Gelled emulsions and methods of using the same

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Gelled emulsions contain (i.) an external phase of an aqueous water-soluble solvent solution, polymeric viscosifying agent and, optionally, an oxidative and/or acidic breaker; and (ii.) an internal phase of a dispersed organic fluid. The aqueous water-soluble solvent solution constitutes between from about 15 to about 50 volume percent of the gelled emulsion and the dispersed organic fluid is presented in the gelled emulsion in amounts ranging from about 50 to about 85 volume percent. The gelled emulsions are useful in a variety of applications including, but not limited to, oil field, pipeline and processing facility applications.

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Description
FIELD OF THE INVENTION

The invention relates to gelled emulsions which contain an aqueous water-soluble solvent solution. The gelled emulsions are essentially phosphate-free. The invention further relates to methods of using such gelled emulsions.

BACKGROUND OF THE INVENTION

Stimulation techniques, such as hydraulic fracturing, used in the treatment of oil and gas wells improve productivity of the treated well. In hydraulic fracturing, a fluid is injected down the wellbore and into the productive formation at a sufficient rate and pressure such that the formation rock fractures from the induced stresses. A proppant is added to the fluid and is carried into the formation fracture. The proppant prevents closure of the fracture when hydraulic pressures are released, thereby leaving a conductive flow channel from the wellbore deep into the rock matrix.

Traditionally the fluid used for the purpose of hydraulic fracturing has been oil, water, or an emulsion of these two liquids. An efficient fracturing fluid should possess good proppant transport characteristics. Such characteristics are dependent on the viscosity of the fluid. Generally, the viscosity should be high in order to achieve wider and larger fractures. High viscosity is further generally desirable for more efficient transport of proppant into the fractured formation. A wide range of additives may be used to enhance the rheological properties and/or the chemical properties of the fluid. Such additives include viscosifiers, friction reducing agents, surface active agents, fluid loss control additives and the like. After the fracturing treatment is complete, it is desirable to lower the viscosity of the fluid, so that it can be pumped back out of the well without carrying entrained proppant.

Fracturing fluids, especially those used in the stimulation of gas wells, often contain aqueous methanol, either by itself or in conjunction with a foaming agent (surfactant) and a gas, such as carbon dioxide or nitrogen. The use of methanol or other water-soluble solvents in stimulation fluids is desirable for several reasons. Being non-aqueous, such solvents minimize the tendency of the clay-filled reservoir porosity to swell and migrate. They also impart a low surface and interfacial tension to water-based fluids, thereby reducing the pressure required for initial cleanup. In the case of methanol, it is also very volatile and will therefore evaporate even in the presence of water saturated gases. The use of methanol with liquid carbon dioxide is particularly beneficial because of its low freeze point.

Some efforts have therefore been undertaken to develop emulsions which use anhydrous fluids. For instance, U.S. Pat. No. 4,554,082 discloses a fracturing fluid containing liquefied carbon dioxide, anhydrous glycol/hydrocarbon and a low HLB surfactant to form a liquid-liquid emulsion. Glycol, however, is more costly than methanol and exhibits lower volatility. The disclosed emulsions are further undesirable since, at elevated temperatures and pressures, hydrocarbons (such as kerosene and diesel fuel) become miscible and a low viscosity, single phase liquid results.

U.S. Pat. No. 6,838,418 discloses a fracturing emulsion fluid containing carbon dioxide as an internal phase and an external phase containing a high percentage of methanol and water, an emulsifier and a synthetic polymer for thickening the emulsion. The emulsion does not contain a hydrocarbon phase which is considered commercially desirable since carbon dioxide is not always available and since hydrocarbons are generally cheaper and easier to recover.

Traditionally, hydrocarbon based fluids, such as those disclosed in U.S. Pat. Nos. 5,514,645, 5,190,675 and 6,149,693, are gelled with phosphate esters and have particular applicability in the fracturing of deep gas wells. The absence of high molecular weight polymers and the inherent low interfacial tension between the hydrocarbon and the high pressure reservoir gas provides highly effective fluid recovery. Concerns have arisen, however, regarding residual phosphorous compounds (which may remain in the crude and cause refinery upsets) as well as contamination of refined petroleum products.

While non-phosphate-based hydrocarbon gellants have been developed, such as those disclosed in U.S. Pat. No. 6,849,581, they are often slow to gel at low temperature. Other non-phosphate-based hydrocarbon gellants are too expensive to be commercially viable. Further, the gelation rates and stability of many of the non-phosphate-based hydrocarbon gels of the prior art are severely affected by contaminants such as, for example, water. This further makes them commercially undesirable.

Alternatives continue to be sought for phosphorous-free gelled fluids which provide the benefits of phosphate ester gelled hydrocarbons.

SUMMARY OF THE INVENTION

The invention relates to gelled emulsions which are essentially phosphorous-free. The gelled emulsion contains an aqueous water-soluble solvent solution and a dispersed hydrocarbon or organic fluid. In addition, the gelled emulsion contains a polymeric viscosifying agent, emulsifying agent and, optionally, an oxidative or acidic breaker (or both oxidizer and acidic breaker). The gelled emulsion further may contain a dispersed gaseous component, such as carbon dioxide or nitrogen.

The external phase of the emulsion contains the aqueous water-soluble solvent solution and the polymeric viscosifying agent, emulsifying agent and, optionally, oxidative and/or acidic breaker. The internal phase contains the dispersed hydrocarbon/organic fluid. The internal phase further may contain the optional gaseous component(s). The emulsifying agent serves as the coalescence barrier to the external and internal phases.

Additives and mixing methodology may be employed in order to delay the hydration of the polymeric viscosifying agent. As such, the initial viscosity of the gelled emulsion may be minimized; the viscosity of the emulsion being allowed to increase over time. This, in turn, minimizes pumping friction pressure.

The aqueous water-soluble solvent solution may consist of an organic solvent that reduces the interfacial tension of the water. The solvent is preferably volatile in the producing reservoir gas. Although the water-soluble solvent is typically a C1-C4 alcohol, preferably methanol, other water-soluble solvents may also be used such as ethylene glycol, propylene glycol, acetone, methylene sulfonic acid, acetic acid, formic acid and hydroxy acetic acid as well as mixtures thereof.

