WO2014163947A1 - Protective colloid stabilized fluids - Google Patents

Abstract

A fluid composition and methods of using same are provided, where the fluid composition may include an aqueous continuous phase, a protective colloid, a surfactant, an organic solvent, and a dissolution additive. Also provided are methods of cleaning a wellbore drilled with an invert emulsion fluid or oil-based fluid, the wellbore having an invert emulsion based filtercake or oil-based filtercake on the walls thereof.

Description

PROTECTIVE COLLOID STABILIZED FLUIDS

BACKGROUND

[0001] During the drilling of a wellbore, various fluids are typically used in the well for a variety of functions. The fluids may be circulated through a drill pipe and drill bit into the wellbore, and then may subsequently flow upward through wellbore to the surface. During this circulation, the drilling fluid may act to remove drill cuttings from the bottom of the hole to the surface, to suspend cuttings and weighting material when circulation is interrupted, to control subsurface pressures, to maintain the integrity of the wellbore until the well section is cased and cemented, to isolate the fluids from the formation by providing sufficient hydrostatic pressure to prevent the ingress of formation fluids into the wellbore, to cool and lubricate the drill string and bit, and/or to maximize penetration rate.

[0002] One way of protecting the formation is by forming a filtercake on the surface of the subterranean formation. Filtercakes are formed when particles suspended in a wellbore fluid coat and plug the pores in the subterranean formation such that the filtercake prevents or reduce both the loss of fluids into the formation and the influx of fluids present in the formation. A number of ways of forming filtercakes are known in the art, including the use of bridging particles, cuttings created by the drilling process, polymeric additives, and precipitates. Fluid loss pills may also be used where a viscous pill comprising a polymer may be used to reduce the rate of loss of a wellbore fluid to the formation through its viscosity.

[0003] Upon completion of drilling, the filtercake and/or fluid loss pill may stabilize the wellbore during subsequent completion operations such as placement of a gravel pack in the wellbore. Additionally, during completion operations, when fluid loss is suspected, a fluid loss pill of polymers may be spotted into to reduce or prevent such fluid loss by injection of other completion fluids behind the fluid loss pill to a position within the wellbore which is immediately above a portion of the formation where fluid loss is suspected. Injection of fluids into the wellbore is then stopped, and fluid loss will then move the pill toward the fluid loss location. [0004] After any completion operations have been accomplished, removal of filtercake

(formed during drilling and/or completion) remaining on the sidewalls of the wellbore may be desired. Although filtercake formation and use of fluid loss pills are useful in drilling and completion operations, the barriers can be a significant impediment to the production of hydrocarbon or other fluids from the well if, for example, the rock formation is still plugged by the barrier. Because filtercake is compact, it often adheres strongly to the formation and may not be readily or completely flushed out of the formation by fluid action alone.

[0005] The problems of efficient well clean-up and completion are a significant issue in all wells, and especially in open-hole horizontal well completions. The productivity of a well is somewhat dependent on effectively and efficiently removing the filtercake while minimizing the potential of water blocking, plugging, or otherwise damaging the natural flow channels of the formation, as well as those of the completion assembly.

SUMMARY

[0006] In one aspect, embodiments disclosed herein relate to fluid compositions that include an aqueous continuous phase; a protective colloid; a surfactant; an organic solvent; and a dissolution additive.

[0007] In another aspect, embodiments disclosed herein are directed to methods of cleaning a wellbore drilled with an invert emulsion fluid or oil-based fluid that forms an invert emulsion or oil-based filtercake, the method including: emplacing a fluid composition into the wellbore, the fluid composition containing: an aqueous continuous phase, a protective colloid, a surfactant, an organic solvent, and a dissolution additive; and shutting in the well for a period of time sufficient to initiate breaking of the filtercake.

[0008] In yet another aspect, embodiments disclosed here are directed to methods of cleaning a surface contaminated with an oleaginous residue, the method including: contacting a surface with an effective amount of a fluid composition, the fluid composition containing: an aqueous continuous phase, a protective colloid, a surfactant, an organic solvent, and a dissolution additive; and forming an aqueous emulsion, wherein the aqueous emulsion contains the oleaginous residue in an internal oleaginous phase.

[0009] This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

BRIEF DESCRIPTION OF DRAWINGS

[0010] FIG. 1 is a graphical illustration showing the dissolution of oil-based muds when treated with breaker fluid formulations according to embodiments disclosed herein.

[0011] FIG. 2 is a graphical illustration showing the comparison of performance of breaker fluid according to embodiments disclosed herein in comparison to other surfactant-based breaker fluids.

DETAILED DESCRIPTION

[0012] Fluid compositions according to embodiments herein may provide for efficient and complete or near-complete solubilization of oil-based fluids within an external aqueous phase, which may be beneficial in cleanup, storage, and removal applications. In particular embodiments, removal of oil-based filtercakes deposited from oil-based or invert emulsion drilling fluids, do not inhibit the ability of the formation to produce oil or gas once the well is brought into production. Fluids according to embodiments herein may form emulsions that include protective colloids that stabilize the discontinuous phase of the emulsion, preventing or reducing the separation of the emulsion into its constituent organic and aqueous phases even in the presence of elevated temperatures or high salinity fluids.

[0013] One or more embodiments disclosed herein relate generally to fluid compositions for use in breaking filtercakes formed on wellbore walls. Particularly, some embodiments disclosed herein may relate to methods and breaker fluid formulations for breaking filtercakes formed on wellbore walls from oil-based or invert emulsion fluids. As discussed above, filtercakes are formed on walls of a subterranean borehole (or along the interior of a gravel pack screen, for example) to reduce the permeability of the walls into and out of the formation (or screen). Some filtercakes are formed during the drilling stage to limit losses from the well bore and protect the formation from possible damage by fluids and solids within the well bore, while others are formed from spotted fluid loss pills to similarly reduce or prevent the influx and efflux of fluids across the formation walls. Also reducing the influx and efflux of fluids across a formation wall are fluid loss pills, which prevent such fluid movement by the pills' viscosity. Further, one skilled in the art would appreciate that in addition to a base fluid, the filtercake may also comprise other components such as drill solids, bridging/weighting agents, surfactants, fluid loss control agents, and viscosifying agents as residues left by the drilling fluid or fluid loss pill. Examples of bridging/weighting agents include, but are not limited to, calcium carbonate, barite, and manganese oxide, among others.

[0014] In accordance with embodiments of the present disclosure, methods are provided for removing an oil-based filtercake (formed from drilling with an oil-based mud) via the formation of an oil-in-water emulsion. Some oil-based muds used in drilling may be invert emulsions, that is, water-in-oil emulsions, and remain invert emulsions upon formation of a filtercake. Upon exposure of an invert emulsion filtercake to the fluid compositions of the present disclosure, the invert emulsion may "flip" such that the oleaginous fluid (continuous phase in the invert emulsion) becomes emulsified within an external aqueous phase.

