Classifications

• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
  • C09K8/60—Compositions for stimulating production by acting on the underground formation
  • C09K8/62—Compositions for forming crevices or fractures
  • C09K8/66—Compositions based on water or polar solvents
• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
  • C09K8/60—Compositions for stimulating production by acting on the underground formation
  • C09K8/607—Compositions for stimulating production by acting on the underground formation specially adapted for clay formations
• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
  • C09K8/60—Compositions for stimulating production by acting on the underground formation
  • C09K8/62—Compositions for forming crevices or fractures
  • C09K8/72—Eroding chemicals, e.g. acids
  • C09K8/74—Eroding chemicals, e.g. acids combined with additives added for specific purposes
• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K2208/00—Aspects relating to compositions of drilling or well treatment fluids
  • C09K2208/12—Swell inhibition, i.e. using additives to drilling or well treatment fluids for inhibiting clay or shale swelling or disintegrating

Definitions

• the present invention relates to multi-stage methods for treating a subterranean formation in order to desensitize formation faces to deleterious chemical or physical changes.
• formation faces refers to any portion of the formation that is exposed to, for example, a treatment fluid, and includes fracture faces and platelet faces.
• ductile refers to becoming able to deform under pressure.
• Troublesome formations may include, but not be limited to, water-sensitive clays, tight gas formations, shales, and coal beds.
• the terms “clays” and “water-sensitive clays” are used herein interchangeably to generally indicate water-sensitive clays that, when contacted by aqueous fluids in disequilibrium with the minerals in the formation, tend to swell and/or migrate.
• the clay content of the formations may be a single species of a clay mineral or several species, including, but not limited to, the mixed-layer types of clay.
• the term "tight gas” refers to gas found in sedimentary rock that is cemented together so that permeabilities are relatively low.
• the term “shale” refers to a sedimentary rock formed from the consolidation of fine clay and silt materials into laminated, thin bedding planes.
• coal bed refers to a rock formation that may be comprised of, inter alia, one or more types of coal, including, but not limited to, peat, lignite, sub-bituminous coal, bituminous coal, anthracite, and graphite.
• the desensitizing agents are removed from the desensitizing solution by the formation faces through known mechanisms including, but not limited to, adsorption, ion exchange, and chemical reaction. As the concentration of the desensitizing agents decreases in the remaining solution, untreated formation faces are exposed to aqueous fluids which promotes the deleterious chemical and physical changes.
• Current state-of-the- art implementation of desensitizing solutions call for injection of a single bolus of a relatively high concentration of desensitizing solution into the subterranean formation. Using such a method results in the depletion of desensitizing agents most notably at the leading-edge of the desensitizing solution as the solution migrates through the subterranean formation.
• the present invention relates to multi-stage methods for treating a subterranean formation in order to desensitize formation faces to deleterious chemical or physical changes.
• a method of desensitizing a subterranean formation may comprise : introducing a leading- edge fluid comprising a first base fluid and a first desensitizing agent, wherein the first desensitizing agent is present in the first base fluid at a first concentration; then introducing a treatment fluid comprising a second base fluid and a second desensitizing agent, wherein the second desensitizing agent is present in the second base fluid at a second concentration; and wherein the first concentration is higher than the second concentration.
• a method of desensitizing a subterranean formation may comprise : introducing a leading- edge fluid into a subterranean formation at or above the matrix pressure, wherein the leading-edge fluid comprises a first base fluid and a first desensitizing agent, wherein the first desensitizing agent is present in the first base fluid at a first concentration; then introducing a treatment fluid into the subterranean formation at or above the matrix pressure, wherein the treatment fluid comprises a second base fluid and a second desensitizing agent, wherein the second desensitizing agent is present in the second base fluid at a second concentration; and wherein the first concentration is higher than the second concentration.
• a method of desensitizing a subterranean formation may comprise : introducing a leading- edge fluid comprising a first base fluid and a first desensitizing agent above the matrix pressure into the subterranean formation, wherein the first desensitizing agent is present in the first base fluid at a first concentration, wherein the first concentration ranges from about 0.1% to about 15% v/v of first desensitizing agent to first base fluid; then introducing a treatment fluid comprising a second base fluid and a second desensitizing agent, wherein the second desensitizing agent is present in the second base fluid at a second concentration, wherein the second concentration ranges from about 0.001% to about 5% v/v of second desensitizing agent to second base fluid; and wherein the desensitizing solution is the same chemical composition in the leading-edge fluid and treatment fluid .
• Figure 1 provides illustrative graphs of the concentration of the desensitizing agent within the fluid phase as a function of depth of penetration from the wellbore.
• Figure 2 provides illustrative graphs of the concentration of the desensitizing agent at the formation faces as a function of depth of penetration from the wellbore.
• Figure 3 provides an illustrative graph of a nonlimiting example of an injection profile of a wellbore treatment according to the present invention.
• the present invention relates to multi-stage methods for treating a subterranean formation in order to desensitize formation faces to deleterious chemical or physical changes.
• the present invention provides for methods yielding formation face desensitization, i.e. , mineral desensitization, against deleterious chemical and/or physical changes that penetrate deeper into the subterranean formation while decreasing the overall amount of the desensitizing agents.
• Reduction in the amount of desensitizing agents used can result in a significant cost savings for the operator and may help reduce the environmental impact of the treatment.
• penetration refers to both the distance traversed from the wellbore within a fracture network and the radially distance from the fracture into the formation, e.g., penetrating radially several clay platelets deep into the formation along a fracture.
• formation face includes the faces encountered radially from the fracture network into the formation.
• a method of desensitizing a subterranean formation may generally include the steps of: introducing a leading-edge fluid comprising a first base fluid and a first desensitizing agent into at least a portion of the subterranean formation, wherein the first desensitizing agent is present in the first base fluid at a first concentration; and then introducing a treatment fluid comprising a second base fluid and a second desensitizing agent into at least a portion of the subterranean formation, wherein the second desensitizing agent is present in the second base fluid at a second concentration, and wherein the first concentration is higher than the second concentration.
• leading-edge fluid Because the leading-edge fluid enters the formation first, it contacts formation faces, such as water-sensitive clays, before other liquids are placed into the formation. That is, the leading-edge fluid is highly likely to encounter sensitive minerals. The depletion of desensitizing agents in the leading-edge fluids, as to contacts new formation faces, may be extensive. Therefore, a high concentration of desensitizing solution in the leading-edge fluid may effectively desensitize minerals as the fluid penetrates the subterranean formation and maintains a desensitizing solution concentration above the necessary amount to desensitize minerals deeper into the subterranean formation. The treatment fluids placed subsequent to the leading-edge fluid may exhibit lower levels of desensitizing solution than required in traditional methods.