The aqueous water-soluble solvent solution typically constitutes between from about 15 to about 50 volume percent of the gelled emulsion. The dispersed organic fluid is present in the gelled emulsion in amounts ranging from about 50 to about 85 volume percent.

The dispersed organic fluid is preferably at least one of diesel, gasoline, kerosene, reformate, naphthalene, xylene, toluene, mineral oil, light mineral oil, condensate, crude oil, lubricating oils, or mixtures thereof. In some applications other organic fluids with limited water solubility may be used.

Suitable polymeric viscosifying agents include those having one or more hydroxyl, carboxyl, sulfate, sulfonate, amino or amide functional groups as well as polysaccharides and polysaccharide derivatives such as guar gum derivatives.

Suitable emulsifying agents are those which ensure that the aqueous water-soluble solvent solution remains the external phase of the emulsion as the dispersed phase content is increased and that the stability of the gelled emulsion is maintained at reservoir temperatures for at least 10 minutes under static conditions.

The gelled emulsions have particular applicability in the fracturing of gas wells.

BRIEF DESCRIPTION OF THE DRAWINGS

In order to more fully understand the drawings referred to in the detailed description of the present invention, a brief description of each drawing is presented, in which:

FIG. 1 demonstrates the viscosity of the gelled emulsion of the invention over time at 90° C.

FIG. 2 demonstrates the effect of polymer loading on the viscosity of the gelled emulsion of the invention.

FIG. 3 demonstrates the effect of concentration of emulsifying agent in the gelled emulsion on viscosity.

FIG. 4 demonstrates the effect of the volumetric ratio of hydrocarbon to methanol in the gelled emulsion of the invention versus viscosity.

FIG. 5 demonstrates the build-up of viscosity in a flow loop of the gelled emulsion of the invention.

FIG. 6 illustrates the effect of the encapsulated oxidizer breaker on the viscosity of the aqueous water-soluble solvent solution of the gelled emulsion of the invention.

FIG. 7 illustrates the effect of the encapsulated oxidizer breaker on the emulsion viscosity of the gelled emulsion at 80° C.

FIG. 8 illustrates the effect of delayed hydration of the gellant on viscosity of the gelled emulsion.

 DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

The gelled emulsion of the invention is substantially free of phosphorous and typically exhibits shear-thinning, non-newtonian behavior. The gelled emulsion contains a high level of an aqueous water-soluble solvent solution and dispersed organic fluids. The gelled emulsion further, optionally, contains gaseous components. The presence of such gaseous components is especially desirable when the emulsion is to be used in the fracturing of gas wells.

In a preferred embodiment, the emulsion contains no greater than 1 volume percent of phosphorous. In a most preferred embodiment, the emulsion is phosphorous-free.

The gelled emulsion exhibits relatively stable rheological characteristics at relatively high temperatures and may advantageously be formulated from solid or liquid components.

The gelled emulsion may be employed in any application known in the art in which, for example, gelled hydrocarbons are suitable for use. Examples of possible applications include, but are not limited to, well treatment fluids (including stimulation fluids such as fracture fluids, matrix stimulation fluids, acidizing fluids, hydrocarbon-based treatment fluids etc.), drilling fluids (such as drilling muds, drill-in fluids, workover fluids, packer fluids, completion fluids, fluids for use with coil tubing, etc.), pipeline treatment fluids (such as gelled pipeline pigs, separation plugs, etc.), as well as process facility treatment fluids (such as gelled fluids for cleaning and/or chemical processing equipment used in oil field facilities, refineries, chemical plants, refineries, etc.).

The gelled emulsion is formed from the combination of an aqueous water-soluble solvent solution, a dispersed organic fluid, polymeric viscosifying agent and emulsifying agent. In addition, the gelled emulsion may contain an oxidizer or acid as a polymer degrading agent and/or emulsion breaker.

The emulsion may be composed of an external phase containing the aqueous water-soluble solvent solution and polymeric viscosifying agent and an internal phase of the dispersed organic fluid. The external phase further may contain the oxidative or acidic breaker. The internal phase may further contain a foaming or gasifying agent. The emulsifying agent serves as coalescence barrier to the external and internal phases, the hydrophobic portion of the emulsifying agent lying in the internal phase and the hydrophilic portion lying in the external phase.

The gelled emulsions offer substantially stable viscosities at temperatures up to at least about 175° F., alternatively up to at least about 200° F., alternatively up to at least about 250° F. Further, the gelled emulsions may exhibit stable viscosity at temperatures as low as −30° F., typically encountered, for example, in pipelines. In such cases, rheology may be modified to suit colder conditions, such as by using lower percentages of polymeric viscosifying agent than that specifically recited herein.

The water-soluble solvent is a C1-C4 alkanol, preferably methanol, ethanol or isopropanol, more preferably methanol. Other water-soluble solvents may also be used, such as ethylene glycol, propylene glycol, acetone, methylene sulfonic acid, acetic acid, formic acid and hydroxy acetic acid as well as mixtures thereof. When used, ethylene glycol may be recovered after the fracture treatment and reused. Use of acetone may lend to improved solvency to organic deposits. Use of acetic acid is desirable when the reservoir rock contains siderite beds [Fe (II) carbonate] or other acid soluble components.

Further, the water of the aqueous water-soluble solvent solution can be any aqueous solution such as distilled water, fresh water, salt water (brine), etc.

The amount of water-soluble solvent in the gelled emulsion is that amount sufficient to render acceptable permeability regain to the emulsion. Increased concentration of solvent in the aqueous water-soluble solvent solution translates to greater solubility of the oleophilic portion of the emulsifying agent.

Typically, the aqueous water-soluble solvent solution contains between from about 15 to about 80 volume percent of solvent and the remainder water. The aqueous water-soluble solvent solution typically constitutes between from about 15 to about 65 volume percent of the gelled emulsion. When methanol is used as the water-soluble solvent, above 60 volume percent of methanol is not desired. At higher percentages, fire hazards increase and the solubility of hydrocarbons and condensates increase. Since the emulsion contains a high percentage of water-soluble solvent (in combination with the dispersed organic fluid), the emulsion is particularly efficacious when used in gas wells.

