208/00Aspects relating to compositions of drilling or well treatment fluids
    • C09K2208/18Bridging agents, i.e. particles for temporarily filling the pores of a formation; Graded salts
    • YGENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y10TECHNICAL SUBJECTS COVERED BY FORMER USPC
    • Y10TTECHNICAL SUBJECTS COVERED BY FORMER US CLASSIFICATION
    • Y10T428/00Stock material or miscellaneous articles
    • Y10T428/29Coated or structually defined flake, particle, cell, strand, strand portion, rod, filament, macroscopic fiber or mass thereof
    • Y10T428/2982Particulate matter [e.g., sphere, flake, etc.]

Abstract

The present invention relates to subterranean treatment operations, and more particularly to improved bridging agents comprising a degradable material, improved subterranean treatment fluids comprising such improved bridging agents, and methods of using such improved subterranean treatment fluids in subterranean formations. An example of a method of the present invention is a method of drilling a well bore in a subterranean formation. Another example of a method of the present invention is a method of forming a self-degrading filter cake in a subterranean formation. Another example of a method of the present invention is a method of degrading a filter cake in a subterranean formation. An example of a composition of the present invention is a treatment fluid including a viscosifier, a fluid loss control additive, and a bridging agent comprising a degradable material. Another example of a composition of the present invention is a bridging agent comprising a degradable material.

Description

    CROSS-REFERENCE TO RELATED APPLICATION
  • [0001]
    This application is a continuation-in-part of U.S. patent application Ser. No. 10/664,126 entitled “Improved Subterranean Treatment Fluids and Methods of Treating Subterranean Formations,” filed Sep. 17, 2003, incorporated by reference herein for all purposes, and from which priority is claimed pursuant to 35 U.S.C. § 120.
  • BACKGROUND OF THE INVENTION
  • [0002]
    The present invention relates to subterranean treatment operations, and more particularly, to improved bridging agents comprising a degradable material, to improved subterranean treatment fluids comprising such improved bridging agents, and to methods of using such improved subterranean treatment fluids in subterranean formations.
  • [0003]
    A subterranean treatment fluid used in connection with a subterranean formation may be any number of fluids (gaseous or liquid) or mixtures of fluids and solids (e.g., solid suspensions, mixtures and emulsions of liquids, gases and solids) used in subterranean operations. An example of a subterranean treatment fluid is a drilling fluid. Drilling fluids are used, inter alia, during subterranean well-drilling operations to, e.g., cool the drill bit, lubricate the rotating drill pipe to prevent it from sticking to the walls of the well bore, prevent blowouts by serving as a hydrostatic head to counteract the sudden entrance into the well bore of high pressure formation fluids, and also remove drill cuttings from the well bore. Another example of a subterranean treatment fluid is a “drill-in and servicing fluid.” “Drill-in and servicing fluids,” as referred to herein, will be understood to include fluids placed in a subterranean formation from which production has been, is being, or may be cultivated. For example, an operator may begin drilling a subterranean borehole using a drilling fluid, cease drilling at a depth just above that of a potentially productive formation, circulate a sufficient quantity of a drill-in and servicing fluid through the bore hole to completely flush out the drilling fluid, then proceed to drill into the desired formation using the well drill-in and servicing fluid. Drill-in and servicing fluids often are utilized, inter alia, to minimize damage to the permeability of such formations.
  • [0004]
    Subterranean treatment fluids generally are aqueous-based or oil-based, and may comprise additives such as viscosifiers (e.g., xanthan) and fluid loss control additives (e.g., starches). Subterranean treatment fluids further may comprise bridging agents, which may aid in preventing or reducing loss of the treatment fluid to, inter alia, natural fractures within the subterranean formation. Calcium carbonate is an example of a conventional bridging agent. In certain circumstances, a bridging agent may be designed to form a filter cake so as to plug off a “thief zone” (a portion of a subterranean formation, most commonly encountered during drilling operations, into which a drilling fluid may be lost). Generally, bridging agents are designed to form fast and efficient filter cakes on the walls of the well bores within the producing formations to minimize potential leak-off and damage. Generally, the filter cakes are removed before hydrocarbons are produced from the formation.
  • [0005]
    Conventionally, the filter cakes are removed from well bore walls by contacting the filter cake with one or more subsequent fluids. For example, where an aqueous-based treatment fluid comprising bridging agents is used to establish a filter cake, operators conventionally have employed enzymes and oxidizers to remove the viscosifier and fluid loss control additive, and then used an acid, or a delayed-generation acid, to clean up the calcium carbonate bridging agent. The removal of filter cakes established by oil-based treatment fluids, however, is often much more difficult.
  • [0006]
    When an oil-based treatment fluid comprising bridging agents is placed in a subterranean formation, a filter cake often results that covers the walls of the well bore. Because the fluids that subsequently will be placed in the well bore often will be aqueous-based, an operator ordinarily might prefer to remove this filter cake with an aqueous-based cleanup fluid that may be compatible with the subsequent fluids. However, attempts to remove the filter cake with an aqueous-based cleanup fluid generally have been unsuccessful, due at least in part to the fact that oil and water are immiscible, which may impair the aqueous-based cleanup fluid's ability to clean the filter cake off the well bore walls. Accordingly, operators have attempted to introduce acid into the well bore, to try to dissolve the calcium carbonate bridging agents which are acid-soluble. This method has been problematic, however, because such calcium carbonate bridging agents are generally well-mixed within the filter cake. Multi-stage cleanup operations usually ensue, and may include, in a first stage, the introduction of water-wetting and oil-penetrating surfactants, followed by multiple stages that involve the introduction of an acid solution into the well bore. Additionally, some operators have attempted to use an oil-based treatment fluid having a particular pH to establish a filter cake (which, as noted above, is essentially a water-in-oil emulsion when formed by an oil-based treatment fluid), and followed the oil-based treatment fluid with a cleanup fluid having a pH that is sufficiently different to invert the emulsion (e.g., the filter cake) to become water-external, thereby water-wetting the bridging particles within the filter cake.