• the treatment fluid needs not act as the primary desensitization fluid . Rather, the desensitizing agents in the treatment fluid following the leading-edge fluid may be used to desensitize any newly exposed minerals during the treatment. Therefore, the concentration of the desensitizing agents in the fracturing fluid is significantly lower than in the leading-edge fluid.
• Figures 1-3 compare a nonlimiting example of a treatment according to an embodiment of the present invention to current methods of injecting desensitizing agents at a constant concentration.
• Figure 3 illustrates the injection profile, i.e. , the concentration injected as a function of time.
• the leading-edge method injects first a higher concentration of destabilizing agent than a lower concentration.
• the method to which this example compares injects a single concentration over the same amount of time.
• Figures 1 and 2 provide a series of illustrative snapshots of what may be occurring over time in the subterranean formation as the two methods would be implemented.
• Figure 1 looks at the concentration remaining in the fluid phase as a function of depth of penetration into the formation. It should be noted this is meant to illustrate the concentration in solution in the formation, e.g. , down the length of a fracture, at a specific time point and not the injection profile. The various time points show the fluid in both treatments being depleted .
• the treatment fluid which has a significantly lower concentration, injected after the leading-edge fluid maintains the level of desensitization and therefore is not significantly depleted . Further illustrated is the level of desensitization of the formation face with a line indicating "fully" desensitized minerals.
• desensitized minerals includes substantially desensitized and most likely varies based on depth of penetration into the formation.
• the leading-edge of the fluid may not have a high enough concentration of desensitizing agents to interact with the formation faces, i.e. , sensitive minerals may undergo deleterious chemical and/or physical changes at the leading-edge of a treatment.
• the methods of the present invention aim to overcome this problem by introducing a leading-edge fluid that comprises a higher concentration of desensitizing agents so that at the leading-edge of a treatment sensitive minerals are effectively desensitized .
• Figure 2 provides the concentration injection profile at time point 3 of Figure 1.
• the illustrative method of the present invention uses less desensitizing agent than the method currently implemented .
• compositions and methods of the present invention may be used in subterranean formations containing water-sensitive clays, tight gas formations, shales, and coal beds.
• Some suitable methods of the present invention may comprise placing a leading-edge fluid comprising a concentrated desensitizing solution into the subterranean reservoir to expose formation faces to the desensitizing agent so as to reduce, or remediate, their sensitivity to deleterious chemical and/or physical changes.
• Subsequently placed treatment fluids may comprise a lower concentration of desensitizing solution to preserve the existing level of mineral desensitization and/or inhibit sensitization of newly exposed formation faces.
• a treatment fluid introduced into a subterranean formation subsequent to a leading-edge fluid may be a fracturing fluid, an acidizing fluid, a stimulation fluid, a sand control fluid, a completion fluid, a frac-packing fluid, or gravel packing fluid .
• the methods, leading-edge fluids, and subsequent treatment fluids of the present invention may be used in full-scale operations, pills, or any combination thereof.
• a "pill” is a type of relatively small volume of specially prepared treatment fluid placed or circulated in the wellbore.
• leading-edge fluids and/or subsequent treatment fluids may be introduced at or above "fracture pressure,” which as used herein refers to pressures necessary to create or extend at least one fracture within the subterranean formation.
• leading- edge fluids and/or subsequent treatment fluids may be introduced at "matrix pressure,” which as used herein refers to pressures below the fracture pressure of the formation.
• leading-edge fluids may be introduced into a single wellbore multiple times, e.g. , multi-stage fracturing operations where sections of the formation are fractured then plugged sequentially where each fracturing includes introducing a leading-edge fluid followed by at least one subsequent treatment fluid .
• a fracturing method may comprise multiple stages (or sections).
• the stages may include, but not be limited to, introducing a leading-edge fluid or a treatment fluid, each with the appropriate concentration of desensitizing agent, that comprise an additive that may include, but not be limited to, proppants; diverting agents including degradable diverting agents; plugs; plugging agents; and any combination thereof.
• a multi-stage treatment may include
• a fourth treatment fluid comprising a diverting agent bstantially divert subsequent fluids from the second stage of the wellbore, the fourth treatment fluid optionally comprising a desensitizing agent and/or a proppant;
• the stages may be defined by a perforation or a cluster of perforations.
• the diverting agent in any of the above steps may be interchanged with a plug, e.g. , a packer, a bridge plug, a frac plug, or the like, or a plugging agent, e.g. , perf balls, gels, plugging foams, degradable diverting agents, and the like.
• said treatment fluid may be a fracturing fluid .
• steps e.g., flushing treatments and acidizing treatments, may be included within the above nonlimiting example.
• One skilled in the art, with the benefit of this disclosure, should understand the plurality of steps that may be included and the order in which to include them to achieve a desired wellbore treatment design.
• leading-edge fluids with subsequent treatment fluids may be used in a high-rate water frac including multi-stage high-rate water fracs. These are typically done in shales that have high clay content; therefore, a leading-edge fluid with a desensitizing agent may be especially useful.
• leading-edge fluids may be used in a remedial treatment for a subterranean formation having at least some formation faces having undergone deleterious chemical and/or physical changes.
• a leading-edge fluid may be introduced into a subterranean formation for remediation at a matrix pressure so as to treat existing formation faces therein. For example, when the fractures are worn out and need to be restimulated .
• leading-edge fluids with subsequent treatment fluids may be used for injection wells.
• injection wells refer to wells in which fluids are injected rather than produced with the primary objective of maintaining reservoir pressure that may assist in production from a nearby well .
• injection wells In formations with sensitive minerals, the deleterious chemical and/or physical changes to formation faces can lead to higher injection pressures needed to maintain reservoir pressure. It is believed that employing leading edge fluids and subsequent treatment fluids, as described in some embodiments herein, could result in a lower injection pressure being required for injection wells.
• leading-edge fluids with subsequent treatment fluids may be used in a well completion operation, such as a pre-pad fluid in gravel packing operations. The higher concentration of desensitizing agents in a leading-edge fluid would protect the surrounding formation during the wellbore completion operations.
• the optimal concentration of desensitizing agents to use in the leading-edge fluid can be determined by one skilled in the art.
