WO2010094932A1 - Method for diversion of hydraulic fracture treatments - Google Patents
Method for diversion of hydraulic fracture treatments Download PDFInfo
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- WO2010094932A1 WO2010094932A1 PCT/GB2010/000301 GB2010000301W WO2010094932A1 WO 2010094932 A1 WO2010094932 A1 WO 2010094932A1 GB 2010000301 W GB2010000301 W GB 2010000301W WO 2010094932 A1 WO2010094932 A1 WO 2010094932A1
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- fluid
- fracturing
- degradable diverting
- subterranean formation
- diverting material
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- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/60—Compositions for stimulating production by acting on the underground formation
- C09K8/62—Compositions for forming crevices or fractures
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- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/60—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
- C09K8/68—Compositions based on water or polar solvents containing organic compounds
Definitions
- the present invention relates to methods useful in subterranean treatments, and, at least in some embodiments, to methods of diverting fracturing fluids within a subterranean formation.
- zone simply refers to a portion of the formation and does not imply a particular geological strata or composition.
- the producing zone may be stimulated by introducing a hydraulic fracturing fluid into the producing zone to create fractures in the formation, thereby increasing the production of hydrocarbons therefrom.
- some form of diversion within or among zones in the subterranean formation may be useful.
- a packer or bridge plug may be used between sets of perforations to divert a treatment fluid between the perforations
- solid diverting agents such as proppant particulates, to form bridges or plugs in the casing to divert fluid within or among zones.
- balls may be used to seal off individual perforations to divert fluid within or among zones.
- the means of diverting the treatment fluid preferably is subsequently removed from the well bore to allow the maximum flow of produced hydrocarbon from the subterranean zone into the well bore.
- a bridge plug generally is removed or drilled out at the end of the operation to allow for production.
- sand plugs or bridges are cleaned out for poduction; sealing balls are often recovered for production.
- the present invention relates to methods useful in subterranean treatments, and, at least in some embodiments, to methods of diverting fracturing fluids within a subterranean formation.
- the invention provides a method for treating a well bore which method comprises introducing a degradable diverting material into a subterranean formation; and introducing a treatment fluid into the subterranean formation, wherein the degradable diverting material diverts at least a portion of the treatment fluid.
- the invention provides a method for fracturing a subterranean formation comprising: fracturing a portion of a subterranean formation with a fracturing fluid through a first perforation tunnel to create a first fracture; introducing a degradable diverting material into the first perforation tunnel; and fracturing the subterranean formation with the fracturing fluid through a second perforation tunnel to create a second fracture, wherein the degradable diverting material diverts at least a portion of the fracturing fluid away from the first perforation tunnel.
- the present invention provides a method for fracturing a subterranean formation comprising fracturing a subterranean formation with a fracturing fluid through a first perforation tunnel to create a first fracture; introducing a degradable diverting material into the first perforation tunnel at a sub-fracture pressure; and fracturing the subterranean formation with the fracturing fluid through a second perforation tunnel to create a second fracture, wherein the degradable diverting material diverts at least a portion of the fracturing fluid away from the first perforation tunnel.
- the present invention provides a method for fracturing a well bore comprising fracturing a well bore with a fracturing fluid containing a plurality of proppant particulates through a first perforation tunnel to create a first fracture; forming a proppant particulate plug in the well bore, wherein the plug covers the first perforation tunnel; introducing a degradable diverting material into the proppant particulate plug at a sub-fracture pressure; fracturing the subterranean formation with the fracturing fluid through a second perforation tunnel to create a second fracture, wherein the degradable diverting material diverts at least a portion of the fracturing fluid away from the first perforation tunnel covered by the proppant plug.
- the treatment fluids and fracturing fluids used do not comprise cement.
- Figure Ia illustrates a cross-sectional, side view of an exemplary embodiment of the present invention.
- Figure Ib illustrates a cross-sectional, side view of an exemplary alternate embodiment of the present invention where the fracturing treatment is placed using a do wnhole jetting tool.
- Figure 2a illustrates a cross-sectional, side view of an exemplary embodiment of the present invention after a first treatment in accordance with an embodiment of the present invention.
- Figure 2b illustrates a cross-sectional, side view of an exemplary embodiment of the present invention after a first treatment in accordance with an alternate embodiment of the present invention where the fracturing treatment is placed using a downhole jetting tool.
- Figure 3 a illustrates a cross-sectional, side view of an exemplary embodiment of the present invention with a horizontal well bore formed therein after a first treatment in accordance with an embodiment of the present invention.
- Figure 4b illustrates a cross-sectional, side view of an exemplary embodiment of the present invention after a second treatment in accordance with an alternate embodiment of the present invention where the fracturing treatment is placed using a do wnhole jetting tool.
- the present invention relates to methods useful in subterranean treatments, and, at least in some embodiments, to methods of diverting fracturing fluids within a subterranean formation.
- pill as used herein is not limited to any particular shape and is intended to include material particles having the physical shape of platelets, shavings, flakes, ribbons, rods, strips, spheroids, toroids, pellets, tablets or any other physical shape.
- degrade refers to both the two relative cases of hydrolytic degradation that the degradable diverting material may undergo, i.e., heterogeneous (or bulk erosion) and homogeneous (or surface erosion), and any stage of degradation in between these two.
- This degradation can be a result of inter alia, a chemical or thermal reaction or a reaction induced by radiation.
- treatment refers to any subterranean operation that uses a fluid in conjunction with a desired function and/or for a desired purpose.
- treatment does not imply any particular action by the fluid or any particular component thereof.
- enhancing refers to the extension or enlargement of a natural or previously created fracture in the formation.
- Zero simply refers to a portion of the formation and does not imply a particular geological strata or composition.