  • [0007]
    These conventional methods have been costly, laborious to perform, and generally have not produced the desired results, largely because the filter cake is not cleaned evenly-rather, the cleanup methods described above generally only achieve “pinpricks” in the filter cake itself. These pinpricks may be problematic because the well bore is typically under hydrostatic pressure from the column of treatment fluid, which may be lost through these pinpricks where the filter cake has been penetrated. Thus, any fluid that subsequently is placed within the well bore may be lost into the formation, as such fluid may follow the path of least resistance, possibly through the pinpricks.
  • SUMMARY OF THE INVENTION
  • [0008]
    The present invention relates to subterranean treatment operations, and more particularly, to improved bridging agents comprising a degradable material, to improved subterranean treatment fluids comprising such improved bridging agents, and to methods of using such improved subterranean treatment fluids in subterranean formations.
  • [0009]
    An example of a method of the present invention is a method of drilling a well bore in a subterranean formation, comprising the step of drilling a well bore in a subterranean formation using a treatment fluid comprising a base fluid, a viscosifier, a fluid loss control additive, and a bridging agent that comprises a degradable material.
  • [0010]
    Another example of a method of the present invention is a method of forming a self-degrading filter cake in a subterranean formation, comprising the steps of: placing a treatment fluid in a subterranean formation, the treatment fluid comprising a base fluid, a viscosifier, a fluid loss control additive, and a bridging agent comprising a degradable material; and permitting the bridging agent to form a self-degrading filter cake upon a surface in the formation, whereby fluid loss to the formation through the self-degrading filter cake is reduced.
  • [0011]
    Another example of a method of the present invention is a method of degrading a filter cake in a subterranean formation, the filter cake having been deposited therein by a treatment fluid comprising a bridging agent, comprising the steps of: utilizing a bridging agent comprising a degradable material; and permitting the degradable material to degrade.
  • [0012]
    An example of a composition of the present invention is a treatment fluid comprising a viscosifier, a fluid loss control additive, and a bridging agent comprising a degradable material.
  • [0013]
    Another example of a composition of the present invention is a bridging agent comprising a degradable material.
  • [0014]
    The features and advantages of the present invention will be readily apparent to those skilled in the art upon a reading of the description of exemplary embodiments, which follows.
  • DETAILED DESCRIPTION OF EXEMPLARY EMBODIMENTS
  • [0015]
    The present invention relates to subterranean treatment operations, and more particularly, to improved bridging agents comprising a degradable material, to improved subterranean treatment fluids comprising such improved bridging agents, and to methods of using such improved subterranean treatment fluids in subterranean formations. While the compositions and methods of the present invention are useful in a variety of subterranean applications, they may be particularly useful in subterranean drilling operations.
  • [0016]
    The subterranean treatment fluids of the present invention generally comprise a base fluid, a viscosifier, a fluid loss control additive, and a bridging agent of the present invention, the bridging agent comprising a degradable material capable of undergoing an irreversible degradation downhole. Optionally, other additives may be added as desired.
  • [0017]
    The base fluid may comprise any number of organic fluids. Examples of suitable organic fluids include, but are not limited to, mineral oils, synthetic oils, esters, kerosene, diesel, and the like. Generally, these organic fluids may be referred to generically as “oils.” Where a treatment fluid of the present invention comprises one or more of these organic fluids, and is used as a drilling fluid in drilling operations, such drilling fluid may be referred to as an “oil-based fluid” or an “oil-based mud.” Generally, any oil in which a water solution of salts can be emulsified may be suitable for use as a base fluid in the treatment fluids of the present invention. Generally, the base fluid may be present in an amount sufficient to form a pumpable treatment fluid. More particularly, the base fluid typically is present in the treatment fluid in an amount in the range of from about 20% to about 99% by volume of the treatment fluid. In certain exemplary embodiments, the base fluid may be present in the treatment fluid in an amount in the range of from about 20% to about 95% by volume of the treatment fluid.
  • [0018]
    The treatment fluids of the present invention comprise a viscosifier. A broad variety of viscosifiers may be suitable. For example, the viscosifier may be an organophilic clay, a synthetic oil-soluble polymer, or a polymeric fatty acid. An example of a synthetic oil-soluble polymer is commercially available from Halliburton Energy Services, Inc., of Houston, Tex., under the trade name “BARAPAK.” An example of a polymeric fatty acid is commercially available from Halliburton Energy Services, Inc., of Houston, Tex., under the trade name “X-VIS.” Generally, the viscosifier is present in the treatment fluids of the present invention in an amount sufficient to provide a desired capability for solids suspension. In certain exemplary embodiments, the viscosifier may be present in the treatment fluid in an amount in the range of from about 1 to 20 pounds of viscosifier per barrel of treatment fluid. In certain exemplary embodiments, the viscosifier may be present in the treatment fluid in an amount in the range of from about 2 to about 15 pounds of viscosifier per barrel of treatment fluid.
  • [0019]
    The treatment fluids of the present invention further comprise a fluid loss control additive. Generally, any fluid loss control additive may be suitable for use in the treatment fluids of the present invention. Examples of suitable fluid loss control additives include, but are not limited to, synthetic oil-soluble polymers, powdered hydrocarbon resins, and organophilic lignite. An example of a synthetic oil-soluble polymer is commercially available from Halliburton Energy Services, Inc., of Houston, Tex., under the trade name “BARAPAK.” In certain exemplary embodiments, the fluid loss control additive may be a synthetic oil-soluble copolymer commercially available from Halliburton Energy Services, Inc., under the trade name “ADAPTA.” Generally, the fluid loss control additive is present in the treatment fluid in an amount sufficient to provide a desired degree of fluid loss control. In certain exemplary embodiments, the fluid loss control additive is present in the treatment fluid in an amount in the range of from about 1 to about 30 pounds of fluid loss control additive per barrel of treatment fluid. In certain exemplary embodiments, the fluid loss control additive is present in the treatment fluid in an amount in the range of from about 2 to about 20 pounds of fluid loss control additive per barrel of treatment fluid.