• One suitable method for determining the optimal concentration of desensitizing agents to be used in the leading-edge fluid involves a four-step analysis. First, determine the total mineral concentration(s) and mineral type(s) from known methods including, but not limited to, x-ray analysis and scanning electron microscopy. Second, determine the desensitizing capacity of a formation sample. By way of non-limiting example, the cation exchange capacity of a formation sample can be determined by Langmuir adsorption isotherms, surface roughness, and cation exchange capacity. Third, estimate the generated surface area during the fracture treatment using known simulation methods. Finally, estimate the mass of desensitizing agents required using the values determined in the first three steps.
• An approximate concentration of desensitizing agents to use in the leading-edge fluid can be determined by one skilled in the arts by generally characterizing the degree to which the mineral(s) in the subterranean formation require desensitization.
• water-sensitive clays may be categorized as very water sensitive, moderately water sensitive, or minimally water sensitive.
• one skilled in the arts may be able to estimate the necessary desensitization of the minerals in the subterranean formation based on known characteristics of the formation, nearby wells, and similar formations.
• a preferred method for desensitizing minerals calls for the concentration of the desensitizing agents in the leading-edge fluid to range from a lower limit of about 0.01%, 0.05%, 0.1%, 0.5%, 1%, 2%, 5%, or 10% to an upper limit of about 60%, 50%, 25%, 15%, 10%, or 5% v/v, and wherein the concentration may range from any lower limit to any upper limit and encompass any subset therebetween. Minerals requiring more desensitization may require more concentrated desensitizing solution in the leading-edge fluid relative to the fracturing fluid .
• a preferred method for desensitizing minerals calls for the concentration of the desensitizing agents in subsequent treatment fluids to range from a lower limit of about 0.0001%, 0.001%, 0.01%, 0.1%, or 1% to an upper limit of about 20%, 10%, 5%, 2%, 1%, or 0.1% v/v, where the concentration may range from any lower limit to any upper limit and encompass any subset therebetween.
• the concentration of desensitizing agents in the leading-edge fluid may range from a lower limit of about 2, 3, 5, 10, or 25 times to an upper limit of about 5000, 2500, 1000, 500, 100, 75, 50, or 25 times greater than the concentration of desensitizing agents in the treatment fluid, and wherein the concentration may range from any lower limit to any upper limit and encompass any subset therebetween.
• the concentration of desensitizing agents may vary during the fracturing operation, i.e. , during the introduction of the fracturing fluid.
• the concentration change may be step-wise, gradient, or any combination thereof.
• a transition fluid may be used between the leading-edge fluid and subsequent treatment fluids.
• the transition fluid may comprise desensitizing agents at an intermediate concentration relative to the leading-edge fluid and subsequent treatment fluids.
• a transition fluid may provide for a step-wise, gradient, or combination thereof concentration reduction of the desensitizing agents from the leading-edge fluid to the subsequent treatment fluids.
• the transition fluid may be introduced to the subterranean formation at a matrix pressure, at or above formation pressure, or any combination thereof.
• the concentration of desensitizing agents in leading-edge fluids, transition fluids, and/or subsequent treatment fluids may be adjusted on-the-fly.
• the fluid being introduced into the wellbore may be changed based on a pressure change observed at the surface of the wellbore.
• a pressure drop at the surface of a wellbore may indicated fracturing is occurring and a transition to a leading-edge fluid is necessary.
• Nearly all desensitizing agents suitable for use in subterranean operations may be used in the methods of the present invention including, but not limited to, inorganic acids, salts, polyelectrolytes, multivalent ions, inorganic bases, strong bases, oxides, resins, surfactants, polymers, cationic polymers, methyl glucosides, polyglycerols, polyglycols, emulsion facilitating particles, chelating agents, phosphines, soluble organic stabilizing compounds, silica control agents, embrittlement modification agents, surface modification agents, microparticles, nanoparticles, and any combination thereof.
• the desensitizing agents may be the same or different chemical compositions within the various fluids for use in the methods provided herein . Utilizing different chemical compositions may be advantageous to further reduce costs.
• the leading-edge fluid may comprise an expensive desensitizing agent that is more effective at desensitizing formation faces. Subsequent fluids may be less expensive desensitizing agents that maintain the level of desensitization at the formation faces.
• the desensitizing agents may be for desensitizing a single mineral composition or multiple mineral compositions, e.g. , desensitizing water-swellable clays and shales in a single treatment fluid .
• the desensitizing agents can be at the same or different concentrations relative to one another within the various fluids for use in the methods provided herein .
• the preparation of a desensitizing solution is expected to be according to a preferred preparation embodiment for the desensitizing solution, which is known by one skilled in the arts.
• the desensitizing agents may be in various forms : foams, latexes, microemulsions, emulsions, simple solutions, surfactants, nanoparticles, microparticles, degradable particulates, dry form that later breaks up, gelled form, and combinations thereof.
• Desensitizing agents may interact with the surfaces, interlayers, and cores of minerals and mineral platelets to mitigate or reverse mineral hydration, swelling, and sloughing .
• Charges on the minerals and mineral platelets may permit interaction with dissolved/suspended molecules and ions in fluids, both native and non-native to the formation.
• the net negative charge on a platelet may be typically balanced mainly by cationic molecules and ions, e.g., sodium ions and silicates.
• the cations, or charge-balancing ions, associated with the platelet faces are termed "exchangeable" as they can be readily substituted with other cations when presented to the clay platelets.
• Each macroscopic mineral particle may be comprised of many thousands of sandwiched mineral platelets, each having exchangeable cations and a layer of water therebetween.
• water may penetrate between the platelets, forcing them further apart.
• the cations present at the platelet faces may begin to diffuse away from platelet faces.
• the amount of water contained within the platelets may be dependant upon the pressure under which the mineral is located, typically the depth of the mineral deposit in the subterranean formation.
• Mechanisms of mineral hydration may include surface hydration through bonding of water molecules to oxygen atoms on the surface of mineral platelets; ionic hydration through hydration of interlayer cations with surrounding shells of water molecules; and osmotic hydration, which occurs in some minerals after they are completely surface hydrated and ionically hydrated, usually at 100% humidity.
• Suitable desensitizing agents may include, but not be limited to, salts, resins, soluble organic stabilizing compounds, silica control agents, embrittlement modification agents, and any combination thereof.