[0015] The term "oil-in-water emulsion" refers to emulsions wherein the continuous phase is an aqueous phase and the discontinuous phase is oil, which is dispersed within the continuous phase. When combining the two immiscible fluids (aqueous and oleaginous) without the use of a stabilizing emulsifier, while it is possible to initially disperse or emulsify one fluid within the other, after a period of time, the discontinuous, dispersed fluid droplets coalesce or flocculate, for example, due to the instability of the formed emulsion. Thus, to stabilize the emulsion, a surfactant may be used. Whether an emulsion turns into a water-in-oil emulsion or an oil-in-water emulsion depends on the volume fraction of both phases and on the type of surfactant. [0016] Fluid compositions in accordance with embodiments of the present disclosure may form oil-in-water emulsions, where an organic solvent is mixed with an aqueous base fluid, for example. The term "oil-in-water emulsion refers to emulsions wherein the continuous phase is an aqueous phase and the discontinuous phase is oil, which is dispersed within the continuous phase. When combining the two immiscible fluids (aqueous and oleaginous) without the use of a stabilizing emulsifier, while it is possible to initially disperse or emulsify one fluid within the other, after a period of time, the discontinuous, dispersed fluid droplets coalesce or flocculate, for example, due to the instability of the formed emulsion. Thus, to stabilize the emulsion, a protective colloid and/or a surfactant (or emulsifier) may be used. Whether an emulsion turns into a water-in-oil emulsion or an oil-in-water emulsion depends on the volume fraction of both phases and on the type of surfactant employed.

[0017] Protective Colloid

[0018] In the fluid composition formulations of the present disclosure a protective colloid may be added to protect other colloids from the coagulative effect of electrolytes and other agents. For example, protective colloids may form a protective film around emulsion droplets that increases the stability of the colloidal phase and increases the resistance of emulsions to phase separation at extreme temperatures and high ionic strength salt solutions (i.e., brines).

[0019] In some applications, the presence of an aqueous fluid with a high salt content, such as seawater or brine, may prevent conventional surfactants from stabilizing an emulsion or prevent its ability to partition into distinct organic and aqueous phases. For clean-up operations, for example, on a section of a wellbore having high bottom hole pressures (requiring greater hydrostatic pressures to support the bottom hole pressures), it may be desirable to use a brine-based fluid to achieve required hydrostatic pressure.

[0020] The instability of the oil-in-brine emulsion may be explained by examining the principles of colloid chemistry. The stability of a colloidal dispersion (or emulsion when the dispersion is liquid-in-liquid) is determined by the behavior of the surface of the constituent particle via its surface charge and short-range attractive van der Waals forces. Electrostatic repulsion prevents dispersed particles from combining into their most thermodynamically stable state of aggregation into a macroscopic form, thus rendering the dispersions or emulsions metastable. Emulsions are metastable systems for which phase separation of the oil and water phases represents to the most stable thermodynamic state due to the addition of a surfactant to reduce the interfacial energy between oil and water.

[0021] Oil-in- water emulsions may be stabilized by both electrostatic stabilization

(electric double layer between the two phases) and steric stabilization (van der Waals repulsive forces), whereas invert emulsions (water-in-oil) may be stabilized by steric stabilization. The addition of salts, however, may result in a reduced electrical double layer. As the double layer decreases, and the distance between two oil droplets is reduced, the oil droplets have more chances to collide with each other and coalesce. Thus, the increase of salt concentration in an emulsion system will increase the electrical conductivity and will in turn destabilize emulsions. Other ways in which salts may potentially destabilize an emulsion include reversible flocculation, irreversible flocculation, change in proton concentrations, etc. Thus, when salts are added to an oil- in-water emulsion stabilized by a conventional emulsifier, the salts, aqueous fluid, and oleaginous fluid are separated into three distinct phases.

[0022] In one or more embodiments of the instant disclosure, the protective colloid may be a derivatized natural polymer, such as an amphiphilic polysaccharide, where the hydrophilic natural polymer backbone has been chemically modified with hydrophobic side chains. While not limited to a particular theory, the hydrophobic side chains may anchor the molecules to droplet surface of the internal phase of the emulsion, while the hydrophilic polysaccharide blocks extend into the aqueous continuous phase, providing stability against droplet aggregation through steric and electrostatic repulsion. Thus, the protective colloids of the present disclosure may be substantially larger molecules than conventional surfactants, but their amphiphilic nature may be used to stabilize an oleaginous phase within an aqueous phase and to do so at higher temperatures and brine concentrations than conventional surfactants. [0023] The protective colloids useful in embodiments of the present disclosure may be selected from, for example, derivatized natural polymers selected from the group consisting of cellulose, modified celluloses such as hydroxyethyl cellulose, hydroxypropy cellulose, or carboxymethyl cellulose, gelatin, glycoproteins or oligo-peptide modified polysaccharides such as gum arabic, starches or modified starches such as corn, potato, wheat, rice, sago, tapioca, waxy maize, sorghum, amylose, and the like. Natural polymers may be derivatized by reacting groups present on the polymer backbone (e.g., hydroxyl, carboxylic, formyl, or amine functional groups) with small molecules or polymers that contain reactive groups such as, for example, alkenyl, epoxy, halogen, or carboxylic acid functional groups.

[0024] In embodiments, the protective colloid may be formed from the esterification of a natural polymer or modified natural polymer with one or more aliphatic C2-24 carboxylic acids. The carboxylic acid component of such an ester can be derived from a lower alkane acid, such as acetic acid, propionic acid or butyric acid or a mixture thereof. However, the carboxylic acid component can also originate from a saturated on unsaturated native fatty acid. Examples of these include palmitic acid, stearic acid, oleic acid, linoleic acid, or mixtures thereof. In addition to carboxylic acids, the corresponding acid anhydrides and acid chlorides and other similar reactive acid derivatives can also be used in forming the ester by known methods.

[0025] In addition to carboxylic acids, other hydrophobic anionic groups may be covalently attached to natural polymers and modified natural polymers, such as by reacting the natural polymer with an alkyl succinic anhydride or alkenyl succinic anhydride. In embodiments, the alkyl or alkenyl chain may vary from 4-24 carbons, including, for example, octenyl succinic anhydride, nonyl succinic anhydride, decyl succinic anhydride, dodecenyl succinic anhydride, etc. The esterification reaction to introduce the desired alkyl or alkenyl succinate groups can be performed in any manner as known in the art. In some embodiments, for example, the protective colloid may be the octenyl succinic anhydride (OSA) modified starch CLEARGUM® CO 01, available from Roquette Foods (Keokuk, IA). [0026] In other embodiments, cellulose derivatives that may be included in fluid compositions of the present disclosure include cationic quaternized cellulose derivatives such as laurdimonium hydroxyethyl cellulose, steardimonium hydroxyethylcellulose, cocodimonium hydroxyethylcellulose, and cocodimonium hydroxypropyl oxyethyl cellulose. In some embodiments, the protective colloid may be CRODACEL® QM available from Croda Chemicals Europe.

[0027] Protective colloids that may be incorporated into the fluid compositions of the present disclosure may also include natural polymers derivatized with one or more of a number of molecules including isobutyrate, vinyl pivalate, vinyl-2-ethylhexanoate, vinyl esters of saturated branched monocarboxylic acids having 9 or 10 carbon atoms in the acid residue, vinyl esters of long-chain, saturated or unsaturated fatty acids such as vinyl laurate, vinyl stearate, and vinyl esters of benzoic acid and derivatives of benzoic acid such as p-tert-butylbenzoate.