  • [0020]
    The treatment fluids of the present invention further comprise a bridging agent of the present invention that comprises a degradable material capable of undergoing an irreversible degradation downhole. The term “irreversible,” as used herein, means that the degradable material once degraded should not recrystallize or reconsolidate while downhole, e.g., the degradable material should degrade in situ but should not recrystallize or reconsolidate in situ. The terms “degradation” or “degradable” refer to both the two relatively extreme cases of hydrolytic degradation that the degradable material may undergo, e.g., bulk erosion and surface erosion, and any stage of degradation in between these two. This degradation can be a result of, inter alia, a chemical or thermal reaction, or a reaction induced by radiation.
  • [0021]
    The bridging agent of the present invention becomes suspended in the treatment fluid and, as the treatment fluid begins to form a filter cake within the subterranean formation, the bridging agent becomes distributed throughout the resulting filter cake. In certain exemplary embodiments, the filter cake forms upon the face of the formation itself. After the requisite time period dictated by the characteristics of the particular degradable material utilized, the degradable material undergoes an irreversible degradation. This degradation, in effect, causes the degradable material to substantially be removed from the filter cake. As a result, voids are created in the filter cake. Removal of the degradable material from the filter cake allows produced fluids to flow more freely.
  • [0022]
    Generally, the bridging agent comprising the degradable material is present in the treatment fluids of the present invention in an amount sufficient to assist in creating an efficient filter cake. As referred to herein, the term “efficient filter cake” will be understood to mean a filter cake comprising no material beyond that required to provide a desired level of fluid loss control. In certain embodiments, the bridging agent comprising the degradable material is present in the treatment fluid in an amount ranging from about 0.1% to about 32% by weight. In certain exemplary embodiments, the bridging agent comprising the degradable material is present in the treatment fluid in the range of from about 3% and about 10% by weight. In certain exemplary embodiments, the bridging agent is present in the treatment fluid in an amount sufficient to provide a fluid loss of less than about 15 mL in tests conducted according to the procedures set forth by API Recommended Practice (RP) 13. One of ordinary skill in the art with the benefit of this disclosure will recognize an optimum concentration of degradable material that provides desirable values in terms of enhanced ease of removal of the filter cake at the desired time without undermining the stability of the filter cake during its period of intended use.
  • [0023]
    Nonlimiting examples of suitable degradable materials that may be used in conjunction with the present invention include, but are not limited to, degradable polymers, hydrated organic or inorganic compounds, and/or mixtures of the two. In choosing the appropriate degradable material, one should consider the degradation products that will result. Also, these degradation products should not adversely affect other operations or components. One of ordinary skill in the art, with the benefit of this disclosure, will be able to recognize when particular components of the treatment fluids of the present invention would be incompatible or would produce degradation products that would adversely affect other operations or components.
  • [0024]
    As for degradable polymers, a polymer is considered to be “degradable” herein if the degradation is due to, inter alia, chemical and/or radical process such as hydrolysis, oxidation, enzymatic degradation, or UV radiation. The degradability of a polymer depends, at least in part, on its backbone structure. For instance, the presence of hydrolyzable and/or oxidizable linkages in the backbone often yields a material that will degrade as described herein. The rates at which such polymers degrade are dependent on, inter alia, the type of repetitive unit, composition, sequence, length, molecular geometry, molecular weight, morphology (e.g., crystallinity, size of spherulites, and orientation), hydrophilicity, hydrophobicity, surface area, and additives. The manner in which the polymer degrades also may be affected by the environment to which the polymer is subjected (e.g., temperature, presence of moisture, oxygen, microorganisms, enzymes, pH, and the like).
  • [0025]
    Suitable examples of degradable polymers that may be used in accordance with the present invention include, but are not limited to, those described in the publication of Advances in Polymer Science, Vol. 157 entitled “Degradable Aliphatic Polyesters” edited by A. C. Albertsson, pages 1-138. Specific examples include homopolymers, random, block, graft, and star- and hyper-branched aliphatic polyesters. Such suitable polymers may be prepared by polycondensation reactions, ring-opening polymerizations, free radical polymerizations, anionic polymerizations, carbocationic polymerizations, and coordinative ring-opening polymerization for, e.g., lactones, and any other suitable process. Specific examples of suitable polymers include, but are not limited to, polysaccharides such as dextran or cellulose; chitin; chitosan; proteins; orthoesters; aliphatic polyesters; poly(lactide); poly(glycolide); poly(ε-caprolactone); poly(hydroxybutyrate); poly(anhydrides); aliphatic polycarbonates; poly(orthoesters); poly(amino acids); poly(ethylene oxide); and polyphosphazenes. Of these suitable polymers, aliphatic polyesters and polyanhydrides may be preferred in many situations.
  • [0026]
    Suitable aliphatic polyesters have the general formula of repeating units shown below:
    Figure US20050059556A1-20050317-C00001
  • [0027]
    where n is an integer between 75 and 10,000 and R is selected from the group consisting of hydrogen, alkyl, aryl, alkylaryl, acetyl, heteroatoms, and mixtures thereof. Of the suitable aliphatic polyesters, poly(lactide) is preferred. Poly(lactide) is synthesized either 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 writ of formula I without any limitation as to how the polymer was made (such as from lactides, lactic acid, or oligomers), and without reference to the degree of polymerization or level of plasticization.
  • [0028]
    The lactide monomer exists generally in three different forms: two stereoisomers L- and D-lactide and racemic D,L-lactide (meso-lactide). The oligomers of lactic acid, and oligomers of lactide are defined by the formula:
    Figure US20050059556A1-20050317-C00002
  • [0029]
    where m is an integer: 2≦m≦75. In certain exemplary embodiments, m is an integer: 2≦m≦10. These limits correspond to number average molecular weights below about 5,400 and below about 720, respectively. The chirality of the lactide units provides a means to adjust, inter alia, 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 invention where a slower degradation of the degradable material 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 in accordance with the present invention. Additionally, they may be copolymerized with, for example, glycolide or other monomers like ε-caprolactone, 1,5-dioxepan-2-one, trimethylene carbonate, or other suitable monomers to obtain polymers with different properties or degradation times. Additionally, the lactic acid stereoisomers can be modified by blending high and low molecular weight polylactide or by blending polylactide with other polyesters.