• inorganic acids, organic acids, salts thereof, and combinations thereof known in the art that are suitable for use in subterranean operations may be used in the methods of the present invention including, but not limited to, inorganic acids, salts of inorganic acids, organic acids, salts of organic acids, or any combination thereof.
• a "salt" of an acid, as that term is used herein, refers to any compound that shares the same base formula as the referenced acid, but one of the hydrogen cations thereon is replaced by a different cation (e.g., an antimony, bismuth, potassium, sodium, calcium, magnesium, cesium, zinc cation).
• Suitable inorganic salts may include cations of Group I and II elements.
• inorganic acid refers to any acidic compound that does not comprise a carbon atom .
• suitable salts of inorganic acids include, but are not limited to, sodium chloride, calcium chloride, potassium chloride, sodium bromide, calcium bromide, potassium bromide, sodium sulfate, calcium sulfate, sodium phosphate, calcium phosphate, sodium nitrate, calcium nitrate, cesium chloride, cesium sulfate, cesium phosphate, cesium nitrate, cesium bromide, potassium sulfate, potassium phosphate, potassium nitrate, zinc chloride, magnesium chloride, magnesium bromide, zinc bromide, and the like.
• Suitable salts may be Group I and II salts.
• organic acid refers to any acidic compound that comprises a carbon atom .
• suitable salts of organic acids include, but are not limited to, sodium acetate, sodium formate, calcium acetate, calcium formate, cesium acetate, cesium formate, potassium acetate, potassium formate, magnesium acetate, magnesium formate, zinc acetate, zinc formate, antimony acetate, antimony formate, bismuth acetate, and bismuth formate.
• Suitable inorganic acids may include, but not be limited to, hydrochloric acid, nitric acid, phosphoric acid, sulfuric acid, boric acid, and the like, or any combination thereof.
• Suitable organic acids may include, but not be limited to, acetic acid, formic acid, citric acid, oxalic acid, and the like, or any combination thereof.
• the various fluids for use in the methods provided herein may comprise any combination of inorganic acids, salts of inorganic acids, organic acids, and/or salts of organic acids.
• the one or more inorganic acids and/or organic acids (or salts thereof) may be present in the various fluids for use in the methods provided herein in an amount sufficient to provide the desired effect.
• the amount of the inorganic acid(s) and/or organic acid(s) (or salts thereof) included in the various fluids for use in the methods provided herein may depend upon the particular acid and/or salt thereof used, as well as other components of the various fluids, and/or other factors that will be recognized by one of ordinary skill in the art with the benefit of this disclosure.
• inorganic bases organic bases, strong bases, and combinations thereof known in the art suitable for use in subterranean operations may be used in the methods of the present invention.
• Suitable inorganic bases may include, but not be limited to, sodium hydroxide, ammonium hydroxide, barium hydroxide, calcium hydroxide, magnesium hydroxide, potassium hydroxide, sodium carbonate, ammonium carbonate, barium carbonate, calcium carbonate, magnesium carbonate, potassium carbonate, magnesium chloride triethylamine, sodium amide, and the like, or any combinations thereof.
• Suitable organic bases may include, but not be limited to, pyridine, methyl amine, imidazole, benzimidazole, histidine, phophazene, dimethylaniline, trimethylamine, piperidine, and the like, or any combination thereof.
• Suitable strong bases may include, but not be limited to, sodium hydroxide, potassium hydroxide, calcium hydroxide, barium hydroxide, and the like, or any combination thereof.
• the various fluids for use in the methods provided herein may comprise any combination of inorganic bases, organic bases, and strong bases.
• the one or more inorganic bases, organic bases, and strong bases may be present in the various fluids for use in the methods provided herein in an amount sufficient to provide the desired effect.
• the amount of the inorganic bases, organic bases, and strong bases included in the various fluids for use in the methods provided herein may depend upon the particular base used, as well as other components of the various fluids, and/or other factors that will be recognized by one of ordinary skill in the art with the benefit of this disclosure.
• any polymer or resin known in the art that is suitable for use in subterranean operations may be used in the methods of the present invention, including salts thereof.
• cationic polymer may be preferred, e.g., amines and imines.
• the polymers and resins can be synthetic or natural and non-hardenable or hardenable.
• Polymers and resins suitable for use in the present invention include all polymers, resins, and combinations thereof known in the art that desensitize clay.
• polymers and resins suitable for use in the present invention include, but are not limited to : acrylic acid polymers; partially hydrolyzed polyacrylamide (PHA); acrylic acid ester polymers; acrylic acid derivative polymers; acrylic acid homopolymers; acrylic acid ester homopolymers (such as poly(methyl acrylate), poly(butyl acrylate), and poly(2- ethylhexyl acrylate)); acrylic acid ester co-polymers; methacrylic acid derivative polymers; methacrylic acid homopolymers; methacrylic acid ester homopolymers (such as poly(methyl methacrylate), poly(butyl methacrylate), and poly(2- ethylhexyl methacrylate)); acrylamido-methyl-propane sulfonate polymers; acrylamido-methyl-propane sulfonate derivative polymers; acrylamido-methyl- propane sulfonate co-polymers; acrylic acid/acrylamido-
• the polymers or resins (or salts thereof) and combinations thereof may be present in the various fluids for use in the methods provided herein in an amount sufficient to provide the desired effect.
• the amount of the polymer or resin (or salts thereof) included in the various fluids for use in the methods provided herein may depend upon the particular polymer, resin, and/or salt thereof used, as well as other components of the various fluids, and/or other factors that will be recognized by one of ordinary skill in the art with the benefit of this disclosure.
• Suitable surfactants and combinations thereof for use in the present invention may include anionic surfactants, cationic surfactants, amphoteric surfactants, and/or nonionic surfactants.
• surfactants that may be suitable for use in the present invention include, but are not limited to Ci2 to C 2 2 alkyl phosphonate surfactants, ethoxylated nonyl phenol phosphate esters, ethoxylated fatty acids, sodium dodecyl sulfate, poly(vinyl alcohol), sodium dodecylbenzenesulfonic acid, cetyltrimethylammonium bromide, cetylpyridinium bromide, hexadecylmaltoside, trimethylcocoammonium chloride, trimethyltallowammonium chloride, dimethyldicocoammonium chloride, bis(2- hydroxyethyl)tallowamine, bis(2-hydroxyethyl)erucylamine, erucyl methyl bis(
• alkyl quaternary ammonium salts alkyl pyridinium salts, and any derivatives thereof.