The polymeric viscosifying agent may be a conventional thickening or gelling agent known in the art, such as those containing one or more hydroxyl, carboxyl, sulfate, sulfonate, amino or amide functional groups. Other suitable gelling agents are polysaccharides and polysaccharide derivatives containing monosaccharides such as glucose, galactose, mannose, xylose, arabinose and fructose. Suitable polysaccharide derivatives include, but are not limited to, guar gum derivatives such as HPG (hydroxypropyl guar), HEG (hydroxyethyl guar) and CMHPG (carboxymethyl hydroxypropyl guar), cellulose and its derivatives such as CMHEC (carboxymethyl hydroxyethyl cellulose) and HPC (hydroxyl propyl cellulose), xanthan gum and starch derivatives. Synthetic polymers can be used as gelling agents. A few of these include, but are not limited to, polyacrylate, polymethylacrylate, polyacrylamide, acrylamide methyl propane sulfonic acid copolymers, polyvinyl alcohol, polyvinyl pyrrolidone, and maleic anhydride methyl vinyl ether copolymers and polyethylene oxide. Typically, the amount of polymeric viscosifying agent in the gelled emulsion is between from about 3 to about 10 kg/m3. (Measurements in terms of kg/m3, or L/m3, herein refer to the aqueous water-soluble solvent solution, not the weight of the total emulsion. Other concentrations of components of the emulsion described herein are based on the weight of the aqueous water-soluble solvent solution.)

The viscosity of the gelled emulsion typically varies with the nature of the dispersed organic fluid. Suitable as the dispersed organic fluid are those suitable for forming an organic fluid gel, including those organic fluids commonly employed in oilfields, pipelines and refineries as well as chemical plants. Suitable dispersed organic fluids include, but are not limited to, hydrocarbon-based fluids. Typically, between from about 50 to about 85 volume percent of the gelled emulsion contains the dispersed organic fluid.

Types of suitable dispersed organic fluids include, but are not limited to, aliphatic, alicyclic and aromatic hydrocarbons, esters, such as oily esters and alkoxylated esters as well as mixtures thereof.

Specific examples of suitable aliphatic hydrocarbons include, but are not limited to, alkanes such as propane, n-butane, isobutane, n-hexane, n-octane, n-decane, n-tridecane, etc. Other aliphatics include alkenes and alkadienes. Alicyclic compounds include cyclohexane, etc. Specific examples of suitable aromatics include, but are not limited to, benzene, toluene, xylene, ethylbenzene and other alkyl benzenes, naphthalene, etc. In a preferred embodiment, the dispersed organic fluid is lighter than diesel such as C8-C15 alkanes.

Particular examples of commercial aromatic products include, but are not limited to, “FRACSOL”, “FRACSOL-S”, and “XYSOL” from EnerChem Canada or Amsol of the United States, or “RX-2100” from Canadian National Resources Limited of Calgary, Canada. Other specific examples of suitable dispersed organic fluids include, but are not limited to at least one of diesel, gasoline, kerosene, reformate, naphthalene, xylene, toluene, mineral oil, light mineral oil, condensate, crude oil, lubricating oils, or mixtures thereof (such as diesel mixed with condensate to lower API gravity, etc.). Other dispersed organic fluids such as alkanes (such as hexane) and derivatized alkanes (such as alkylhexanes), may also be employed.

Other suitable organic fluids (including oily esters, such as those derived from long chain acids and/or alcohols), are described in U.S. Pat. No. 5,519,063, which is incorporated by reference herein in its entirety. Also suitable are synthetic oils (including, but not limited to, synthetic hydrocarbon-base oils, ester-type oils, alkylene polymers, polysiloxanes, etc.). Also suitable are more environmentally compatible (e.g., biodegradable) natural or synthetic dispersed organic fluids such as Exxon's “ESCAID 90” or “ESCAID 110”, or refined kerosene (such as “LOTOX” available from Exxon), “HYDROSOLV P150” or “HYDROSOLV B100” (from Shrieve Chemical Products), “ISOPAR L” or “ISOPAR M” (from Nalco-Exxon Chemical Company), etc. Natural dispersed organic fluids such as animal oils and vegetable oils may also be suitable including, but not limited to, linseed oil, palm oil, cotton seed oil, rapeseed oil, soybean oil, olive oil, canola oil, sunflower oil, peanut oil, etc.

Two or more of the representative examples above may be mixed together to form a dispersed organic fluid having desired characteristics. In one exemplary embodiment, an organic fluid may be a liquid hydrocarbon that is at least one of diesel, condensate, or mixtures thereof. Further information on suitable organic-based fluids may be found in U.S. Pat. No. 6,302,209, which is incorporated herein by reference in its entirety.

The volumetric ratio of the viscosified water-soluble solvent solution to dispersed organic fluid in the gelled emulsion is typically between from about 1:5 to 1:2, preferably about 1:3. The gelled emulsion has particular applicability in fracturing using conventional proppants, such as sand, as well as lightweight (and ultra lightweight) proppants.

The gelled emulsion further preferably contains a dispersed gas component. Suitable dispersed gases are carbon dioxide and nitrogen. Typically, when present, the amount of dispersed gas in the emulsion is between from about 10 to about 70 volume percent, preferably about 25 volume percent.

The emulsifying agent is present in the gelled emulsion in an amount between from about 0.5 to about 3.5, preferably from about 1.0 to about 2.5, volume percent based on the aqueous water-soluble solvent solution. A suitable emulsifying agent for use in the invention may be ascertained by preparing a fully hydrated gel of the water-soluble solvent/water solution using 3 kg/m3 gellant and any buffer or agent deemed necessary to hydrate the gel. About 100 ml of the hydrated gel may then be placed in a blender equipped with a variable transformer. To the methanol/water blend may then be added 20 L/m3 of the test emulsifying agent. 300 ml of the hydrocarbon phase may then be slowly added while stirring with the variable transformer set to ˜40 volts. Stirring may then be continued for about 2 minutes. If an emulsion is formed, the emulsion may then be placed in a jar in a 70° C. water bath for about 30 minutes and the viscosity may then be measured at a shear rate of 100/s. If the viscosity of the emulsion is greater than 200 centipoise, the emulsifying agent is then suitable for use in the invention.