  • [0030]
    Plasticizers may be present in the polymeric degradable materials of the present invention. The plasticizers may be present in an amount sufficient to provide the desired characteristics, for example, (a) more effective compatibilization of the melt blend components, (b) improved processing characteristics during the blending and processing steps, and (c) control and regulation of the sensitivity and degradation of the polymer by moisture. Suitable plasticizers include, but are not limited to, derivatives of oligomeric lactic acid, selected from the group defined by the formula:
    Figure US20050059556A1-20050317-C00003
  • [0031]
    where R is a hydrogen, alkyl, aryl, alkylaryl, acetyl, heteroatom, or a mixture thereof and R is saturated, where R′ is a hydrogen, alkyl, aryl, alkylaryl, acetyl, heteroatom, or a mixture thereof and R′ is saturated, where R and R′ cannot both be hydrogen, where q is an integer: 2≦q≦75; and mixtures thereof. In certain exemplary embodiments, q is an integer: 2≦q≦10. As used herein, the term “derivatives of oligomeric lactic acid” includes derivatives of oligomeric lactide.
  • [0032]
    Aliphatic polyesters useful in the present invention may be prepared by substantially any of the conventionally known manufacturing methods, including, but not limited to, those described in U.S. Pat. Nos. 6,323,307; 5,216,050; 4,387,769; 3,912,692; and 2,703,316, the relevant disclosures of which are incorporated herein by reference. In addition to the other qualities above, the plasticizers may enhance the degradation rate of the degradable polymeric materials.
  • [0033]
    Polyanhydrides are another type of particularly suitable degradable polymer useful in the present invention. Examples of suitable polyanhydrides include poly(adipic anhydride), poly(suberic anhydride), poly(sebacic anhydride), and poly(dodecanedioic anhydride). Other suitable examples include, but are not limited to, poly(maleic anhydride) and poly(benzoic anhydride).
  • [0034]
    The physical properties of degradable polymers depend on several factors, including, inter alia, the composition of the repeat units, flexibility of the chain, presence of polar groups, molecular mass, degree of branching, crystallinity, and orientation. For example, short-chain branches reduce the degree of crystallinity of polymers while long-chain branches lower the melt viscosity and impart, inter alia, elongational viscosity with tension-stiffening behavior. The properties of the material utilized further can be tailored by blending, and copolymerizing it with another polymer, or by changing the macromolecular architecture (e.g., hyper-branched polymers, star-shaped, or dendrimers, etc.). The properties of any such suitable degradable polymers (e.g., hydrophobicity, hydrophilicity, rate of degradation, etc.) can be tailored by introducing select functional groups along the polymer chains. For example, poly(phenyllactide) will degrade at about ⅕th of the rate of racemic poly(lactide) at a pH of 7.4 at 55° C. One of ordinary skill in the art, with the benefit of this disclosure, will be able to determine the appropriate functional groups to introduce to the polymer chains to achieve the desired physical properties of the degradable polymers.
  • [0035]
    In certain exemplary embodiments, the bridging agents used in the treatment fluids of the present invention comprise a degradable aliphatic polyester and a hydrated organic or inorganic compound. Examples of such hydrated organic or inorganic compounds include, but are not limited to, sodium acetate trihydrate, L-tartaric acid disodium salt dihydrate, sodium citrate dihydrate, sodium tetraborate decahydrate, sodium hydrogen phosphate heptahydrate, sodium phosphate dodecahydrate, amylose, starch-based hydrophilic polymers, or cellulose-based hydrophilic polymers. In certain exemplary embodiments, the degradable aliphatic polyester is poly(lactic acid). In certain exemplary embodiments, the hydrated organic or inorganic compound is sodium acetate trihydrate. In certain exemplary embodiments, the lactide units of the aliphatic polyester and releasable water from the hydrated organic or inorganic compound may be present in stoichiometric amounts. In certain exemplary embodiments, the bridging agent comprises a degradable aliphatic polyester and a hydrated organic or inorganic compound in combination with a bridging agent that comprises calcium carbonate in an amount in the range of about 1 pound to about 100 pounds of calcium carbonate per barrel of treatment fluid.
  • [0036]
    The choice of degradable material can depend, at least in part, on the conditions of the well, e.g., well bore temperature. For instance, lactides have been found to be suitable for lower temperature wells, including those within the range of about 60° F. to about 150° F., and polylactides have been found to be suitable for well bore temperatures above this range. Hydrated organic or inorganic compounds also may be suitable for higher temperature wells.
  • [0037]
    Also, we have found that a preferable result is achieved if the degradable material degrades slowly over time as opposed to instantaneously. The slow degradation of the degradable material helps, inter alia, to maintain the stability of the filter cake. The time required for degradation of the degradable material may depend on factors including, but not limited to, the temperature to which the degradable material is exposed, as well as the type of degradable material used. In certain exemplary embodiments, a bridging agent of the present invention comprises a degradable material that does not begin to degrade until at least about 12 to about 24 hours after its placement in the subterranean formation. Certain exemplary embodiments of the treatment fluids of the present invention may comprise degradable materials that may begin degrading in less than about 12 hours, or that may not begin degrading until after greater than about 24 hours.
  • [0038]
    The specific features of the degradable material may be modified so as to maintain the filter cake's filtering capability when the filter cake is intact while easing the removal of the filter cake when such removal becomes desirable. In certain exemplary embodiments, the degradable material has a particle size distribution in the range of from about 0.1 micron to about 1.0 millimeters. Whichever degradable material is utilized, the bridging agents may have any shape, including, but not limited to, particles having the physical shape of platelets, shavings, flakes, ribbons, rods, strips, spheroids, toroids, pellets, tablets, or any other physical shape. One of ordinary skill in the art with the benefit of this disclosure will recognize the specific degradable material and the preferred size and shape for a given application.