• An example of commercially-available surfactants that may be suitable in certain embodiments of the present invention is 19NTM surfactant (a cationic nonemulsifier, available from Halliburton Energy Services, Inc.), TWEEN® surfactants (a polysorbate surfactant, available from Sigma-Aldrich), TRITON® surfactants (a nonionic surfactant, available from Sigma-Aldrich), and BRIJ® surfactants (a nonionic surfactant, available from Sigma-Aldrich).
• 19NTM surfactant a cationic nonemulsifier, available from Halliburton Energy Services, Inc.
• TWEEN® surfactants a polysorbate surfactant, available from Sigma-Aldrich
• TRITON® surfactants a nonionic surfactant, available from Sigma-Aldrich
• BRIJ® surfactants a nonionic sur
• Certain cationic surfactants may be incompatible or undesirable to use with certain anionic polymers, minerals present on the mineral surface, and/or other elements or conditions in a treatment fluid (e.g. , pH) and/or subterranean formation present in a particular application of the present invention .
• a treatment fluid e.g. , pH
• subterranean formation present in a particular application of the present invention .
• the surfactants (or salts thereof) and combinations thereof may be present in the various fluids for use in the methods provided herein in an amount sufficient to provide the desired effect.
• the amount of the surfactant (or salts thereof) included in the various fluids for use in the methods provided herein may depend upon the particular surfactant and/or salt thereof used, as well as other components of the various fluids, and/or other factors that will be recognized by one of ordinary skill in the art with the benefit of this disclosure.
• particulates may comprise emulsion facilitating particles, i.e. , any particle with a size smaller than a discontinuous phase droplet in the emulsion .
• the emulsion facilitating particles have a size less than about 75 microns. Generally, smaller emulsion facilitating particles are preferred .
• Suitable examples of emulsion facilitating particles include particles that have or exhibit a suitable fluid contact angle, such as any organically modified material, metal sulfate, or polymer. Suitable organically modified materials may include modified silicas, modified fumed silicas, or various clay types.
• Fumed silicas may have slightly different degrees of organic modification when small amounts of dimethyldichlorosilane are added in the process of fuming the silica .
• suitable modified silicas or modified fumed silicas include, but not be limited to, HDK® silicas (silica silylates, Wacker-Chemie GmbH) such as H DK® H20, HDK® H30, and H DK® H2000.
• the HDK® silicas are loose white powders that are primarily amorphous lattice structures of Si0 2 .
• Suitable organically modified materials also may include organically modified aluminum, titanium, zirconium, or various clay types.
• Various clay types may include non-kaolinitic clays such as bentonite, kaolin clays, and any other clay types capable of cation exchange.
• the emulsion facilitating particles and combinations thereof may be present in the various fluids for use in the methods provided herein in an amount sufficient to provide the desired effect.
• the amount of the emulsion facilitating particles included in the various fluids for use in the methods provided herein may depend upon the particular emulsion facilitating particles used, as well as other components of the various fluids, and/or other factors that will be recognized by one of ordinary skill in the art with the benefit of this disclosure.
• Suitable organic acids include, but are not limited to, formic acid, acetic acid, citric acid, glycolic acid, lactic acid, 3- hydroxypropionic acid, a Ci to Ci 2 carboxylic acid, an aminopolycarboxylic acid such as hydroxyethylethylenediamine triacetic acid, and combinations thereof.
• the various fluids for use in the methods provided herein may comprise a salt of an organic acid .
• a "salt" of an acid refers to any compound that shares the same base formula as the referenced acid, but one of the hydrogen cations thereon is replaced by a different cation (e.g.
• an antimony, bismuth, potassium, sodium, calcium, magnesium, cesium, or zinc cation examples include, but are not limited to, sodium acetate, sodium formate, calcium acetate, calcium formate, cesium acetate, cesium formate, potassium acetate, potassium formate, magnesium acetate, magnesium formate, zinc acetate, zinc formate, antimony acetate, antimony formate, bismuth acetate, and bismuth formate.
• the one or more organic acids (or salts thereof) may be present in the various fluids for use in the methods provided herein in an amount sufficient to provide the desired effect.
• the amount of the organic acid(s) (or salts thereof) included in the various fluids for use in the methods provided herein may depend upon the particular acid and/or salt used, as well as other components of the treatment fluid, and/or other factors that will be recognized by one of ordinary skill in the art with the benefit of this disclosure.
• a variety of monomers (or salts thereof) are suitable for use as an organic stabilizing compound in the present invention.
• suitable monomers include, but are not limited to, acrylic acid, methacrylic acid, acrylamide, methacrylamide, 2-methacrylamido-2-methylpropane sulfonic acid, dimethylacrylamide, vinyl sulfonic acid, N,N-dimethylaminoethylmethacrylate, 2- triethylammoniumethylmethacrylate chloride, N,N-dimethyl- aminopropylmethacryl-amide, methacrylamidepropyltriethylammonium chloride, N-vinyl pyrrolidone, quaternary amines, imidazolium salts, phosphonium salts, vinyl-phosphonic acid, methacryloyloxyethyl trimethylammonium sulfate, 1- carboxy-N,N,N-trimethyl methanaminium chloride, 2-hydroxy-N,N
• the organic stabilizing compounds and combinations thereof may be present in the various fluids for use in the methods provided herein in an amount sufficient to provide the desired effect.
• the amount of the organic stabilizing compounds included in the various fluids for use in the methods provided herein may depend upon the particular organic stabilizing compounds used, as well as other components of the various fluids, and/or other factors that will be recognized by one of ordinary skill in the art with the benefit of this disclosure.
• Suitable chelating agents may comprise amines, esters, carboxylic acids, alcohols, ethers, aldehydes, ketones, mercaptans, thiols, and/or combinations thereof.
• chelating agents include ethylenediaminetetraacetic acid (“EDTA”), nitrilotriacetic acid (“NTA”), hydroxyethylethylenediaminetriacetic acid (“HEDTA”), dicarboxymethyl glutamic acid tetrasodium salt (“GLDA”), diethylenetriaminepentaacetic acid (“DTPA”), propylenediaminetetraacetic acid (“PDTA”), ethylenediaminedi(o- hydroxyphenylacetic) acid (“EDDHA”), glucoheptonic acid, gluconic acid, amino tri(methylene phosphonic acid), penta sodium salt of aminotri(methylene phosphonic acid), tetra sodium salt of aminotri(methylene phosphonic acid), 1- hydroxyethylidene-l, l,-diphosphonic acid, hexamethylenediamine tetra(methylene phosphonic acid), diethylenetriamine penta(methylene phosphonic acid), bis(hexyl
• the chelating agents and combinations thereof may be present in the various fluids for use in the methods provided herein in an amount sufficient to provide the desired effect.