[0028] In yet other embodiments, the protective colloid may be a synthetic polymer such as polyvinylpyrrolidone, polyacrylic acids, polyacrylamide, polyvinyl alcohol, polyethylene oxide, polyalkyl oxazoline, and copolymers, derivatives, or mixtures thereof.

[0029] In embodiments, protective colloids may be incorporated into fluid compositions in accordance with the present disclosure at a percent by volume (vol%) up to 5 vol%. In other embodiments, protective colloids may be incorporated into fluid compositions at 0.2 vol% to 5 vol%. In still other embodiments, the protective colloids may be incorporated into fluid compositions at 0.5 vol% to 1 vol%.

[0030] Surfactants

[0031] In addition, to aid the formation of an oil-in- water emulsion, fluid compositions in accordance with the present disclosure may also contain at least one surfactant that serves to affect the wettability of the filtercake. Specifically, an invert emulsion filtercake will be "oil-wet" and thus incompatible with aqueous breaker fluids or oil-in- water emulsion breaker fluids that may not readily penetrate into the filtercake. However, the incorporation of a surfactant into the breaker fluid may allow for the penetration of the surfactant into the oil-wet filtercake and shift the wettability from oil- wet to water- wet to aid in the breaking of the filtercake.

[0032] Generally, the Bancroft rule applies to the behavior of emulsions: surfactants and emulsifying particles tend to promote dispersion of the phase in which they do not dissolve very well; for example, a compound that dissolves better in water than in oil tends to form oil-in-water emulsions (that is they promote the dispersion of oil droplets throughout a continuous phase of water). Emulsifiers may be amphiphilic. That is, they possess both a hydrophilic portion and a hydrophobic portion. The chemistry and strength of the hydrophilic polar group compared with those of the lipophilic nonpolar group determine whether the emulsion forms as an oil-in-water or water-in-oil emulsion. In particular, emulsifiers may be evaluated based on their HLB value. The term "HLB" (Hydrophilic Lipophilic Balance) refers to the ratio of the hydrophilicity of the polar groups of the surface-active molecules to the hydrophobicity of the lipophilic part of the same molecules. To form an oil-in-water emulsion, a surfactant or a mixture of surfactants having a high HLB, such as greater than 11, may be desirable. In some embodiments, the HLB value of the emulsifier may range from 11 to 16.

[0033] In an embodiment, surfactants used to stabilize the breaker fluid formulations of the present disclosure may include alkyl amine oxide surfactants such as C10-C18 dimethyl amine oxides or C10-C18 amidopropyl dimethyl amine oxides that may include, for example, lauryldimethylamine oxide, hexyldimethylamine oxide, octyldimethylamine oxide, decyldimethylamine oxide, dodecyldimethylamine oxide, eicosyldimethylamine oxide, docosyldimethylamine oxide, tetracosyldimethylamine oxide, myristyldimethylamine oxide, and the like. Commercially available alkyl dimethylamine oxide surfactants include, for example, TEGOTENS™ DO available from Evonik Industries AG.

[0034] In other embodiments surfactants may be selected from C10-C18 amidopropyl betaines, alkyl mono- and di-ethanolamides, sulfobetaines, derivatives thereof and combinations thereof such as, for example, Ammonyx® LMDO (lauramidopropyl amine oxide and myristamidopropyl amine oxide), Amphosol® LB (Lauryl Amidopropyl Betaine), Ammonyx® LO (lauramine oxide), Ninol® LMP, Ninol® 40-CO, Petrostep® SB, Amphosol® SB, Amphosol® CS-50, and the like, which are commercially available from the Stepan Company (Northfield,IL). Other surfactants within the scope of the present disclosure include fatty acid alkanolamides obtained by reacting a fatty acid, such as a C9-18 fatty acid, with an alkanolamine to produce, for example, cocodiethanolamide.

[0035] Further, one skilled in the art would appreciate that other surfactants or emulsifying agents may be used, including nonionic, cationic or anionic emulsifying agents, as long as a hydrophilic/lipophilic balance sufficient to obtain a stable emulsion of oil into water or brine. Examples of other surfactants that may produce an oil-in- water emulsion may include alkyl aryl sulfonates, alkyl sulfonates, alkyl phosphates, alkyl aryl sulfates, ethoxylated fatty acids, ethoxylated amines, ethoxylated phenols, polyoxyethylene fatty acids, esters, ethers and combinations thereof. Blends of these materials as well as other emulsifiers and surfactants may also be used for this application. In a particular embodiment, an anionic surfactant such as alkyl aryl sulfonates, an example of which includes dodecylbenzyl sulfonic acid, may be included in breaker fluids in accordance with embodiments of this disclosure to provide for reaction with calcium carbonate in the filtercake.

[0036] In embodiments, surfactants may be incorporated into fluid compositions at a percent volume up to about 15 vol%. In other embodiments, surfactants may be incorporated into fluid compositions at 1 vol% to 15 vol%. In still other embodiments, surfactants may be incorporated into fluid compositions at 2 vol% to 10 vol%.

[0037] Organic Solvent

[0038] Fluid compositions disclosed herein may contain an oleaginous or organic solvent contained within an internal phase capable of disrupting or dissolving filtercakes deposited from oil-based drilling muds (OBM). Organic solvents in accordance with embodiments of this disclosure may be selected based on Hansen solubility parameters, which quantify various properties for a number of solvents. The parameters are subdivided into three basic categories: the dispersion force (/¾ that characterizes the London dispersion forces resulting from the formation of dipoles induced during molecular impacts, the polar force (f_p) that characterizes the forces of Debye interactions between permanent dipoles and the forces of Keesom interactions between induced dipoles and permanent dipoles; and the hydrogen bonding force (/¾) that characterizes the forces of specific interactions such as hydrogen bonds, acid/base, donor/acceptor, and the like. The parameters f_d,f_P, and_/_¾ are expressed in J/cm³. These parameters and the calculation thereof are described in detail in the article by C. M. Hansen: "The three-dimensional solubility parameters," J. Paint Technol., 39, 105 (1967).

[0039] Organic solvents with similar solubility parameters may have different solvating power due to the nature of their molecular composition. This distinction is best described by the Hansen solubility parameter (HSP), which is a combination of dispersive, polar, and hydrogen bonding solubility parameters observed for the respective compounds. Having this property in mind, a cocktail of solvents may be prepared to have a specified solubility parameter to ensure solvency of the solute, while providing other properties such as relatively lower surface tension for viscosity reduction. The Applicant has discovered that solvents which interact strongly with oil- based filtercakes and give rapid breaker leak off (BLO) may have similar HSPs. In some embodiments, the fluid compositions may be formulated to contain solvents having HSPs within the range of 0.7 to 0.9/_A, 0.1 to 0.3 f_p, and 0.3 to 0.6 f_d.