The emulsifying agent is preferably at least one member selected from (1) alkoxylated non-ionic emulsifiers having a lipophilic portion comprising a C12-C36 alkyl, dialkyl or alkylaryl and a hydrophilic portion having 20 to 150 moles of polyalkylene oxide; (2) an anionic, cationic or zwitterionic/amphoteric emulsifier having a lipophilic portion comprising a lipophilic portion comprising a C12-C22 alkyl, dialkyl or alkylaryl group and a hydrophilic portion having 10 to 80 moles of polyalkylene oxide; (3) an ethylene oxide/propylene oxide block copolymer comprising between from about 10 to about 50 moles of propylene oxide and from about 20 to about 150 moles of ethylene oxide; and (4) polyoxyalkylene sorbitan fatty acid esters. A class of surfactants known as “splittable surfactants” as taught in U.S. Pat. No. 5,774,064 are of particular interest because they can be deactivated by simply lowering the pH. This may be accomplished by an encapsulated acid, a slowly soluble acid or a low pH buffer.

The emulsifying agent is preferably at least one member selected from non-ionic emulsifiers; anionic, cationic or zwitterionic/amphoteric emulsifiers; ethylene oxide/propylene oxide block copolymers; and polyoxyalkylene sorbitan fatty acid esters. The emulsifying agent is preferably selected in order to maintain the emulsion stable at reservoir temperatures for at least 10 minutes under static conditions.

The emulsifying agent is typically chosen such that the following three criteria are met. First, the hydrophobic (lypophilic) portion of the molecule is sufficiently large to be effective in the aqueous water-soluble solvent solution. Second, the hydrophile/lypophile balance is sufficiently high to form and stabilize an emulsion having a low volume of aqueous water-soluble solvent solution as the external phase and larger volume of water-immiscible organic fluid as the dispersed or internal phase. Third, the molecule is capable of exhibiting efficient packing in the stabilizing film. An over-abundance of branches, unsaturated bonds and/or aromatic groups in the lyophilic portion of the molecule may lead to a film that is too loose to serve as a barrier to coalescence.

Published HLB values, such as those in “McCutcheon's Volume 1: Emulsifiers and Detergents 1998 North American Edition”—MC Publishing Co., may be used to select a suitable emulsifying agent. To be suitable, the HLB value for the emulsifying agent should be between from about 10 to about 20 and preferably from about 16 to about 18.

For ionic surfactants, it is may be desired to use a measured relative solubility number (RSN) in place of the HLB. The emulsifying agent typically exhibits an (RSN) in excess of 10, preferably between from about 13 to about 17. RSN is a measure of the amount of water required to reach the cloud point at 25° C. of the solution of 1 gram of the “solvent free” emulsifying agent dissolved in 30 ml of a solvent system comprising 4 volume percent xylene in dioxane and is further based on the hydrophile-lipophile character (see H. N. Greenwold et al, Analytical Chemistry, Vol. 28 Nov. 11, November, 1956 on pages 1693-1697) and further referenced in U.S. Pat. No. 4,551,239, herein incorporated by reference.

The emulsifying agent allows the dispersed organic fluid to become the dispersed phase of the emulsion and the aqueous water-soluble solvent solution to become the external phase. The emulsifying agent further provides stability to the emulsion by providing the means to keep the gelled emulsion in an emulsified state under desired operating conditions. Stability to the emulsion may further be affected by selection of polymeric viscosifying agent and the loading of the polymeric viscosifying agent. In order to allow the emulsifying agent to resist the mutual solvent effect of the high solvent content of the aqueous water-soluble solvent solution, the molecular weight of the emulsifying agent is high, thereby prohibiting the hydrophobic end of the emulsifying agent from entering the water phase of the emulsion. As a result of its high molecular weight, the hydrophobic portion of the emulsifying agent stays at the hydrocarbon/water interface where it stabilizes the emulsion at high temperature downhole conditions.

In a preferred mode, the emulsifying agent is a freeze-proofed solution.

The emulsifying agent may also be employed to assist in the hydration of the polymeric viscosifying agent. In so doing, the emulsifying agent assists in dispersement of the polymeric viscosifying agent in such a way that the viscosifying agent may hydrate, gel and/or increase the viscosity of the fluid. This minimizes the initial viscosity of the gelled emulsion and allows the emulsion viscosity to build with time thereby minimizing pumping friction pressure.

Suitable alkoxylated non-ionic emulsifiers are those having a lipophilic portion comprising a C12-C36, preferably from about C15-C22, alkyl, dialkyl and alkylaryl and a hydrophilic portion having between from about 20 to about 150 moles of polyalkylene oxide, preferably polyethylene oxide or a polyethylenepropylene block oxide, most preferably polyethylene oxide.

Suitable anionic, cationic or zwitterionic/amphoteric emulsifiers are those having a C15-C22 alkyl, dialkyl or alkylaryl group as lipophilic portion and a hydrophilic portion having between from about 10 to about 80 moles of polyalkylene oxide in addition to the charged groups; preferably polyethylene oxide or a polyethylenepropylene block oxide, most preferably polyethylene oxide. Preferred anionic emulsifiers include alkoxylated carboxylates, alkoxylated ether sulfates as well as alkoxylated alpha olefin sulfonates. Suitable cationic emulsifiers include alkoxylated amines.

Suitable as the ethylene oxide/propylene oxide block copolymer are those having between from about 10 to about 50 moles of propylene oxide and from about 20 to about 150 moles of ethylene oxide.

Preferred zwitterionic emulsifiers are betaines, such as fatty acid amido alkyl betaines like cocoamidopropyl betaines as well as sulfobetaines.