• the amount of the chelating agents included in the various fluids for use in the methods provided herein may depend upon the particular chelating agents used, as well as other components of the various fluids, and/or other factors that will be recognized by one of ordinary skill in the art with the benefit of this disclosure.
• Nearly all silica control agents and combinations thereof known in the art that are suitable for use in subterranean operations may be used in the methods of the present invention .
• silica may act as a binder of clay, sand, diageneous minerals, clasts, and/or other fine particulates in subterranean formations.
• the silica control agent may comprise a compound chosen from the group consisting of: silica, silicates (e.g. , orthosilicates, pyrosilicates, cyclic-silicates, single chain silicates, double chain silicates, sheet silicates, colloidal silicates), silanes, organo-silanes, and any combination thereof.
• silicates e.g. , orthosilicates, pyrosilicates, cyclic-silicates, single chain silicates, double chain silicates, sheet silicates, colloidal silicates
• silanes e.g. , silica control agent
• organo-silanes e.g. , colloidal silicates
• Suitable examples of naturally occurring minerals comprising silica or a silicate include, but are not limited to, phenacite, willemite, zircon, olivine, garnet, thortveitite, benitoite, beryl, pyroxenes, enstatite, spodumene, pollucite, tremolite, crocidolite, talc, petalite, cristobalite, and any combination thereof.
• phenacite willemite, zircon, olivine, garnet, thortveitite, benitoite, beryl, pyroxenes, enstatite, spodumene, pollucite, tremolite, crocidolite, talc, petalite, cristobalite, and any combination thereof.
• finely ground refers to mesh sizes smaller than or equal to 270 U .S.
• Suitable silicates include, but are not limited to, potassium silicate, calcium silicate, sodium aluminum silicate, and sodium silicate.
• Suitable commercially available silica control agents may include INJ ECTROL® (a sealant, available from Halliburton Energy Services, Inc) . However, dilution to near the saturation point may be required for such products to be suitable silica control agents in order to avoid precipitation and plugging of the formation .
• non-polymeric metal silicates such as sodium silicate or potassium silicate
• the silicate may be sodium silicate having a weight ratio of Si0 2 to Na 2 0 ranging from about 3.25 : 1 to 1.5 : 1.
• the silicate may be potassium silicate having a ratio of Si0 2 to K 2 0 ranging from about 2.5 : 1 to 1.5 : 1.
• Silanes may include chemicals that contain silicone at the center of the silane molecule that is chemically attached to a first functional group such as vinyl, amino, chloro, epoxy, mercapto, and a second functional group such as methoxy or ethoxy.
• a first functional group such as vinyl, amino, chloro, epoxy, mercapto
• a second functional group such as methoxy or ethoxy.
• silanes and organo-silanes may include, but not be limited to, N-2-(aminoethyl)-3-aminopropyltrimethoxysilane, 3-glycidoxypropyltrimethoxysilane, n-beta-(aminoethyl)-gamma-aminopropyl trimethoxysilane, methyltrimethoxysilane, vinyltrimethoxysilane, methyltriethoxysilane, tetraethoxysilane, methyltriacetoxysilane, methyl tris-(N- methylbenzamidosilane), methyl tris-(methyl ethyl ketoximino) silane, methyl tris-(methylisobutylketoximino) silane, methyl vinyl bis-(methyl ethylketoximino) silane, tetrakis-(methyl ethylketoximino) silane, methyl tris
• the silica control agents and combinations thereof may be present in the various fluids for use in the methods provided herein in an amount sufficient to provide the desired effect.
• the amount of the silica control agents included in the various fluids for use in the methods provided herein may depend upon the particular silica control agent used, as well as other components of the various fluids, and/or other factors that will be recognized by one of ordinary skill in the art with the benefit of this disclosure.
• embrittlement and its derivatives as used herein refers to a process by which the properties of a material are changed through a chemical interaction such that a material that originally behaves in a ductile or plastic manner is transformed to a material that behaves in a more brittle manner. This may be determined by examining the Young's modulus and the Poisson's ratio of the natural rock before treatment. If the rock has become embrittled, the Young's modulus should be higher and the Poisson's ratio should be lower as compared to the natural rock before treatment.
• Young's modulus is the ratio of stress, which has units of pressure, to strain, which is dimensionless; therefore Young's modulus itself has units of pressure.
• the SI unit of modulus of elasticity (E, or less commonly Y) is the pascal (Pa or N/m 2 ); the practical units are megapascals (MPa or N/mm 2 ) or gigapascals (GPa or kN/mm 2 ). In United States customary units, it is expressed as pounds (force) per square inch (psi).
• Young's modulus, E can be calculated by dividing the tensile stress by the tensile strain :
• E is the Young's modulus (modulus of elasticity).
• F is the force applied to the object
• a Q is the original cross-sectional area through which the force is applied
• AL is the amount by which the length of the object changes
• L 0 is the original length of the object.
• Poisson's ratio (v) is the ratio, when a sample object is stretched, of the contraction or transverse strain (perpendicular to the applied load), to the extension or axial strain (in the direction of the applied load).
• Etrans is transverse strain (negative for axial tension, positive for axial compression).
• Suitable embrittlement modification agents for use in the present invention may comprise high alkaline materials. Suitable examples may include, but not be limited to, lithium hydroxide, sodium hydroxide, potassium hydroxide, rubidium hydroxide, calcium hydroxide, strontium hydroxide, barium hydroxide, cesium hydroxide, sodium carbonate, sodium silicate, lime, amines, ammonia, borates, Lewis bases, other strong bases, and any derivative or combination thereof.
• concentration of the embrittlement modification agent in a treatment fluid may depend on the desired pH (e.g., about 10 or above at downhole conditions) of the fluid given the factors involved in the treatment.
• the embrittlement modification agents and combinations thereof may be present in the various fluids for use in the methods provided herein in an amount sufficient to provide the desired effect.
• the amount of the embrittlement modification agents included in the various fluids for use in the methods provided herein may depend upon the particular embrittlement modification agent used, as well as other components of the treatment fluid, and/or other factors that will be recognized by one of ordinary skill in the art with the benefit of this disclosure.