[0040] In some embodiments, the organic solvent may be selected from alkyl amide solvents that include C8-14 dialkyl amides and C8-14 dialkyl amides such as, for example, Ν,Ν-dimethyloctanamide and Ν,Ν-dimethyldecanamide, or selected from alkyl mono- or di-ethanolamides such as lauryl monoethanolamide or myristyl monoethanolamide, for example. In some embodiments, the alkyl amide solvent may be STEPOSOL™ M8-10 available from the Stepan Company (Northfield, IL).

[0041] In other embodiments, organic solvents may include esters of aliphatic C2-5 carboxylic acids and C4-C22 alcohols or polyols such as, for example, methyl laurate, ethyl laurate, methyl myristate, ethyl myristate, butyl lactate, ethyl lactate, isopropyl lactate, isopropyl palmitate, propylene carbonate, and butylene carbonate. In yet other embodiments, the solvent may be one selected from glycol ethers such as those formed from C1-C6 alcohols and C2-12 glycols including, but not limited to, dipropylene glycol methyl ether, hexylene glycol methyl ether, ethylene glycol monobutyl ether (EGMBE), and triethylene glycol monobutyl ether.

[0042] Fluid compositions in accordance with embodiments of the present disclosure may include organic solvents incorporated at a percent volume up to about 20 vol%. In other embodiments, organic solvents may be incorporated into the fluid composition at a vol% having a lower limit equal to or greater than 1 vol%, 2 vol%, 5 vol%, 8 vol%, and 10 vol% to an upper limit of less than 15 vol%, 18 vol%, 20 vol%, 22 vol%, 25 vol% and 30 vol%, where the vol% incorporation of an organic solvent may range from any lower limit to any upper limit.

[0043] Dissolution Additive

[0044] Fluid compositions of the present disclosure may also be formulated to contain a dissolution additive to aid in the disruption and solubilization of organic deposits such as, for example, filtercakes (and filtercake components) present within a wellbore. Suitable dissolution additives may include acid sources and/or chelants. Examples of acid sources that may be used as breaker fluid additives include strong mineral acids, such as hydrochloric acid or sulfuric acid, and organic acids, such as citric acid, salicylic acid, lactic acid, malic acid, acetic acid, and formic acid. Suitable organic acids that may be used as the acid sources may include citric acid, salicylic acid, glycolic acid, malic acid, maleic acid, fumaric acid, and homo- or copolymers of lactic acid and glycolic acid as well as compounds containing hydroxy, phenoxy, carboxylic, hydroxycarboxylic or phenoxycarboxylic moieties. In embodiments, the acid source may be CAL-ACID™, a mixture of an organic acid and a corrosion inhibitor available from M-I L.L.C. (Houston, TX).

[0045] The addition of acid sources to fluid formulations in accordance with the instant disclosure may also be desirable to aid in the solubilization acid-sensitive solutes that are present in the oil-based material being solubilized. Examples of acid-sensitive solutes include particulate carbonates, as well as polymeric additives that may be present in a filtercake.

[0046] Aggressive breakers that give high cake dissolution tend to breakthrough cakes very quickly in "hot spots," exhausting the acid source quickly and leaving residue behind. In such applications, it may be desirable to delay the production of acid in a fluid formulation. Delayed acid sources, as referred to herein, include compounds which will release acid upon hydrolysis or spontaneous degradation after a determined length of time. In particular, compounds that hydro lyze to form acids in situ may be utilized as a delayed acid source. Such delayed source of acidity may be provided, for example, by hydrolysis of an ester. Illustrative examples of such delayed acid sources include hydrolyzable anhydrides of carboxylic acids, hydrolyzable esters of carboxylic acids; hydrolyzable esters of phosphonic acid, hydrolyzable esters of sulfonic acid and other similar hydrolyzable compounds that should be well known to those skilled in the art.

[0047] Suitable esters may include carboxylic acid esters so that the time to achieve hydrolysis is predetermined on the known downhole conditions, such as temperature and pH. In a particular embodiment, the delayed acid source may include a formic or acetic acid ester of a C2-C30 alcohol, which may be mono- or polyhydric, such as ethylene glycol mono formate or diformate. In embodiments, the delayed acid source may be the hydrolysable ester D-STRUCTOR™ available from M-I L.L.C. (Houston, TX).

[0048] Other esters that may find use in activating the oxidative breaker of the present disclosure include those releasing C1-C6 carboxylic acids, including hydroxycarboxylic acids formed by the hydrolysis of lactones, such as γ-lactone and δ-lactone). In another embodiment, a hydrolyzable ester of CI to C6 carboxylic acid and a C2 to C30 poly alcohol, including alkyl orthoesters, may be used.

[0049] In embodiments, acid sources may be incorporated into fluid compositions at a percent volume up to 50 vol%. In other embodiments, acid sources may be incorporated into fluid compositions at 0.5 vol% to 50 vol%. In still other embodiments, the acid sources may be incorporated into fluid compositions at 5 vol% to 30 vol%. However, one of ordinary skill in the art would appreciate that the amount may vary, for example, on the rate of hydrolysis for the particular acid source used.

[0050] Chelants

[0051] Chelants useful as dissolution additives in the embodiments disclosed herein may sequester polyvalent cations through bonds to two or more atoms of the chelant. Chelants may act to remove structural components from the filtercake, weakening the overall structure of the filtercake and aiding in its removal. For example, cations sequestered by the chelants may be sourced from solid filtercake components including various weighting or bridging agents such as calcium carbonate, barium sulfate, etc. Useful chelants may include organic ligands such as ethylenediamine, diaminopropane, diaminobutane, diethylenetriamine, triethylenetetraamine, tetraethylenepentamine, pentaethylenehexamine, tris(aminoethyl)amine, triaminopropane, diaminoaminoethylpropane, diaminomethylpropane, diaminodimethylbutane, bipyridine, dipyridylamine, phenanthroline, aminoethylpyridine, terpyridine, biguanide and pyridine aldazine.

[0052] In some embodiments, the chelant that may be used may be a polydentate chelator such that multiple bonds are formed with the complexed metal ion. Polydentate chelants suitable may include, for example, ethylenediaminetetraacetic acid (EDTA), diethylenetriaminepentaacetic acid (DTP A), nitrilotriacetic acid (NTA), ethylene glycol- bis(2-aminoethyl)-N,N,N',N'-tetraacetic acid (EGTA) , 1 ,2-bis(o-aminophenoxy)ethane- Ν,Ν,Ν',Ν'-tetraaceticacid (BAPTA), cyclohexanediaminetetraacetic acid (CDTA), triethylenetetraaminehexaacetic acid (TTHA), N-(2-Hydroxyethyl)ethylenediamine- Ν,Ν',Ν'-triacetic acid (HEDTA), glutamic-N,N-diacetic acid (GLDA), ethylene-diamine tetra-methylene sulfonic acid (EDTMS), diethylene-triamine penta-methylene sulfonic acid (DETPMS), amino tri-methylene sulfonic acid (ATMS), ethylene-diamine tetra- methylene phosphonic acid (EDTMP), diethylene-triamine penta-methylene phosphonic acid (DETPMP), amino tri-methylene phosphonic acid (ATMP), salts thereof, and mixtures thereof. In embodiments, the chelant may be D-SOLVER™ HD available from M-I L.L.C. (Houston, TX). However, this list is not intended to have any limitation on the chelating agents suitable for use in the embodiments disclosed herein. One of ordinary skill in the art would recognize that selection of the chelant may depend on the metals present downhole in the filtercake. In particular, the selection of the chelant may be related to the specificity of the chelant to the particular cations, the logK value, the optimum pH for sequestering and the commercial availability of the chelating agent, as well as downhole conditions, etc.