Suitable polyoxyalkylene sorbitan fatty acid esters include those wherein the polyoxyalkylene oxide is polyethylene oxide or a polyethylenepropylene block oxide, most preferably polyethylene oxide.

Particularly preferred surfactants are those set forth in Table I below:

TABLE I Manufacturer Trade Name RSN HLB C Min C Max Moles EO Class Structure Ethox Ethox MS-100 16.0 18.6 18 18 100 Nonionic Ethoxylated Fatty Acid POE(100) Stearyl-C18 Ethox Ethox MS-40 15.8 17.2 18 18 40 Nonionic Ethoxylated Fatty Acid POE(40) Stearyl-C18 Ethox Ethox MI-14 10.6 13.0 18 18 14 Nonionic Ethoxylated Fatty Acid POE(14) Isostearyl C-18 Ethox Ethox 3482 16.4 18.8 Nonionic Ethoxylated fatty Acid (unspecified) Ethox Ethal CSA 40/70% 16.8 17.4 16 18 40 Nonionic Ethoxylated Alcohols POE(40) Cetyl-Stearyl C16-C18 Alcohol Ethox Ethal LA-50 16.8 18.3 12 12 50 Nonionic Ethoxylated Alcohols POE(50) Lauryl C12 Alcohol Ethox Ethox TAM-25 17.0 16.0 16 18 25 Cationic Ethoxylated Tallow Amine POE(25) C-16-18 Ethox Ethox SAM-50 15.8 17.8 16 16 50 Cationic Ethoxylated Stearyl Amine POE(50) C-18

The emulsifying agent used in the invention exhibits water wetting characteristics and can be chosen so as to be compatible with potassium chloride or synthetic temporary and permanent clay stabilizers.

One or more other phosphorous-free additives may further be employed to alter the characteristics of the gelled emulsion fluid. Such additives may include any additive known in the art that is suitable for altering characteristics of aqueous gels, or for assisting with or modifying the combination or reaction of individual ingredients to form such gels. Examples of such additives which may be employed include, but are not limited to, buffering agents, cross-linking agents, scale/corrosion inhibitors and agents for controlling fines or clay swelling or migration such as potassium chloride or KCl substitutes of the type based on quaternary amine chlorides, such as CC-2, a product of BJ Services Company or polycationic clay control additives such as Claymaster 5C™, a product of BJ Services Company, or mixtures of these clay control additives.

While stability of the emulsion at room temperature is not dependent on pH, it is desirable to buffer the pH to be between from about 4 to about 6 to prevent premature acid hydrolysis of the polymeric viscosifying agent at downhole conditions and to assist hydration of the polymeric viscosifying agent at surface conditions.

The gelled emulsions may be prepared in any manner suitable for combining the components to form the gel. For example, the gelled emulsions may be prepared by blending the aqueous water-soluble solvent solution and polymeric viscosifying agent to form a gel and then introducing the emulsifying agent and the dispersed organic fluid. The remaining components, e.g., optional oxidizer and/or breaker and gasifying agent, may then be added. The breaker and/or oxidizer may even be added after the gelled emulsion has been formed, such as at a point at or near blender discharge manifold.

The oxidative or acidic breaker may then be added to the formulation to cause the gelled fluid to lose its structure, viscosity, etc. Typically, the gelled emulsion contains between from about 0.2 to about 30, more typically between from about 2 to about 25, kg/m3 of oxidative or acidic breaker.

In one embodiment, one or more breaker materials may be added for providing a delayed reduction in viscosity of gelled emulsions prepared herein. Such viscosity reduction may be desirable, for example, when a gelled fluid is used as a well treatment fluid such as a hydraulic fracturing fluid. In such a case, a breaker material may be combined with other components of the gelled emulsion prior to introduction of the fluid downhole, and may be formulated so that a gelled fluid viscosity is substantially maintained or increased during the time the gelled emulsion is displaced downhole and into the formation but is decreased, for example, after sufficient time has occurred to allow transport of proppant into the subterranean formation.

Any material(s) suitable for imparting viscosity reduction characteristics to the disclosed gelled emulsions may be employed as a breaker. Examples of suitable materials include, but are not limited to, oxidizing agent, amines, acids, acid salts, acid-producing materials, etc. The breaker is preferably an acid breaker such as hydrochloric acid, formic acid or sulfamic acid or alternatively an acid salt such as sodium bisulfate.

The oxidizing agent is preferably an alkaline earth peroxide, an encapsulated persulfate, a catalyzed organic peroxide or a hydrochlorite bleach.

The gelled emulsions may be employed as a component of a well treatment fluid, such as a drilling, stimulation, completion or workover fluid. In this regard, the disclosed gelled emulsions may be introduced into a wellbore and/or subterranean formation to function as viscosifiers or gelled components of circulating, lost circulation, or kill fluids (drilling muds, drill-in fluids, packer fluids, workover fluids, gelled pills, etc.), as well as fulfilling similar purposes as components of stimulation fluids (such as fracture fluids, gelled acids, foamed fluids, diversion fluids, etc.), injection profile modification fluids, etc. With benefit of this disclosure, it will be understood that the disclosed gelled emulsions may be employed in any drilling or well treatment application known in the art.

The components of the gelled emulsions may be combined in a batch process performed at the wellsite using mixing vessels such as frac tanks. Alternatively, the components may be batched mixed away from the wellsite and transported to the wellsite using methods known in the art.

In a preferred embodiment, the gelled emulsion is prepared on the fly using continuous mixing methods at the wellsite, such as those employing concomitantly introduced component process streams. In this regard, any continuous mixing method known in the art which is suitable for combining the disclosed components to form gelled gelled emulsion fluids may be employed. For example, when formulating well stimulation fluids, the dispersed organic fluid and alcohol/water blend may be introduced into a suction manifold simultaneously with a slurry of polymeric viscosifying agent along with the emulsifying agent. Once the gelled emulsion has formed in the tank or blender tub, proppant (when desired) as well as foaming agent or gasifying agent is introduced through a high pressure pump just prior to the gelled emulsion being introduced into the wellbore.