• embrittlement modification agents for use in the present invention may comprise cationic additives, such as cationic polymers and cationic organic additives, to enhance the plasticity modification.
• Divalent cationic additives may be more stable. If used, such cationic additives may be used in an amount of about 0.01% to about 1% by weight of the embrittlement modification agents. Hydroxy aluminum and zirconium oxychloride are examples.
• CLA-STA ® XP CLA-STA ® FS
• CLAYFIX ® an acid salt, available from Halliburton Energy Services, Inc.
• CLAYFIX ® -II a temporary clay stabilizing additive, available from Halliburton Energy Services, Inc.
• CLAYFIX ® -II PLUS a temporary clay stabilizing additive, available from Halliburton Energy Services, Inc.
• HPT- 1TM a cationic polymer, available from Halliburton Energy Services, Inc.
• Suitable additives are described in the following patents, each of which are hereby incorporated by reference, U.S. Patent Nos. 5,097,094, 4,974,678, 4,424,076, and 4,366,071.
• embrittlement modification agents for use in the present invention may comprise salt(s) such as salts of lithium, sodium, potassium, rubidium, calcium, strontium, barium, cesium, magnesium, and manganese.
• salts such as salts of lithium, sodium, potassium, rubidium, calcium, strontium, barium, cesium, magnesium, and manganese.
• the ion exchange resulting from the presence of the salt is useful in aiding in the shrinkage of the rock.
• including surfactants in the embrittlement modification agents may facilitate ultra low surface tensions and allow these fluids to penetrate into a subterranean formation more easily, e.g. , via microfractures and between mineral platelets.
• microparticles refers to particles less than 500 microns in one dimension, but larger than nanoparticles.
• nanoparticles refers to particles with at least one dimension less than about 100 nm .
• microparticles and combinations thereof known in the art that are suitable for use in subterranean operations and can adsorb and/or bind to minerals may be used in the methods of the present invention.
• suitable microparticles may include, but not be limited to, metal oxide microparticles like silica, titania, alumina, magnesium oxide, calcium oxide, and the like; minerals like slag, zeolite, vitrified shale, silica flour, silica sand; polymeric microparticles including those that comprise the polymers and/or resins disclosed herein; or any combination thereof.
• Nanoparticles and combinations thereof known in the art that are suitable for use in subterranean operations and can adsorb and/or bind to minerals may be used in the methods of the present invention.
• suitable nanoparticles may include, but not be limited to, carbon nanoparticles like fullerenes (spherical or otherwise), endofullerenes, nanotubes (single or multi-walled), filled nanotubes, carbon nanohorns, carbon nano- bamboo, graphene (single to few layer thick), and carbon quantum dots; metal oxide nanoparticles like silica, titania, alumina, iron oxide, manganese oxide, zinc oxide, molybdenum oxide, magnesium oxide, and calcium oxide; metal nanoparticles like gold, palladium, silver, and palladium; nitride nanoparticles; carbide nanoparticles; magnetic nanoparticles like Fe 3 0 4 and gamma-Fe 2 0 3 ; quantum dots like CdSe and Z
• nanoparticles include nanorods, nanospheres, nanorices, nanowires, nanostars (like nanotripods and nanotetrapods), hollow nanostructures, hybrid nanostructures that are two or more nanoparticles connected as one, and non-nano particles with nano-coatings or nano-thick walls.
• nanoparticles include the functionalized derivatives of nanoparticles including, but not limited to, nanoparticles that have been functionalized covalently and/or non-covalently, e.g. , pi-stacking, physisorption, ionic association, van der Waals association, and the like.
• Suitable functional groups may include, but not be limited to, moieties comprising amines (1°, 2°, or 3°), amides, carboxylic acids, aldehydes, ketones, ethers, esters, peroxides, silyls, organosilanes, hydrocarbons, aromatic hydrocarbons, and any combination thereof; polymers; chelating agents like ethylenediamine tetraacetate, diethylenetriaminepentaacetic acid, triglycollamic acid, and a structure comprising a pyrrole ring; and any combination thereof.
• the various fluids described herein may comprise proppants.
• Proppants suitable for use in the present invention may comprise any material suitable for use in subterranean operations. Suitable materials for these proppants include, but are not limited to, sand, bauxite, ceramic materials, glass materials, polymer materials, polytetrafluoroethylene materials, nut shell pieces, cured resinous particulates comprising nut shell pieces, seed shell pieces, cured resinous particulates comprising seed shell pieces, fruit pit pieces, cured resinous particulates comprising fruit pit pieces, wood, composite particulates, and combinations thereof.
• Suitable composite particulates may comprise a binder and a filler material wherein suitable filler materials include silica, alumina, fumed carbon, carbon black, graphite, mica, titanium dioxide, meta-silicate, calcium silicate, kaolin, talc, zirconia, boron, fly ash, hollow glass microspheres, solid glass, and combinations thereof.
• suitable filler materials include silica, alumina, fumed carbon, carbon black, graphite, mica, titanium dioxide, meta-silicate, calcium silicate, kaolin, talc, zirconia, boron, fly ash, hollow glass microspheres, solid glass, and combinations thereof.
• the mean particulate size generally may range from about 2 mesh to about 400 mesh on the U .S. Sieve Series; however, in certain circumstances, other mean particulate sizes may be desired and will be entirely suitable for practice of the present invention .
• preferred mean particulates size distribution ranges are one or more of 6/12, 8/16, 12/20, 16/30, 20/40, 30/50, 40/60, 40/70, or 50/70 mesh .
• the term "particulate,” as used in this disclosure includes all known shapes of materials, including substantially spherical materials, fibrous materials, polygonal materials (such as cubic materials), and combinations thereof.
• fibrous materials that may or may not be used to bear the pressure of a closed fracture, may be included in certain embodiments of the present invention .
• the proppant may be present in the various fluids described herein in an amount in the range of from about 0.5 pounds per gallon ("ppg") to about 30 ppg by volume of the treatment fluid, and encompass any subset therebetween .
• the base fluid of a leading-edge fluid, transition fluid, and/or treatment fluid may comprise oil-based fluids, aqueous-based fluids, aqueous- miscible fluids, water-in-oil emulsions, or oil-in-water emulsions.
• Suitable oil- based fluids may include alkanes, olefins, aromatic organic compounds, cyclic alkanes, paraffins, diesel fluids, mineral oils, desulfurized hydrogenated kerosenes, and any combination thereof.