[0053] In a particular embodiment, the chelant used to dissolve metal ions is EDTA or salts thereof. Salts of EDTA may include, for example, alkali metal salts such as a tetrapotassium salt or tetrasodium salt. However, as the pH of the dissolving solution is altered in the processes disclosed herein, a di- or tri- potassium or salt or the acid may be present in the solution.

[0054] However, to dissolve or sequester some metals (for example, barium), stronger chelating agents may need to be used. For example, of several example chelating agents, the chelating power is, from strongest to weakest, DTPA, EDTA, GLDA, and HEDTA. Thus, incorporation of a chelant into a breaker fluid may serve to dissolve and chelate metals present in the filtercake to aid in dissolution or degradation of the filtercake.

[0055] In other embodiments, chelants in the embodiments disclosed herein may be delayed or inactivated chelants. Delayed chelants are chelants in which the moieties that actively bind substrates, i.e. amines, carboxylates, hydroxyls, etc., have been passivated by reversible reactions with a protecting group. Passivation or inactivation of the chelants may be achieved through modification of the chelant with protecting groups such as acetyl, benzoyl, benzyl, carbamates, nitriles, and esters, for example. Other protecting strategies are well known in the art and may be employed without deviating from the scope of this disclosure.

[0056] Suitable delayed chelants may include, for example, amido-chelants and esterified-chelants such as polyethyl esters or amides, internal cyclic esters or amides, nitrile-chelants, anhydride-chelants and combinations thereof, which are described in further detail in U.S. Patent Application 61/445,386, which is incorporated herein by reference in its entirety. [0057] Delayed chelants may be hydrolyzed to release a strong or activated chelant by elevated temperature, hydrolysis by a suitable enzyme, or hydrolysis in elevated or reduced pH. Inactivation of a chelant may be reversed upon exposure to a chemical or physical signal such as by altering the surrounding environment. According to embodiments of the present disclosure, the inactive chelant may be activated by introduction of a triggering agent, for example, by injecting a hydro lyzing agent such as an enzyme into the fluid composition environment, by thermally hydrolyzing the inactive chelating agent, and/or decreasing or increasing the pH by the addition of acids or bases.

[0058] One of ordinary skill in the art should appreciate that other agents or additives may be introduced to the fluid composition environment to trigger the release of an activated chelating agent, and/or rely on the temperature of the wellbore to hydrolyze the amides, esters, nitriles, and anhydrides to an activated chelant.

[0059] In embodiments, chelants may be incorporated into fluid compositions at a percent volume up to about 35 vol%. In other embodiments, chelants may be incorporated into fluid compositions at 0.5 vol% to 30 vol%. In still other embodiments, chelants may be incorporated into fluid compositions at 5 vol% to 25 vol%.

[0060] Base Fluid

[0061] Fluid compositions may contain an aqueous fluid optionally containing salts therein, such as brine or sea water (depending on requirements of a well). For example, the aqueous fluid may be formulated with mixtures of desired salts in fresh water. Such salts may include, but are not limited to alkali metal chlorides, hydroxides, or carboxylates, for example. In various embodiments of the fluid disclosed herein, the brine may include seawater, aqueous solutions wherein the salt concentration is less than that of sea water, or aqueous solutions wherein the salt concentration is greater than that of sea water. Salts that may be found in seawater include, but are not limited to, sodium, calcium, sulfur, aluminum, magnesium, potassium, strontium, silicon, lithium, and phosphorus salts of chlorides, bromides, carbonates, iodides, chlorates, bromates, formates, nitrates, oxides, and fluorides. Salts that may be incorporated in a brine include any one or more of those present in natural seawater or any other organic or inorganic dissolved salts. Additionally, brines that may be used in the fluid formulations disclosed herein may be natural or synthetic, with synthetic brines tending to be much simpler in constitution. In a particular embodiment, a brine may include halide or carboxylate salts of mono- or divalent cations of metals, such as cesium, potassium, calcium, zinc, and/or sodium. The density of the fluid formulations may be controlled by increasing the salt concentration in the brine (up to saturation). One skilled in the art would appreciate that, in wellbore applications, such density control may be particularly desirable in order to control bottom hole pressures and/or to prevent (or reduce) movement of a spotted fluid within the wellbore from the section of the wellbore requiring filtercake removal.

[0062] When the fluid compositions are used as a breaker fluid for wellbore applications, contacting an oil-based or invert emulsion-based filtercake may result in the formation of an aqueous emulsion. When the emulsion is formed, it may include an oleaginous discontinuous phase and an aqueous continuous phase. Aqueous fluids (from either the base fluid of the breaker fluid or the non-oleaginous phase of the invert emulsion filtercake) that may form the continuous phase of the stabilized oil-in-water emulsion may include at least one of fresh water, sea water, brine, mixtures of water and water- soluble organic compounds and mixtures thereof. For example, the aqueous fluid may be formulated with mixtures of desired salts in fresh water. Such salts may include, but are not limited to alkali metal chlorides, hydroxides, or carboxylates, for example.

[0063] The oleaginous fluid (from the oleaginous filtercake) that may form the discontinuous phase of the stabilized oil-in-water emulsion may be a liquid, in some embodiments a natural or synthetic oil, and in other embodiments the oleaginous fluid is selected from the group including diesel oil; mineral oil; a synthetic oil, such as hydrogenated and unhydrogenated olefins including polyalpha olefins, linear and branch olefins and the like, polydiorganosiloxanes, siloxanes, or organosiloxanes, esters of fatty acids, specifically straight chain, branched and cyclical alkyl ethers of fatty acids; similar compounds known to one of skill in the art; and mixtures thereof. However, no limitation on the type of oleaginous fluids which may be emulsified is intended by the above list. Rather, the above list includes various oleaginous fluids frequently used in wellbore operations. One of ordinary skill in the art would appreciate that other types of oleaginous fluids may be emulsified in accordance with the present disclosure.

[0064] Additional Components

[0065] Fluid compositions formed in accordance with the present disclosure may include other components, which may be emulsified or not, depending on the needs and requirements for a particular application, and depending on what components may be found within the filtercake broken by the breaker fluids. Thus, it is specifically within the scope of the present disclosure that other solvents, solids, or gases known to those skilled in the art may be found within the fluid compositions of the present disclosure.

[0066] In some instances, such as when screens or other sensitive drilling equipment are used in combination with fluid compositions of the present disclosure, a corrosion inhibitor may be incorporated into the fluid composition to extend the service life of the equipment. Additionally, when the fluid compositions are employed in wellbore applications as a breaker fluid, it may also be desirable to include an oxidant to further aid in breaking or degradation of polymeric additives present in a filtercake. Examples of such oxidants may include any one of those oxidative breakers known in the art to react with polymers such as polysaccharides to reduce the viscosity of polysaccharide- thickened compositions or disrupt filtercakes. Such compounds may include peroxides (including peroxide adducts), other compounds including a peroxy bond such as persulphates, perborates, percarbonates, perphosphates, and persilicates, and other oxidizers such as hypochlorites, which may optionally be encapsulated as is known in the art. Further, use of an oxidant in a breaker fluid, in addition to affecting polymeric additives, may also cause fragmentation of swollen clays, such as those that cause bit balling.