When introduced downhole, initial viscosity of the gelled emulsions set forth herein may be regulated by varying the concentration of the emulsifier, the ratio of hydrocarbon to liquid and the amount of gelling agent. By doing so, friction pressure during the pumping of the fluid downhole may be decreased and thus balanced As a result, the gelled emulsions exhibit low leak-off, excellent proppant transport abilities, clean highly conductive fractures, excellent fracture face permeability regain and are relatively inexpensive.

The gelled emulsions may further be employed within pipeline interiors as a pipeline treatment fluid to clean and/or convert pipeline transmission lines, isolate a pipeline from invasive materials, displace solid materials and/or fluids through a pipeline, or to separate pipeline products from each other or from other materials within the pipeline. Specific examples of such uses include, but are not limited to, use of a gelled plug or pig to isolate two separate fluids (such as different pipeline products) under static or dynamic conditions of flow within a pipeline interior. The disclosed gelled emulsions may also be used to remove debris or contaminants from the interior of the pipeline, such as by displacing a gelled pig of a treatment fluid containing non-phosphate organic liquid gel through at least a portion of a pipeline.

In one exemplary embodiment, when used as a gel pig, the gelled emulsion may be employed in conjunction with a mechanical pig as is known in the art. In one exemplary embodiment, a gel pig may be formed from a liquid organic gel and displaced through a pipeline by fluid under pressure. In this regard, displacement fluid may be gas or liquid, depending upon the needs of the user and the availability of fluids. A gel pig may be used alone or as an element of a “pig train” in a pipeline cleaning process. Such a pig train may be formed, for example, by preceding and/or following a pipeline treatment fluid gel plug with mechanical pigs and/or other chemical pig segments. Such chemical pig segments may be of the same or different composition and may include the additives such as corrosion inhibitors, bactericides, passivation agents, etc. Such chemical pig segments may be liquids or gels.

In other exemplary embodiments, the gelled emulsion may be employed as a separation plug or pig to separate one or more materials, such as pipeline product fluids (e.g., hydrocarbons, paraffins, asphaltenes, fuel oil, condensate, etc.), existing within a pipeline, under static or dynamic conditions, or as a microplug to remove fluids, solids and semi-solids (such as sand, tar, corrosion products and other debris and contaminants, etc.) from the interior of a pipeline.

In other embodiments of the disclosed method and compositions, the gelled fluids may be employed in fluid processing applications including, but not limited to, oil field production facility, refinery, and chemical plant applications.

The following examples will illustrate the practice of the present invention in its preferred embodiments. Other embodiments within the scope of the claims herein will be apparent to one skilled in the art from consideration of the specification and practice of the invention as disclosed herein. It is intended that the specification, together with the example, be considered exemplary only, with the scope and spirit of the invention being indicated by the claims which follow. All otherwise stated, all percentages are weight percentages.

EXAMPLES

GM-55 and GM-60 refer to modified hydroxypropyl guars wherein the molar substitution (defined as the number of moles of hydroxyalkyl groups per mole of anhydroglucose) is between from about 0.80 to about 1.20, a product of BJ Services Company;

Ethal CSA 40/70% is an ethoxylated alcohol POE (50) lauryl C12 alcohol, commercially available from Ethox;

Fracsol® is a 100% oil based fracturing fluid, commercially available from Enerchem International Inc.

Example 1

An emulsion, not containing a breaker, was prepared by making a base gel containing 60 vol % methanol in water to which was added 2 L/m3 acetic acid (60%), 2 L/m3 of a 60% choline chloride solution (a temporary clay stabilizer which avoids the swelling of the clay), 8 kg GM-55 methanol gellant and 20 l/m3 CSA-40/70. The acetic acid was used as a buffer to ensure hydration of the GM-55 gellant. One volume of this solvent blend was then emulsified with 3 volumes of Fracsol. The viscosity was then measured on a Brookfield Model PVS high pressure rheometer equipped with a B5 bob. The results are graphically displayed in FIG. 1.

Example 2

An emulsion was prepared as set forth in Example 1 except that the concentration of gellant was varied. The results are graphically displayed in FIG. 2.

Example 3

An emulsion was prepared as set forth in Example 1 except that the concentration of gellant was 3 kg/m3 and the concentration of emulsifying agent was varied. FIG. 3 illustrates the effect of emulsifier concentration on viscosity of the gelled emulsion.

Example 4

An emulsion was prepared as set forth in Example 1 except that the base gel contained only 3 kg/m3 gellant (GM-55) and varying ratios of Fracsol. The shear rate profile for the Brookfield rheometer was obtained every 5 minutes at 150/s, 125/s, 100/s and 75/s followed by two minute zeroing and then 100/s until the next ramp. The effect of the varied ratio of hydrocarbon to 60% methanol is set forth in FIG. 4.

Example 5

The gelled methanol solution obtained in Example 1 (“New FracFluid”) was added to the reservoir of a flow loop. A comparison gelled emulsion was obtained in a similar manner described in Example 1 but using a 3:1 volume ratio of Fracsol to gelled water containing 7 kg/m3 guar gellant, 12 L/m3 emulsifier (commercially available as PS-3 from BJ Services Company), 1 L/m3 of a 60% choline chloride solution and 1 L/m3 of Claymaster 5C™, a product of BJ Services Company. The flow loop was a 20 ft stainless steel tubing with an inner diameter of 0.417 in. The circulation rate was 200 ml/s. FIG. 5 shows the pressure build-up on the flow loop. (Air entrainment likely caused the pressure to drop off on the NewFrac Fluid.)

Example 6

A gelled emulsion was obtained in accordance with the procedures of Example 1 but using 10 kg/m3 encapsulated oxidative breaker (commercially available as HyPerm KP, a product of BJ Services Company), 8 kg/m3 gellant (GM-55), 20 L/m3 Ethal CSA 40/70, 2 L/m3 acetic acid (60%), 2 L/m3 buffer (commercially available as BF-7LD from BJ Services Company), 1 L/m3 of a 60% choline chloride solution and 1/m3 Claymaster 5C. The effect of the encapsulated oxidizer breaker on the viscosity of the gelled 60% methanol water blend at 80° C. is set forth in FIG. 6.