• Suitable aqueous-based fluids may include fresh water, saltwater (e.g. , water containing one or more salts dissolved therein), brine (e.g. , saturated salt water), seawater, and any combination thereof.
• the water may be from any source, provided that it does not contain components that might adversely affect the stability and/or performance of the leading-edge fluid or the fracturing fluid of the present invention .
• the density of the aqueous base fluid can be adjusted, among other purposes, to provide additional particulate transport and suspension in the leading-edge fluid or the fracturing fluid used in the methods of the present invention .
• the pH of the aqueous base fluid may be adjusted (e.g.
• the pH may be adjusted to a specific level, which may depend on, among other factors, the types of gelling agents, acids, and other additives included in the leading-edge fluid or fracturing fluid .
• a buffer or other pH adjusting agent among other purposes, to reduce the viscosity of the leading-edge fluid or fracturing fluid .
• the pH may be adjusted to a specific level, which may depend on, among other factors, the types of gelling agents, acids, and other additives included in the leading-edge fluid or fracturing fluid .
• Suitable aqueous-miscible fluids may include, but not be limited to, alcohols, e.g. , methanol, ethanol, n-propanol, isopropanol, n-butanol, sec- butanol, isobutanol, and t-butanol; glycerins; glycols, e.g. , polyglycols, propylene glycol, and ethylene glycol ; polyglycol amines; polyols; any derivative thereof; any in combination with salts, e.g.
• Suitable water-in-oil emulsions also known as invert emulsions, may have an oil-to-water ratio from a lower limit of greater than about 50 : 50, 55 : 45, 60 : 40, 65 : 35, 70 : 30, 75 : 25, or 80 : 20 to an upper limit of less than about 100 : 0, 95 : 5, 90 : 10, 85 : 15, 80 : 20, 75 : 25, 70 : 30, or 65 : 35 by volume in the base treatment fluid, and wherein the amount may range from any lower limit to any upper limit and encompass any subset therebetween .
• suitable invert emulsions include those disclosed in U .S. Patent Number 5,905,061, U .S.
• Patent Number 5,977,031, and U .S. Patent Number 6,828,279 each of which are incorporated herein by reference. It should be noted that for water-in-oil and oil-in-water emulsions, any mixture of the above may be used including the water being an aqueous-miscible fluid .
• the base fluid may be foamed, i. e. , may comprise a foaming agent and a gas.
• Suitable foaming agents may be any known foaming agent that does not cause deleterious chemical and/or physical changes to the formation faces and may be used in a sufficient amount to achieve a desired foam, which should be known to one skilled in the art.
• the gas is selected from the group consisting of nitrogen, carbon dioxide, air, methane, helium, argon, and any combination thereof.
• the quality of the foamed fracturing fluid may range from a lower limit of about 5%, 10%, 25%, 40%, 50%, 60%, or 70% gas volume to an upper limit of about 99%, 90%, 80%, 75%, 60%, or 50% gas volume, and wherein the quality of the foamed fracturing fluid may range from any lower limit to any upper limit and encompass any subset therebetween.
• the various fluids described herein can further comprise additives including, but not limited to, salts, weighting agents, inert solids, fluid loss control agents, emulsifiers, dispersion aids, corrosion inhibitors, emulsion thinners, emulsion thickeners, viscosifying agents, high-pressure and high- temperature emulsifier-filtration control agents, surfactants, particulates, proppants, lost circulation materials, foaming agents, gases, pH control additives, breakers, biocides, crosslinkers, stabilizers, scale inhibitors, mutual solvents, oxidizers, reducers, friction reducers, and any combination thereof.
• additives including, but not limited to, salts, weighting agents, inert solids, fluid loss control agents, emulsifiers, dispersion aids, corrosion inhibitors, emulsion thinners, emulsion thickeners, viscosifying agents, high-pressure and high- temperature emulsifier-filtration control agents, surfactants, particulates, prop
• a method of desensitizing a subterranean formation may generally include the steps of: introducing a leading-edge fluid comprising a first base fluid and a first desensitizing agent into at least a portion of the subterranean formation, wherein the first desensitizing agent is present in the first base fluid at a first concentration; and then introducing a treatment fluid comprising a second base fluid and a second desensitizing agent into at least a portion of the subterranean formation, wherein the second desensitizing agent is present in the second base fluid at a second concentration, and wherein the first concentration is higher than the second concentration.
• a method of remedially desensitizing a subterranean formation may generally include the steps of: providing a wellbore penetrating a subterranean formation that comprises a plurality of formation faces, the formation faces having undergone deleterious chemical and/or physical changes; introducing a leading-edge fluid comprising a first base fluid and a first desensitizing agent into at least a portion of the subterranean formation, wherein the first desensitizing agent is present in the first base fluid at a first concentration; and then introducing a treatment fluid comprising a second base fluid and a second desensitizing agent into at least a portion of the subterranean formation, wherein the second desensitizing agent is present in the second base fluid at a second concentration, and wherein the first concentration is higher than the second concentration.
• a method of desensitizing a subterranean formation may generally include the steps of: providing a wellbore penetrating a subterranean formation; introducing a leading-edge fluid comprising a first base fluid and a first desensitizing agent into a first portion of the subterranean formation, wherein the first desensitizing agent is present in the first base fluid at a first concentration; then introducing a treatment fluid comprising a second base fluid and a second desensitizing agent into the first portion of the subterranean formation, wherein the second desensitizing agent is present in the second base fluid at a second concentration, and wherein the first concentration is higher than the second concentration; then diverting fluid flow from the first portion of the subterranean formation to a second portion of the subterranean formation; then introducing a second leading-edge fluid comprising a third base fluid and a third desensitizing agent into the second portion of the subterrane
• Example 1 X-Ray analysis of the field shale samples in South Texas revealed a clay concentration of about 40% to 50% with about 1% of the clay content identified as swelling clay. Based on this information, the following treatment recommendations were made :
• a decrease in permeability of brine after exposure to fresh water comparing with brine pressure after treatment of 1% CLA-WEBTM clay- stabilization additive solution indicates that this 1% CLA-WEBTM clay-stabilization additive concentration was not sufficient for clay protection, which will result in permeability reduction.
• the treatment with 3% CLA-WEBTM clay-stabilization additive solution indicates this CLA-WEBTM clay-stabilization additive concentration was more appropriate to minimize any potential of permeability damage.
• compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values.

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• 2012
  • 2012-08-21 CN CN201280046516.9A patent/CN103842470A/zh active Pending
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