[0067] One skilled in the art would appreciate that stability of fluid compositions in accordance with embodiments of the present disclosure may be affected by other factors such as time, temperature, size of the particle and emulsified material. Depending on the requirements of the desired application, one skilled in the art would appreciate that the fluid compositions may be modified to allow for greater control over the solubilization of organic contaminants or oleaginous fluid when forming an emulsion in situ. Such types of modifications may include altering fluid composition properties that include density and viscosity (e.g., to vary penetration and reaction with a filtercake), changing the concentration and ratio of emulsion components, the addition of multiple surfactants or other additives, etc.

[0068] In embodiments, the final density of the fluid compositions of the present disclosure may range from 7 ppg to 15 ppg. In other embodiments the final density of the fluid compositions may range from 8.5 ppg to 14 ppg. In some embodiments, fluid compositions may have a final specific gravity that ranges from 0.8 to 1.9. In other embodiments, the specific gravity may range from 0.9 to 1.7.

[0069] The fluid compositions of the present disclosure may be emplaced in a wellbore when clean-up/removal of a filtercake is desired. The fluid compositions may be selectively emplaced in the wellbore, for example, by spotting the fluid through a coil tube or by bullheading. A downhole anemometer or similar tool may be used to detect fluid flows downhole that indicate where fluid may be lost to the formation. Various methods of emplacing a pill may be employed, as generally known in the art. However, no limitation on the techniques by which the breaker fluid of the present disclosure is emplaced is intended or implied on the scope of the present application.

[0070] In the application of one or more embodiments, fluid compositions formulated as breaker fluids are applied to a wellbore containing a filtercake and after a sufficient period of time, e.g. , hours to several days to allow for disruption or fragmentation of the filtercake and formation of an oil-in-water emulsion in situ, the fluid may be returned to the surface for collection and subsequent recovery techniques. Subsequent washes of the wellbore with a fluid composition or wash fluids known in the art may be desirable to ensure complete removal of filtercake material remaining therein.

[0071] Further, in some embodiments, the breaker fluids of the present disclosure may be used in wells that have been gravel packed. For example, as known to those skilled in the art, gravel packing involves pumping into the well (and placing in a production interval) a carrier fluid {e.g. , a viscoelastic fluid) that contains the necessary amount of gravel to prevent sand from flowing into the wellbore during production. However, filtercake remaining on the walls and the carrier fluid should be removed prior to production. In a particular embodiment, after placement of a gravel pack, a breaker fluid of the present disclosure may be emplaced in the production interval and allowed sufficient time to decrease the viscosity of the viscoelastic carrier fluid and then penetrate and fragment filtercake in the interval, as described above. Alternatively, a wash fluid may be used following the placement of the gravel pack, but prior to the emplacement of the breaker fluid.

[0072] Examples of fluids that may be used to drill a wellbore and form a filtercake that may be fragmented and removed in accordance with embodiments of the present disclosure include those fluids such as, for example, NOVAPRO™, VERSAPRO™, and FAZEPRO™, SUREMUL™ available from M-I LLC (Houston, Texas) or those described in U.S. Patent Nos. 7,262,152, 6,822,039, 6,790,811, 6,218,342, 5,905,061, 6,291,405, and 5,888, 944, and U.S. Patent Application No. 11/777,399, which are all assigned to the present assignee and herein incorporated by reference in their entirety. However, no limitation on the type drilling fluid/filtercake is implied or intended and it is envisioned that breaker fluids in accordance with embodiments of this disclosure may be used to remove any oil-based filtercake formed from oil-based or invert emulsion drilling fluids.

[0073] As described above, fluid compositions formulated as a breaker fluid may be circulated in the wellbore during or after the performance of the at least one completion operation. In other embodiments, the breaker fluid may be circulated either after a completion operation or after production of formation fluids has commenced to destroy the integrity of and clean up residual conventional or reversible invert emulsion fluids remaining inside casing or liners.

[0074] Generally, a well is often "completed" to allow for the flow of hydrocarbons out of the formation and up to the surface. As used herein, completion processes may include one or more of the strengthening the well hole with casing, evaluating the pressure and temperature of the formation, and installing the proper completion equipment to ensure an efficient flow of hydrocarbons out of the well or in the case of an injector well, to allow for the injection of gas or water. Completion operations, as used herein, may specifically include open hole completions, conventional perforated completions, sand exclusion completions, permanent completions, multiple zone completions, and drainhole completions, as known in the art. A completed wellbore may contain at least one of a slotted liner, a predrilled liner, a wire wrapped screen, an expandable screen, a sand screen filter, a open hole gravel pack, or casing.

[0075] Fluid compositions formulated as breaker fluids as disclosed herein may also be used in a cased hole to remove any residual oil based mud left in the hole during any drilling and/or displacement processes. Well casing may consist of a series of metal tubes installed in the freshly drilled hole. Casing serves to strengthen the sides of the well hole, ensure that no oil or natural gas seeps out of the well hole as it is brought to the surface, and to keep other fluids or gases from seeping into the formation through the well. Thus, during displacement operations, when switching from drilling with an oil- based mud to a water-based mud (or vice-versa), the fluid in the wellbore is displaced with a different fluid. For example, an oil-based mud may be displaced by another oil- based displacement to clean the wellbore. The oil-based displacement fluid may be followed with a water-based displacement fluid prior to beginning drilling or production. Conversely, when drilling with a water-based mud, prior to production, the water-based mud may be displaced with a water-based displacement fluid, followed with an oil-based displacement fluid.

[0076] In accordance with the present application, the fluid compositions of the present application (having a protective colloid therein) may be used between successive displacements to further enhance cleaning of the wellbore, including casing walls, etc, prior to further drilling or production. Specifically, the fluids of the present disclosure may be used to ensure that the wellbore is sufficiently cleaned or that water-wet surfaces become oil-wet, vice-versa, depending on the subsequent operation. Further, one skilled in the art would appreciate that additional displacement fluids or pills, such as viscous pills, may be used in such displacement or cleaning operations as well, as known in the art. [0077] Another embodiment of the present disclosure involves a method of cleaning up a wellbore drilled with the invert emulsion drilling fluid described above. In one such illustrative embodiment, the method involves circulating a fluid composition into a wellbore, which as been drilled to a larger size (i.e., under reamed) with an invert emulsion drilling mud, and then shutting in the well for a predetermined amount of time to allow penetration and fragmentation of the filtercake to take place. Upon fragmentation of the filtercake and formation in situ of an oil-in-water emulsion, the emulsion can be easily produced from the well bore upon initiation of production and thus the residual drilling fluid is easily washed out of the well bore. Alternatively, a wash fluid (different from the breaker fluid) may be circulated through the wellbore prior to commencing production.