  • [0039]
    The filter cake formed by the treatment fluids of the present invention is a “self-degrading” filter cake as defined herein. As referred to herein, the term “self-degrading filter cake” will be understood to mean a filter cake that may be removed without the assistance of a separate “clean up” solution or “breaker” through the well bore, wherein the purpose of such clean up solution or breaker is solely to degrade the filter cake. Though the filter cakes formed by the treatment fluids of the present invention are “self-degrading” filter cakes, an operator nevertheless occasionally may elect to circulate a separate clean up solution or breaker through the well bore under certain circumstances, such as when the operator desires to enhance the rate of degradation of the filter cake.
  • [0040]
    Optionally, the treatment fluids of the present invention also may comprise additives such as weighting agents, emulsifiers, salts, filtration control agents, pH control agents, and the like. Weighting agents are typically heavy minerals such as barite, ilmenite, calcium carbonate, iron carbonate, or the like. Suitable salts include, but not limited to, salts such as calcium chloride, potassium chloride, sodium chloride, and sodium nitrate. Examples of suitable emulsifiers include polyaminated fatty acids, concentrated tall oil derivatives, blends of oxidized tall oil and polyaminated fatty acids, and the like. Examples of suitable polyaminated fatty acids are commercially available from Halliburton Energy Services, Inc., of Houston, Tex., under the trade names “EZMUL” and “SUPERMUL.” An example of a suitable concentrated tall oil derivative is commercially available from Halliburton Energy Services, Inc., of Houston, Tex., under the trade name “FACTANT.” Examples of suitable blends of oxidized tall oil and polyaminated fatty acids are commercially available from Halliburton Energy Services, Inc., of Houston, Tex., under the trade names “INVERMUL®” and “LE MUL.” Examples of suitable filtration control agents include lignites, modified lignites, powdered resins, and the like. An example of a suitable lignite is commercially available from Halliburton Energy Services, Inc., of Houston, Tex., under the trade name “CARBONOX.” An example of a suitable modified lignite is commercially available from Halliburton Energy Services, Inc., of Houston, Tex., under the trade name “BARANEX.” An example of a suitable powdered resin is commercially available from Halliburton Energy Services, Inc., of Houston, Tex., under the trade name “BARABLOK.” Examples of suitable pH control agents include, but are not limited to, calcium hydroxide, potassium hydroxide, sodium hydroxide, and the like. In certain exemplary embodiments, the pH control agent is calcium hydroxide.
  • [0041]
    In an exemplary embodiment of a method of the present invention, a treatment fluid of the present invention may be used as a drilling fluid in a subterranean formation, e.g., by circulating the drilling fluid while drilling a well in contact with a drill bit and a subterranean formation. Accordingly, an exemplary method of the present invention comprises the step of drilling a well bore in a subterranean formation using a treatment fluid comprising a base fluid, a viscosifier, a fluid loss control additive, and a bridging agent that comprises a degradable material. Additional steps may include, inter alia, the step of forming a filter cake in the well bore, and the step of permitting the filter cake to degrade.
  • [0042]
    Another example of a method of the present invention comprises the steps of: placing a treatment fluid in a subterranean formation, the treatment fluid comprising a base fluid, a viscosifier, a fluid loss control additive, and a bridging agent comprising a degradable material; and permitting the bridging agent to form a self-degrading filter cake upon a surface within the formation, whereby fluid loss to the formation through the self-degrading filter cake is reduced. Another example of a method of the present invention is a method of degrading a filter cake in a subterranean formation, the filter cake having been deposited therein by a treatment fluid comprising a bridging agent, comprising the steps of utilizing a bridging agent comprising a degradable material and permitting the degradable material to degrade.
  • [0043]
    An example of a treatment fluid of the present invention comprises 68.9% ACCOLADE BASE by weight, 20.1% water by weight, 3% LE SUPERMUL by weight, 1% ADAPTA by weight, and 7% calcium chloride by weight.
  • [0044]
    To facilitate a better understanding of the present invention, the following examples of some exemplary embodiments are given. In no way should such examples be read to limit, or to define, the scope of the invention.
  • EXAMPLE 1
  • [0045]
    A sample drilling fluid was prepared by adding 80 pounds of calcium carbonate to a barrel of a nonaqueous-based fluid commercially available under the trade name “ACCOLADE,” from Halliburton Energy Services, Inc., of Houston, Tex. The sample drilling fluid was tested using a Model 90B dynamic filtration system that is commercially available from Fann Instruments, Inc., of Houston, Tex. The. sample drilling fluid was circulated through a hollow cylindrical core within the Model 90B, at 100 psi differential pressure and agitated at a setting of 100 sec-1. Filtrate was permitted to leak outwards through the core, thereby building a filter cake on the inside of the core over a time period of 4.5 hours. Next, the sample drilling fluid was displaced from the core and replaced with a conventional breaker solution comprising from 1% to 3% acetic acid by weight. In one test run, the conventional breaker solution comprised 1% acetic acid; in another test run, the conventional breaker solution comprised 3% acetic acid. The conventional breaker solution was permitted to remain in the core, in contact with the filter cake, under 100 psi differential pressure, without stirring. For each test run, the conventional breaker solution fully penetrated the filter cake in about 30 minutes, determined by observation of rapid fluid loss through the core, triggering termination of the test. This simulates, inter alia, the effect of the conventional breaker solution in a subterranean formation, wherein the conventional breaker solution in the well bore would be lost into the formation upon breakthrough of the filter cake.
  • [0046]
    Upon inspection of the filter cake, the penetration was visually observed to have occurred through tiny “pin pricks” within the filter cake, e.g., the conventional breaker solution did not achieve significant clean up of the filter cake, but rather, penetrated through only a very small area. In practice, such breakthrough would likely be undesirable, because the conventional breaker solution would penetrate the filter cake and be lost into the formation through such pinpricks, yet the vast majority of the filter cake would remain unaffected, thereby potentially blocking subsequent production of hydrocarbons from the formation. Accordingly, the above example demonstrates, inter alia, the limitations of conventional drilling fluids and conventional breaker solutions.