Example 7

A gelled emulsion was obtained in accordance with the procedure set forth in Example 1 but using 8 kg/m3 gellant (GM-55), 20 l/m3 emulsifier (Ethal CSA-40/70), 1 l/m3 of a 60% choline chloride solution, 1 l/m3 Claymaster 5C, 2 l/M3 acetic acid (60%), 2 kg/M3 potassium carbonate, 3:1 Fracsol:60% methanol. Various concentration of encapsulated persulfate breaker (HyPerm KP) was then added. FIG. 7 illustrates the effect of the encapsulated oxidizer breaker on the emulsion viscosity at 80° C.

Example 8

A base fluid was prepared by mixing 6 kg/m3 gellant (GM-60), 60% methanol, 35 L/m3 CSA 40/42%, 0.5 kg/m3 Borax, 0.67 kg/m3 potassium carbonate, 1 L/m3 of a 60% choline chloride solution and 1 L/m3 Claymaster 5C. The base fluid was then emulsified with 3 parts by volume of Frascol and mixed at high shear 3:1 v/v Fracsol. The viscosity of the emulsion was read on a Grace M3500 Rheometer. 2 L/m3 acetic acid (60%) was then stirred into the emulsion at low shear and the development of the emulsion measured on the rheometer. FIG. 8 displays the effect on the reduction of the initial viscosity by delayed hydration of the gellant.

Examples 9-14

A base gel was prepared by blending a blend of 60% methanol/40% water, 3 kg/m3, a methanol soluble guar (hydroxypropyl guar), available from BJ Services Company Canada and B.J. Services Company, U.S.A., under the trade mark GM-55 or GM-60; 2 L/m3 acetic acid (60%), 2 L/m3 of Claymaster 5C™, 1 L/m3 of a 60% choline chloride solution, 2 kg/m3 of potassium carbonate buffer and 20 L/m3 various emulsifiers. To this base fluid was added the dispersed organic fluid, Fracsol, a product of EnerChem wherein the volumetric ratio of Fracsol:methanol/water blend was 3:1. The mixture was then subjected to high shear on a Waring blender at speed of 4000 rpm (40 volts on the rheostat) for about 1 minute. The sample was then heated for about 1 hour at 70° C. While the stability of the emulsion is not sensitive to pH, the presence of the acetic acid serves to enable hydration of the HPG when the emulsion is introduced downhole. The emulsifiers used are set forth in Table II:

TABLE II Number of Carbon Moles Emulsifier Name Type Polar groups RSN HLB range EO A Alcohol ether Anionic 1 17.0 0 sulfate B Ethoxylated Non-ionic 0 16.0 18.6 18 100 fatty acid POE (100) Stearyl C Ethoxylated Non-ionic 0 15.8 17.2 18 40 fatty acid POE (40) Stearyl D Ethoxylated Non-ionic 0 10.6 13.0 18 14 fatty acid POE (14) isostearyl E Ethoxylated Non-ionic 0 16.4 18.8 fatty acid unspecified F Ethoxylated Non-ionic 0 16.8 17.4 16/18 40 alcohol POE (40) cetyl/stearyl (40/70 volume)

The viscosity of the blend using Fracsol, a product of EnerChem, as the dispersed organic fluid, was then measured with a Fann 35 rheometer equipped with an R1B2 geometry at 300 and 100 rpm. The viscosity of the emulsions at a shear rate of 100/s was then calculated and the results are set forth in Table III below:

TABLE III Viscosity, 100 Viscosity, Ex. 300 rpm, 100 rpm, Cps@100/s, 300 rpm, rpm, Cps@100/s, No. Emulsifier RT RT RT 70° C. 70° C. 70° C. Comp. A No No 1 No No 1 Ex. 9 emulsion emulsion emulsion emulsion 10 B 177 109 1693 82 41 767 11 C 190 122 1827 64 40 614 12 D 125 82 1205 26 14 245 13 E 191 120 1831 94 60 903 14 F 120 74 1149 74 54 722

Examples 15-19

The protocol of Examples 9-14 above was repeated except that the dispersed organic fluid was RX-2100, a product of Canadian National Resources Limited. The results are set forth in Table IV below:

TABLE IV Ex. 300 rpm, 100 rpm, Viscosity, 300 rpm 100 rpm, Viscosity, No. Emulsifier RT RT Cps@100/s, RT 70° C. 70° C. Cps@100/s, 70° C. 15 B 147 97 1418 79 46 751 16 C 146 92 1401 73 47 702 17 D 81 52 779 6 4 58 18 E 160 98 1530 84 63 821 19 F 148 1425 1323 44 30 426

From the foregoing, it will be observed that numerous variations and modifications may be effected without departing from the true spirit and scope of the novel concepts of the invention.

Claims

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33. A method of stimulating a subterranean formation which comprises introducing into the formation. an emulsion comprising:

(a) a gelled external phase comprising (i.) an aqueous water-soluble solvent solution and (ii.) a polymeric viscosifying agent;
(b) an internal phase of an organic fluid;
(c) an emulsifying agent; and
(d) optionally, an oxidative and/or acidic breaker wherein the emulsion is substantially free of phosphorous.

34. The method of claim 33, wherein the emulsion is prepared on the fly.

35. The method of claim 33, wherein the emulsion contains no phosphorous.

36. The method of claim 33, wherein the emulsion further comprises a proppant.

37. The method of claim 33, wherein the emulsion further comprises a foaming or gasifying agent.

38. The method of claim 37, wherein the foaming or gasifying agent is carbon dioxide or nitrogen.

39. The method of claim 33, wherein the organic solvent of the organic solvent solution is selected from the group consisting of a C1-C4 alcohol, ethylene glycol, propylene glycol, acetone, methylene sulfonic acid, acetic acid, formic acid and hydroxy acetic acid and mixtures thereof.