[0078] The fluid compositions disclosed herein may also be used in a wellbore where a screen is to be put in place down hole. After a hole is under-reamed to widen the diameter of the hole, drilling string may be removed and replaced with production tubing having a desired sand screen. Alternatively, an expandable tubular sand screen may be expanded in place or a gravel pack may be placed in the well. Breaker fluids may then be placed in the well, and the well is then shut in to allow penetration and fragmentation of the filtercake to take place. Upon fragmentation of the filtercake and formation in situ of an oil-in-water emulsion, the emulsion can be easily produced from the well bore upon initiation of production and thus the residual drilling fluid is easily washed out of the well bore. Alternatively, a wash fluid (different from the breaker fluid) may be circulated through the wellbore prior to commencing production.

[0079] However, the fluid compositions disclosed herein may also be used in various embodiments as a displacement fluid and/or a wash fluid. As used herein, a displacement fluid may be used to physically push another fluid out of the wellbore, and a wash fluid that may contain a surfactant and may be used to physically and chemically remove drilling fluid reside from downhole tubulars. When also used as a displacement fluid, the breaker fluids of the present disclosure may act effectively to push or displace the invert emulsion drilling fluid. When also used as a wash fluid, the breaker fluids may assist in physically and/or chemically removing the invert emulsion filtercake once the filtercake has been disaggregated by the breaker system.

[0080] In one embodiment, a fluid composition may be used in a method of cleaning a wellbore that has been drilled with an invert emulsion drilling mud, and thus has an invert emulsion filtercake formed thereon. The breaker fluid may be circulated into the wellbore, contacting the invert emulsion filtercake, and the components within the breaker fluid may break the invert emulsion of the filtercake. The breaker fluid may be circulated in the wellbore that has not produced any hydrocarbons. In one or more embodiments, if a wellbore that has already begun production of hydrocarbons is believed to be impaired by any residual filtercake left in the well following the drilling operations, a breaker fluid of the present invention may be used to clean the wellbore.

[0081] In another embodiment, fluid compositions disclosed herein may be used in the production of hydrocarbons from a formation. Following the drilling of a formation with an invert emulsion drilling mud, at least one completion operation may be performed on the well. A breaker fluid may then be circulated in the well, and the well may be shut for a predetermined time to allow for breaking of the invert emulsion of the filtercake formed on the walls therein. Formation fluids may then enter the well and production of the formation fluids may ensue. Alternatively, a wash fluid (different from the breaker fluid) may be circulated through the wellbore prior to commencing production of formation fluid.

[0082] The following examples are provided to further illustrate the application and the use of the methods and compositions of the present invention and should not be interpreted as limiting or identifying key features thereof.

[0083] EXAMPLES

[0084] In the following Examples, an oil-based mud (OBM) formulation shown in Table

1 is used to assay sample breaker fluid formulations in subsequent examples. The OBM was an inverse emulsion formulated with VG PLUS™, an organically modified clay; SUREMUL EH™ emulsifier; fluid loss additives SUREWET™, VERSATROL™ M, ECOTROL RD™; and SAFE-CARB™ 20, an acid-soluble bridging agent; all of which are available from MI L.L.C. (Houston, TX). The oil-based mud also contains simulated low gravity drilling solids (LGDS) that include a clay (HMP clay), silica flour (D-66), and API grade barite.

[0085] Example 1 - Fluid compositions formulated as breaker fluids and measured performance in varying brines.

[0086] Tests were carried out to look at the effect of changing the type of brines used in various breaker formulation on calcium dissolution. Sample breaker fluid formulations are prepared using CAL-ACID™, a formic acid-based breaker solution that also contains a corrosion inhibitor available from MI L.L.C. (Houston, TX); butyl lactate; TEGOTENS™ DO, an aqueous amine oxide surfactant available from EVONIK INDUSTRIES (Deer Park, TX); STEPOSOL^® M8-10, an alkyl amide solvent available from Stepan Company (Anaheim, CA); and CLEARGUM^® CO 01, an octenyl succinic anhydride-modified hydroxy ethylcellulose available from Roquette (Geneva, IL). Breaker fluid formulations were prepared as shown in Table 2.

Table 1 Breaker fluid formulations for Example 1.

[0087] The ability of the breaker fluid formulations to dissolve calcium carbonate contained within an oil-based mud (OBM) was measured by determining the concentration of calcium ions present in the aqueous phase of the OBM/breaker fluid mixture. The method of determining the calcium ion concentration was performed by adding 5 mL of a sample breaker fluid formulation and 1 mL of the simulated OBM to a vial and gently agitating the mixture. Any observations regarding dispersion characteristics or signs of effervescence were recorded. The vials were placed in an oven at 80°C for 1 hour to simulate bottomhole temperature conditions. Following heat-aging, the samples were removed and cooled to room temperature. A 0.5 mL aliquot of the aqueous phase was then removed, carefully to avoid the top organic layer or precipitate, and the aqueous layer was titrated for calcium using 0.1M EDTA. Results were plotted in FIG. 1.

[0088] The results in FIG. 1 display that the surfactant and solvent additions increase levels of dissolution over the use of acid alone. In addition, it is noted that the results show that brine may have an effect on the levels of calcium dissolution. It should be noted that in calcium based brines there is a high background level of soluble calcium so there is the potential for greater error in the absolute value for these results. For reference, there is a -73% contribution of soluble calcium due to brine, and a maximum ~ 27% contribution from mud depending on dissolution. The value for calcium dissolution for the calcium brines is deduced by subtracting the amount of disodium EDTA required for titrating 0.5ml aliquot from the bottom phase of the test sample, containing 1ml OBM, with the amount required for titrating 0.5ml aliquot of the aged breaker without OBM.

[0089] Example 2- Fluid compositions formulated as breaker fluids with an incorporated delayed acid source.

[0090] The performance of a breaker fluid formulations were analyzed in conjunction with comparative breaker fluid formulations containing DEEPCLEAN™, a surfactant package; or ECF-2557, a surfactant blend containing an alkyl polyglycoside, an ethoxylated alcohol, and a glycol ether; both of which are available from MI L.L.C. (Houston, TX). In addition, samples were formulated with a free acid source (Sample Nos. 7-9) or a delayed acid source (Samples 10-12), D-STRUCTOR™, available from M-I L.L.C. (Houston, TX). Breaker fluid formulations are shown in Table 2.

Table 2 Breaker fluid formulations for Example 2.

[0091] For samples containing the free acid source CAL-ACID , the samples were mixed with the OBM for 1 hour and the soluble calcium in the aqueous phase was measured. Samples containing the delayed acid source were placed in an oven at 80°C for 18 hours before the concentration of free calcium was measured. The amount of free calcium in the aqueous phase was calculated using the method outlined above and results were graphed in FIG. 2. As expected, lower dissolution levels were seen in the samples with the delayed acid source than for those formulated with the free acid. In addition, the results show variances in the level of soluble calcium, dependant on the brine base used.

[0092] Stabilized colloids in accordance with embodiments disclosed herein may comprise an aqueous phase, which could be water, or a saline brine to provide fluid density, a water immiscible solvent or solvent blend of a defined HSP, and additional surfactants. Further, embodiments of fluid compositions may also include a number of dissolution additives, singularly or as mixtures, such as chelants and acids and acid precursors to dissolve solid particles, such as calcium carbonate, in the residues or filtercakes being treated.