  • EXAMPLE 2
  • [0047]
    A white, solid, degradable composite material of the present invention comprising npolylactic acid and sodium acetate trihydrate was placed in a test cell at 250° F. and covered in mineral oil. The material was maintained at 250° F. for about 24 hours, during which time a yellow liquid layer of the degraded composite formed at the base of the cell. This example demonstrates, inter alia, that the degradable materials used in exemplary embodiments of the bridging agents of the present invention may be degraded by heat alone, apart from contact with any external degrading agent.
  • [0048]
    Therefore, the present invention is well adapted to carry out the objects and attain the ends and advantages mentioned as well as those that are inherent therein. While the invention has been depicted and described by reference to certain exemplary embodiments of the invention, such a reference does not imply a limitation on the invention, and no such limitation is to be inferred. The invention is capable of considerable modification, alternation, and equivalents in form and function, as will occur to those ordinarily skilled in the pertinent arts and having the benefit of this disclosure. The depicted and described embodiments of the invention are exemplary only, and are not exhaustive of the scope of the invention. Consequently, the invention is intended to be limited only by the spirit and scope of the appended claims, giving full cognizance to equivalents in all respects.

Claims (91)

  1. 1. A method of drilling a well bore in a subterranean formation, comprising the step of drilling a well bore in a subterranean formation using a treatment fluid comprising a base fluid, a viscosifier, a fluid loss control additive, and a bridging agent that comprises a degradable material.
  2. 2. The method of claim 1 further comprising the step of permitting the bridging agent to form a filter cake in the well bore.
  3. 3. The method of claim 2 wherein the step of permitting the bridging agent to form a filter cake in the well bore comprises forming the filter cake upon a surface in the formation.
  4. 4. The method of claim 2 further comprising the step of permitting the filter cake to degrade.
  5. 5. The method of claim 1 wherein the base fluid comprises an organic fluid.
  6. 6. The method of claim 5 wherein the organic fluid comprises a mineral oil, a synthetic oil, or an ester.
  7. 7. The method of claim 6 wherein the organic fluid is kerosene or diesel.
  8. 8. The method of claim 1 wherein the base fluid is present in the treatment fluid in an amount sufficient to form a pumpable treatment fluid.
  9. 9. The method of claim 8 wherein the base fluid is present in the treatment fluid in an amount in the range of from about 20% to about 99% by volume of the treatment fluid.
  10. 10. The method of claim 1 wherein the viscosifier comprises an organophilic clay, a synthetic oil-soluble polymer, or a polymeric fatty acid.
  11. 11. The method of claim 10 wherein the viscosifier is an organophilic clay.
  12. 12. The method of claim 1 wherein the viscosifier is present in the treatment fluid in an amount sufficient to provide a desired degree of solids suspension.
  13. 13. The method of claim 1 wherein the viscosifier is present in the treatment fluid in an amount in the range of from about 1 to about 20 pounds viscosifier per barrel of treatment fluid.
  14. 14. The method of claim 1 wherein the fluid loss control additive comprises a synthetic oil-soluble polymer, a powdered hydrocarbon resin, or organophilic lignite.
  15. 15. The method of claim 1 wherein the fluid loss control additive is a synthetic, oil-soluble polymer.
  16. 16. The method of claim 1 wherein the fluid loss control additive is present in the treatment fluid in an amount sufficient to provide a desired degree of fluid loss control.
  17. 17. The method of claim 1 wherein the fluid loss control additive is present in the treatment fluid in an amount in the range of from about 1 to about 30 pounds of fluid loss control additive per barrel of treatment fluid.
  18. 18. The method of claim 1 wherein the bridging agent is present in the treatment fluid in an amount sufficient to create an efficient filter cake.
  19. 19. The method of claim 1 wherein the bridging agent is present in the treatment fluid in an amount in the range of from about 0.1% to about 32% by weight of the treatment fluid.
  20. 20. The method of claim 1 wherein the degradable material comprises a polysaccharide, a chitin, a chitosan, a protein, an orthoester, an aliphatic polyester, a poly(glycolide), a poly(lactide), a poly(ε-caprolactone), a poly(hydroxybutyrate), a polyanhydride, an aliphatic polycarbonate, a poly(orthoester), a poly(amino acid), a poly(ethylene oxide), or a polyphosphazene.
  21. 21. The method of claim 1 wherein the degradable material further comprises a plasticizer or a stereoisomer of a poly(lactide).
  22. 22. The method of claim 1 wherein the degradable material comprises poly(lactic acid).
  23. 23. The method of claim 22 wherein the poly(lactic acid) is present in the degradable material in a stoichiometric amount.
  24. 24. The method of claim 1 wherein the degradable material comprises a degradable aliphatic polyester and a hydrated organic or inorganic compound.
  25. 25. The method of claim 24 wherein the hydrated organic or inorganic compound comprises sodium acetate trihydrate, L-tartaric acid disodium salt dihydrate, sodium citrate dihydrate, sodium tetraborate decahydrate, sodium hydrogen phosphate heptahydrate, sodium phosphate dodecahydrate, amylose, a starch-based hydrophilic polymer, or a cellulose-based hydrophilic polymer.
  26. 26. The method of claim 24 wherein the degradable aliphatic polyester is present in the degradable material in a stoichiometric amount.
  27. 27. The method of claim 26 wherein the hydrated organic or inorganic compound is present in the degradable material in a stoichiometric amount.
  28. 28. The method of claim 24 wherein the degradable aliphatic polyester is poly(lactic acid).
  29. 29. The method of claim 24 wherein the degradable material further comprises calcium carbonate.
  30. 30. The method of claim 4 wherein the bridging agent does not begin to degrade until at least about 12 hours after its placement in the subterranean formation.
  31. 31. The method of claim 1 wherein the treatment fluid further comprises a weighting agent, a salt, an emulsifier, a filtration control agent, and a pH control agent.