40. The method of claim 39, wherein the organic solvent is a C1-C4 alcohol.

41. The method of claim 40, wherein the C1-C4 alcohol is methanol, ethanol or isopropanol.

42. The method of claim 41, wherein the C1-C4 alcohol is methanol.

43. The method of claim 33, wherein the emulsifying agent is at least one member selected from the group consisting of:

(a) alkoxylated non-ionic emulsifiers having a lipophilic portion comprising a C12-C36 alkyl, dialkyl or alkylaryl and a hydrophilic portion having 20 to 150 moles of polyalkylene oxide;
(b) an anionic, cationic or zwitterionic/amphoteric emulsifier having a lipophilic portion comprising a lipophilic portion comprising a C12-C22 alkyl, dialkyl or alkylaryl group and a hydrophilic portion having 10 to 80 moles of polyalkylene oxide;
(c) an ethylene oxide/propylene oxide block copolymer comprising between from about 10 to about 50 moles of propylene oxide and from about 20 to about 150 moles of ethylene oxide; and
(d) polyoxyalkylene sorbitan fatty acid esters.

44. The method of claim 33, wherein the emulsion contains an oxidative and/or acidic breaker and further wherein the oxidative and/or acidic breaker is selected from the group consisting of hydrochloric acid, formic acid, sulfamic acid, sodium bisulfate, an alkaline earth peroxide, an encapsulated persulfate, a catalyzed organic peroxide and a hydrochlorite bleach.

45. The method of claim 33, wherein the organic fluid is at least one member selected from the group consisting of diesel, kerosene, gasoline, reformate, naphthalene, condensate, crude oil, mineral oil, vegetable oil, lubricating oil, synthetic oil, animal oil, an aliphatic, alicyclic or aromatic hydrocarbon, alkene, alkadienes and ester.

46. The method of claim 45, wherein the organic fluid is selected from the group consisting of propane, n-butane, isobutane, n-hexane, n-octane, n-decane, n-tridecane, cyclohexane, benzene, toluene, xylene, ethylbenzene, naphthalene, a C8-C15 alkane, an alkene and an alkadiene.

47. The method of claim 33, wherein the polymeric viscosifying agent is selected from the group consisting of polysaccharides, polysaccharide derivatives containing monosaccharides, polyacrylates, polyacrylamides, acrylamide methyl propane sulfonic acid copolymers, polyvinyl alcohol, polyvinyl pyrrolidone, maleic anhydride methyl vinyl ether copolymers and polyethylene oxide.

48. The method of claim 47, wherein the polymeric viscosifying agent is a polysaccharide or a derivatized polysaccharide of sugars selected from the group consisting of glucose, galactose, mannose, xylose, arabinose, fructose, guar gum derivatives, xanthan gum and a starch derivative.

49. The method of claim 48, wherein the polymeric viscosifying agent is a guar derivative.

50. The method of claim 33, wherein the polymeric viscosifying agent is selected from the group consisting of hydroxypropyl guar, hydroxyethyl guar, carboxymethyl hydroxypropyl guar, carboxymethyl hydroxyethyl cellulose and hydroxypropyl cellulose.

51. The method of claim 49, wherein the guar derivative is a hydroxyalkylated guar or modified hydroxyalkylated guar.

52. The method of claim 51, wherein the guar derivative is hydroxypropyl guar.

53. The method of claim 33, wherein the HLB of the emulsifying agent is between from about 10 to about 20.

54. The method of claim 53, wherein the HLB of the emulsifying agent is between from about 16 to about 18.

55. The method of claim 33, wherein the relative solubility number of the emulsifying agent is in excess in 10.

56. The method of claim 55, wherein the relative solubility number of the emulsifying agent is between from about 13 to about 17.

57. A method of stimulating a subterranean formation which comprises introducing into the formation a gelled emulsion comprising:

(a) from about 15 to about 50 volume percent of a blend of a C1-C4 alkanol and water;
(b) from about 50 to about 85 volume percent of a dispersed organic fluid;
(c) a polymeric viscosifying agent;
(d) an emulsifying agent; and
(e) optionally, an oxidative and/or acidic breaker wherein the emulsion is substantially free of phosphorous.

58. The method of claim 57, wherein the blend of C1-C4 alkanol and water contains between from about 15 to about 80 volume percent of alkanol and the remainder water.

59. The method of claim 57, wherein the alkanol is methanol.

60. The method of claim 57, wherein the dispersed organic fluid is hydroxypropyl guar having a molar substitution between from about 0.80 to about 1.20.

61. The method of claim 57, wherein the emulsifying agent is at least one member selected from the group consisting of:

(a) alkoxylated non-ionic emulsifiers having a lipophilic portion comprising a C12-C36 alkyl, dialkyl or alkylaryl and a hydrophilic portion having 20 to 150 moles of polyalkylene oxide;
(b) an anionic, cationic or zwitterionic/amphoteric emulsifier having a lipophilic portion comprising a lipophilic portion comprising a C12-C22 alkyl, dialkyl or alkylaryl group and a hydrophilic portion having 10 to 80 moles of polyalkylene oxide;
(c) an ethylene oxide/propylene oxide block copolymer comprising between from about 10 to about 50 moles of propylene oxide and from about 20 to about 150 moles of ethylene oxide; and
(d) polyoxyalkylene sorbitan fatty acid esters.

62. A method of stimulating a subterranean formation which comprises introducing into the formation an emulsion comprising:

(a) an external phase comprising a gelled product of a (i) C1-C4 alkanol and water; and (ii) a viscosifying polymer;
(b) an internal phase of a dispersed organic fluid; and
(c) an emulsifying agent.

63. The method of claim 62, wherein the external phase further comprises an oxidative and/or acidic breaker.

64. The method of claim 62, wherein the internal phase further comprises carbon dioxide.

Patent History
Publication number: 20080217012
Type: Application
Filed: Mar 8, 2007
Publication Date: Sep 11, 2008
Applicant:
Inventors: John Roland Delorey (Calgary), Brad Rieb (Calgory)
Application Number: 11/715,566
Classifications
Current U.S. Class: Chemical Inter-reaction Of Two Or More Introduced Materials (e.g., Selective Plugging Or Surfactant) (166/300); Processes (166/244.1)
International Classification: E21B 43/16 (20060101);