[0093] It has been found that the use of protective colloids may increase the stability of emulsions, which may be useful for, for example, cleaning up oily residues and oil-based filtercakes present on surfaces within a wellbore. The protective colloid stabilized fluid compositions formed in accordance with embodiments disclosed herein may possess increased stability at elevated temperatures and high salinities than compared to systems such as microemulsions that quickly separate into organic and aqueous phases when exposed to such conditions. Fluid compositions described herein may also possess enhanced storage stability both alone and when used to solubilize oleaginous or nonaqueous materials, which may aid in removal and transport of the fluids to and from worksites.

[0094] Other advantages of the fluid compositions of the present disclosure may include an increased ability to dissolve calcium from muds and oily residues, which in effect may decrease the viscosity of the resulting solubilized OBM residues and aid the removal of solubilized residues from the wellbore by, for example, increasing the flow through completion screens. Further, in some applications where it may be desirable to effect a delayed action for the fluid formulation, the incorporation of delayed acid sources, chelants, and delayed chelants may result in more complete filtercake removal and gentler conditions that may prevent scaling and corrosion of materials within a wellbore.

[0095] In addition to wellbore applications, it is envisioned that fluid compositions in accordance with this disclosure may be used in any industry or application where solubilization and/or removal of oil-based contaminants is desired. For example, fluid compositions may be useful for removing oily residues during paint stripping or cleanup of oilfield equipment, of drilling devices, of oil-saturated drill cuttings, and removal of engine grease, oil-buildup, and sludge in mechanical applications. Other uses for the fluid compositions described herein include use as a flush to clean pipeline systems containing oils, waxes, or other organic deposits, such as pipeline systems encountered in industrial, commercial, and institutional facilities (e.g. oil pipelines, or pipelines and sewers used to dispose of insoluble fats and greases from rendering or food-preparation facilities, etc.)

[0096] Compositions in accordance with embodiments of the present invention are also advantageous in that the constituent chemicals have no or reduced toxicity. Thus, the described fluid compositions may be viable alternatives to more toxic chemicals used for the specific applications, allowing users to retain performance while reducing the overall environmental impact.

[0097] While the disclosure includes a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments may be devised which do not depart from the scope of the present disclosure. Accordingly, the scope should be limited only by the attached claims.

[0098] Although the preceding description has been described herein with reference to particular means, materials, and embodiments, it is not intended to be limited to the particulars disclosed herein; rather, it extends to all functionally equivalent structures, methods, and uses, such as are within the scope of the appended claims.

Claims

CLAIMS What is claimed:

1. A fluid composition comprising:

an aqueous continuous phase;

a protective colloid;

a surfactant;

an organic solvent; and

a dissolution additive.

2. The composition of claim 1, wherein the organic solvent is an alkyl amide solvent.

3. The composition of claim 1, wherein the organic solvent is selected from one or more of ethylene glycol monobutyl ether, diethylene glycol monobutyl ether, triethylene glycol monobutyl ether, hexylene glycol, butyl lactate, ethyl lactate, isopropyl lactate, and isopropyl palmitate.

4. The composition of claim 1, wherein the surfactant is an alkyl amine oxide surfactant.

5. The composition of claim 1, wherein the protective colloid is a derivatized amphiphilic polysaccharide.

6. The composition of claim 5, wherein the protective colloid is a polysaccharide derivatized with a compound selected from the group consisting of octenyl succinic anhydride, palmitic acid, stearic acid, oleic acid, linoleic acid, isobutyric acid, vinyl pivalate, vinyl-2-ethylhexanoate, vinyl esters of saturated branched monocarboxylic acids having 9 or 10 carbon atoms in the acid residue, vinyl laurate, vinyl stearate, and p-tert- butylbenzoate.

7. The composition of claim 5, wherein the protective colloid is one or more selected from the group consisting of laurdimonium hydroxyethyl cellulose, cocodimonium hydroxyethylcellulose, and steardimonium hydroxyethylcellulose.

8. The composition of claim 5, wherein the protective colloid is one or more synthetic polymers selected from the group consisting of polyvinylpyrrolidone, polyacrylic acids, polyacrylamide, polyvinyl alcohol, polyethylene oxide, polyalkyl oxazoline, and copolymers or mixtures thereof.

9. The composition of claim 1, wherein the dissolution additive comprises a chelant.

10. The composition of claim 9, wherein the chelant is a delayed chelant.

11. The composition of claim 1 , wherein the dissolution additive comprises a delayed acid source.

12. The composition of claim 1, wherein the delayed acid source is a formic acid or acetic acid ester of a C2 to C30 alcohol.

13. The composition of claim 1, wherein the organic solvent has Hansen solubility parameters in the range of 0.7 to 0.9^¾, 0.1 to 0.3 f_p, and 0.3 to 0.6 f_d.

14. The composition of claim 1, wherein the organic solvent is incorporated into the fluid composition in a range of 1 vol% to 30 vol%.

15. The composition of claim 1, wherein the surfactant is incorporated into the fluid composition in a range of 1 vol% to 15 vol%.

16. The composition of claim 1, wherein the protective colloid is incorporated into the fluid composition in a range of 0.2 vol% to 5 vol%.

17. The composition of claim 1, wherein the dissolution additive is incorporated into the fluid composition in a range of 0.5 vol% to 50 vol%.

18. A method of cleaning a wellbore drilled with an invert emulsion fluid or oil-based fluid that forms an invert emulsion or oil-based filtercake, the method comprising:

emplacing a breaker fluid into the wellbore, the breaker fluid comprising:

an aqueous continuous phase,

a protective colloid, a surfactant,

an organic solvent, and

a dissolution additive; and

shutting in the well for a period of time sufficient to initiate breaking of the filtercake.

19. The method of claim 18, wherein the organic solvent is incorporated into the breaker fluid in a range of 1 vol% to 30 vol%.

20. The method of claim 18, wherein the surfactant is incorporated into the breaker fluid in a range of 1 vol% to 15 vol%.

21. The method of claim 18, wherein the protective colloid is incorporated into the breaker fluid in a range of 0.2 vol% to 5 vol%.

22. The method of claim 18, wherein the dissolution additive is incorporated into the breaker fluid in a range of 0.5 vol% to 50 vol%.

23. The method of claim 18, wherein the dissolution additive is a delayed acid source.

24. The method of claim 18, wherein the dissolution additive comprises a chelant.

25. The method of claim 18, wherein the solvent has Hansen solubility parameters in the range of 0.7 to 0.9 /¾, 0.1 to 0.3 f_p, and 0.3 to 0.6 f_d.

26. A method of cleaning a surface contaminated with an oleaginous residue, the method comprising:

contacting a surface with an effective amount of a fluid composition, the fluid composition comprising:

an aqueous continuous phase,

a protective colloid,

a surfactant,

an organic solvent, and

a dissolution additive; and forming an aqueous emulsion, wherein the aqueous emulsion contains the olea: residue in an internal oleaginous phase.

27. The method of claim 26, further comprising collecting the aqueous emulsion.