  32. 32. The method of claim 4 wherein the base fluid is an organic fluid, present in the treatment fluid in an amount in the range of from about 20% to about 99% by volume of the treatment fluid; wherein the fluid loss control additive is a synthetic, oil-soluble polymer, present in the treatment fluid in an amount in the range of from about 1 to about 30 pounds fluid loss control additive per barrel of treatment fluid; wherein the viscosifier is present in the treatment fluid in an amount in the range of from about 1 to about 20 pounds per barrel of treatment fluid; wherein the bridging agent is present in the treatment fluid in an amount in the range of from about 0.1% to about 32% by weight of the treatment fluid; and wherein the degradable material comprises a degradable aliphatic polyester and a hydrated organic or inorganic compound.
  33. 33. A method of forming a self-degrading filter cake in a subterranean formation, comprising the steps of:
    placing a treatment fluid in a subterranean formation, the treatment fluid comprising a base fluid, a viscosifier, a fluid loss control additive, and a bridging agent that comprises a degradable material; and
    permitting the bridging agent to form a self-degrading filter cake upon a surface in the formation, whereby fluid loss to the formation through the self-degrading filter cake is reduced.
  34. 34. The method of claim 33 wherein the step of permitting the bridging agent to form a filter cake in the well bore comprises forming the filter cake upon a surface in the formation itself.
  35. 35. The method of claim 33 wherein the base fluid comprises an organic fluid.
  36. 36. The method of claim 35 wherein the organic fluid comprises a mineral oil, a synthetic oil, or an ester.
  37. 37. The method of claim 36 wherein the organic fluid is kerosene or diesel.
  38. 38. The method of claim 33 wherein the base fluid is present in the treatment fluid in an amount in the range of from about 20% to about 99% by volume of the treatment fluid.
  39. 39. The method of claim 33 wherein the viscosifier is present in the treatment fluid in an amount in the range of from about 1 to about 20 pounds viscosifier per barrel of treatment fluid.
  40. 40. The method of claim 33 wherein the fluid loss control additive is present in the treatment fluid in an amount in the range of from about 1 to about 30 pounds fluid loss control additive per barrel of treatment fluid.
  41. 41. The method of claim 33 wherein the bridging agent is present in the treatment fluid in an amount in the range of from about 0.1% to about 32% by weight of the treatment fluid.
  42. 42. The method of claim 33 wherein the degradable material comprises poly(lactic acid).
  43. 43. The method of claim 33 wherein the degradable material comprises a degradable aliphatic polyester and a hydrated organic or inorganic compound.
  44. 44. The method of claim 43 wherein the degradable aliphatic polyester is poly(lactic acid).
  45. 45. The method of claim 33 wherein the base fluid is an organic fluid, present in the treatment fluid in an amount in the range of from about 20% to about 99% by volume of the treatment fluid; wherein the fluid loss control additive is a synthetic, oil-soluble polymer, present in the treatment fluid in an amount in the range of from about 1 to about 30 pounds fluid loss control additive per barrel of treatment fluid; wherein the viscosifier is present in the treatment fluid in an amount in the range of from about 1 to about 20 pounds per barrel of treatment fluid; wherein the bridging agent is present in the treatment fluid in an amount in the range of from about 0.1% to about 32% by weight of the treatment fluid; and wherein the degradable material comprises a degradable aliphatic polyester and a hydrated organic or inorganic compound.
  46. 46. A method of degrading a filter cake in a subterranean formation, the filter cake having been deposited therein by a treatment fluid comprising a bridging agent, comprising the steps of:
    utilizing a bridging agent comprising a degradable material; and
    permitting the degradable material to degrade.
  47. 47. The method of claim 46 wherein the treatment fluid further comprises a base fluid, a viscosifier, and a fluid loss control additive.
  48. 48. The method of claim 47 wherein the base fluid comprises an organic fluid.
  49. 49. The method of claim 48 wherein the organic fluid comprises a mineral oil, a synthetic oil, or an ester.
  50. 50. The method of claim 49 wherein the organic fluid is kerosene or diesel.
  51. 51. The method of claim 46 wherein the base fluid is present in the treatment fluid in an amount in the range of from about 20% to about 99% by volume of the treatment fluid.
  52. 52. The method of claim 47 wherein the viscosifier is present in the treatment fluid in an amount in the range of from about 1 to about 20 pounds per barrel of treatment fluid.
  53. 53. The method of claim 47 wherein the fluid loss control additive is present in the treatment fluid in an amount in the range of from about 1 to about 30 pounds fluid loss control additive per barrel of treatment fluid.
  54. 54. The method of claim 46 wherein the bridging agent is present in the treatment fluid in an amount in the range of from about 0.1% to about 32% by weight of the treatment fluid.
  55. 55. The method of claim 46 wherein the degradable material comprises poly(lactic acid).
  56. 56. The method of claim 46 wherein the degradable material comprises a degradable aliphatic polyester and a hydrated organic or inorganic compound.
  57. 57. The method of claim 56 wherein the degradable aliphatic polyester is poly(lactic acid).
  58. 58. The method of claim 47 wherein the base fluid is an organic fluid, present in the treatment fluid in an amount in the range of from about 20% to about 99% by volume of the treatment fluid; wherein the fluid loss control additive is a synthetic, oil-soluble polymer, present in the treatment fluid in an amount in the range of from about 1 to about 30 pounds fluid loss control additive per barrel of treatment fluid; wherein the viscosifier is present in the treatment fluid in an amount in the range of from about 1 to about 20 pounds per barrel of treatment fluid; wherein the bridging agent is present in the treatment fluid in an amount in the range of from about 0.1% to about 32% by weight of the treatment fluid; and wherein the degradable material comprises a degradable aliphatic polyester and a hydrated organic or inorganic compound.
  59. 59. A treatment fluid comprising a viscosifier, a fluid loss control additive, and a bridging agent comprising a degradable material.
  60. 60. The treatment fluid of claim 59 further comprising a base fluid.
  61. 61. The treatment fluid of claim 60 wherein the base fluid comprises an organic fluid.
  62. 62. The treatment fluid of claim 61 wherein the organic fluid comprises a mineral oil, a synthetic oil, or an ester.
  63. 63. The treatment fluid of claim 62 wherein the organic fluid is kerosene or diesel.
  64. 64. The treatment fluid of claim 60 wherein the base fluid is present in an amount sufficient to form a pumpable treatment fluid.
  65. 65. The treatment fluid of claim 64 wherein the base fluid is present in an amount in the range of from about 20% to about 99% by volume of the treatment fluid.
  66. 66. The treatment fluid of claim 65 wherein the viscosifier comprises an organophilic clay, a synthetic, oil-soluble polymer, or a polymeric fatty acid.
  67. 67. The treatment fluid of claim 66 wherein the viscosifier is an organophilic clay.
  68. 68. The treatment fluid of claim 59 wherein the viscosifier is present in an amount sufficient to provide a desired degree of solids suspension.
  69. 69. The treatment fluid of claim 68 wherein the viscosifier is present in an amount in the range of from about 1 to about 20 pounds viscosifier per barrel of treatment fluid.
  70. 70. The treatment fluid of claim 59 wherein the fluid loss control additive comprises a synthetic, oil-soluble polymer, a powdered hydrocarbon resin, or organophilic lignite.
  71. 71. The treatment fluid of claim 70 wherein the fluid loss control additive is a synthetic, oil-soluble polymer.
  72. 72. The treatment fluid of claim 59 wherein the fluid loss control additive is present in an amount sufficient to provide a desired degree of fluid loss control.
  73. 73. The treatment fluid of claim 71 wherein the fluid loss control additive is present in an amount in the range of from about 1 to about 30 pounds per barrel of treatment fluid.
  74. 74. The treatment fluid of claim 59 wherein the bridging agent comprising the degradable material is present in an amount sufficient to create an efficient filter cake.
  75. 75. The treatment fluid of claim 74 wherein the bridging agent is present in an amount in the range of from about 0.1% to about 32% by weight of the treatment fluid.
  76. 76. The treatment fluid of claim 59 wherein the degradable material comprises a polysaccharide, a chitin, a chitosan, a protein, an orthoester, an aliphatic polyester, a poly(glycolide), a poly(lactide), a poly(ε-caprolactone), a poly(hydroxybutyrate), a polyanhydride, an aliphatic polycarbonate, a poly(orthoester), a poly(amino acid), a poly(ethylene oxide), or a polyphosphazene.
  77. 77. The treatment fluid of claim 59 wherein the degradable material further comprises a plasticizer or a stereoisomer of a poly(lactide).
  78. 78. The treatment fluid of claim 59 wherein the degradable material comprises
  79. 79. The treatment fluid of claim 78 wherein the poly(lactic acid) is present in the degradable material in a stoichiometric amount.
  80. 80. The treatment fluid of claim 59 wherein the degradable material comprises a degradable aliphatic polyester and a hydrated organic or inorganic compound.
  81. 81. The treatment fluid of claim 80 wherein the hydrated organic or inorganic compound comprises sodium acetate trihydrate, L-tartaric acid disodium salt dihydrate, sodium citrate dihydrate, sodium tetraborate decahydrate, sodium hydrogen phosphate heptahydrate, sodium phosphate dodecahydrate, amylose, a starch-based hydrophilic polymer, or a cellulose-based hydrophilic polymer.
  82. 82. The treatment fluid of claim 80 wherein the degradable aliphatic polyester is present in the degradable material in a stoichiometric amount.
  83. 83. The treatment fluid of claim 80 wherein the hydrated organic or inorganic compound is present in the degradable material in a stoichiometric amount.
  84. 84. The treatment fluid of claim 80 wherein the degradable aliphatic polyester is poly(lactic acid).
  85. 85. The treatment fluid of claim 80 wherein the degradable material further comprises calcium carbonate.
  86. 86. The treatment fluid of claim 59 wherein the bridging agent does not begin to degrade until at least about 12 hours after it has been placed in a subterranean formation.
  87. 87. The treatment fluid of claim 59 wherein the treatment fluid further comprises a weighting agent, a salt, an emulsifier, a filtration control agent, and a pH control agent.
  88. 88. The treatment fluid of claim 59 wherein the base fluid is an organic fluid, present in the treatment fluid in an amount in the range of from about 20% to about 99% by volume of the treatment fluid; wherein the fluid loss control additive is an oil-soluble polymer, present in the treatment fluid in an amount in the range of from about 1 to about 30 pounds fluid loss control additive per barrel of treatment fluid; wherein the viscosifier is present in the treatment fluid in an amount in the range of from about 1 to about 20 pounds per barrel of treatment fluid; wherein the bridging agent is present in the treatment fluid in an amount in the range of from about 0.1% to about 32% by weight of the treatment fluid; and wherein the degradable material comprises a degradable aliphatic polyester and a hydrated organic or inorganic compound.
  89. 89. A bridging agent comprising a degradable material.
  90. 90. The bridging agent of claim 89 wherein the degradable material comprises a polysaccharide, a chitin, a chitosan, a protein, an orthoester, an aliphatic polyester, a poly(glycolide), a poly(lactide), a poly(ε-caprolactone), a poly(hydroxybutyrate), a polyanhydride, an aliphatic polycarbonate, a poly(orthoester), a poly(amino acid), a poly(ethylene oxide), or a polyphosphazene.
  91. 91. The bridging agent of claim 89 wherein the degradable material comprises poly(lactic acid).
US10832163 2003-09-17 2004-04-26 Treatment fluids and methods of use in subterranean formations Abandoned US20050059556A1 (en)

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US11634320 US7674753B2 (en) 2003-09-17 2006-12-05 Treatment fluids and methods of forming degradable filter cakes comprising aliphatic polyester and their use in subterranean formations
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US8541346B2 (en) 2013-09-24 grant
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US20100230108A1 (en) 2010-09-16 application

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