- the diverting materials of the present invention may advantageously be used to divert a treatment fluid from one zone in a subterranean formation to another, and may then be degraded in the subterranean formation without the need for an additional step of removing the diverting material.
- the treatment may be a fracturing treatment and the use of degradable diverting material may allow for the creation of multiple fractures through several perforations without the need for additional related operations, such as moving the tubing or placing a plug in the well bore.
- a method of the present invention may include treating a subterranean formation with a first treatment fluid, where the first treatment fluid treats a first treated zone; introducing a degradable diverting material into the subterranean formation; and treating the subterranean formation with a second treatment fluid, where the degradable diverting material diverts at least a portion of the second treatment fluid away from the first treated zone.
- the first treatment may be one of several treatments useful in a subterranean environment including a fracturing treatment, and the degradable diverting material may be used to divert fracturing fluid from an existing fracture to another perforation to create or enhance a new fracture.
- a degradable diverting material may be any material capable of degrading in a subterranean environment. Further, the degradable diverting material may be in any form for delivery, including for example, particulates or powders.
- Nonlimiting examples of degradable diverting material that may be used in conjunction with the methods of the present invention may include, but are not limited to, degradable polymers. Suitable examples of degradable polymers that may be used in accordance with the present invention may include, but are not limited to, homopolymers, random, block, graft, and star- and hyper-branched aliphatic polyesters.
- suitable polymers may include polysaccharides such as dextran or cellulose; chitins; chitosans; proteins; aliphatic polyesters; poly(lactides); poly(glycolides); poly(.epsilon.- caprolactones); poly(hydroxybutyrates); poly(anhydrides); aliphatic polycarbonates; poly(orthoesters); poly(amino acids); poly(ethylene oxides); and polyphosphazenes. Of these suitable polymers, aliphatic polyesters and polyanhydrides may be preferred.
- Aliphatic polyesters may degrade chemically, inter alia, by hydrolytic cleavage. Hydrolysis may be catalyzed by either acids or bases. Generally, during the hydrolysis, carboxylic end groups may be formed during chain scission, and this may enhance the rate of further hydrolysis. This mechanism is known in the art as "autocatalysis,” and may make polyesters more bulk eroding.
- Suitable aliphatic polyesters have the general formula of repeating units shown below:
- n is an integer between 75 and 10,000 and R is selected from the group consisting of hydrogen, alkyl, aryl, alkylaryl, acetyl, heteroatoms, and mixtures thereof.
- poly(lactide) may be preferred.
- Poly(lactide) may be synthesized either from lactic acid by a condensation reaction or more commonly by ring-opening polymerization of cyclic lactide monomer. Since both lactic acid and lactide can achieve the same repeating unit, the general term poly(lactic acid) as used herein refers to formula I without any limitation as to how the polymer was made such as from lactides, lactic acid, or oligomers, and without reference to the degree of polymerization or level of plasticization.
- the lactide monomer may generally exists in three different forms: two stereoisomers L- and D-lactide and racemic D,L-lactide (meso-lactide).
- the oligomers of lactic acid, and oligomers of lactide are defined by the formula:
- m is an integer: 2 ⁇ m ⁇ 75.
- m is an integer: 2 ⁇ m ⁇ 10.
- These limits may correspond to number average molecular weights below about 5,400 and below about 720, respectively.
- the chirality of the lactide units may provide a means to adjust, inter alia, degradation rates, as well as physical and mechanical properties.
- Poly(L-lactide), for instance, may be a semicrystalline polymer with a relatively slow hydrolysis rate. This may be desirable in applications of the present invention where a slower degradation of the degradable diverting material may be desired.
- Poly(D,L-lactide) may be a more amorphous polymer with a resultant faster hydrolysis rate. This may be suitable for other applications where a more rapid degradation may be appropriate.
- R is hydrogen, alkyl, aryl, alkylaryl or acetyl, and R is saturated, where R' is hydrogen, alkyl, aryl, alkylaryl or acetyl, and R' is saturated, where R and R' cannot both be H, where q may be an integer: 2 ⁇ q ⁇ 75; and mixtures thereof. Preferably q may be an integer: 2 ⁇ q ⁇ 10.
- derivatives of oligomeric lactic acid may include derivatives of oligomeric lactide.
- An aliphatic polyester may be poly(lactic acid).
- D-lactide is a dilactone, or cyclic dimer, of D-lactic acid.
- L-lactide is a cyclic dimer of L-lactic acid.
- Meso D,L-lactide is a cyclic dimer of D-, and L-lactic acid.
- Racemic D,L-lactide comprises a 50/50 mixture of D-, and L-lactide.
- the term "D 5 L- lactide" is intended to include meso D,L-lactide or racemic D,L-lactide.
- Poly(lactic acid) may be prepared from one or more of the above.
- the chirality of the lactide units may provide a means to adjust degradation rates as well as physical and mechanical properties.
- Poly(L-lactide), for instance, may be a semicrystalline polymer with a relatively slow hydrolysis rate. This may be desirable in applications of the present invention where slow degradation is preferred.
- Poly(D,L-lactide) may be an amorphous polymer with a faster hydrolysis rate. This may be suitable for other applications of the present invention.
- the stereoisomers of lactic acid may be used individually combined or copolymerized in accordance with the present invention.
- the aliphatic polyesters of the present invention may be prepared by substantially any of the conventionally known manufacturing methods such as those disclosed in U.S. Pat. Nos. 6,323,307; 5,216,050; 4,387,769; 3,912,692 and 2,703,316, the relevant disclosures of which are incorporated herein by reference in their entirety.
- Poly(anhydrides) may be another type of suitable degradable polymer useful in the present invention.
- Poly(anhydride) hydrolysis may proceed, inter alia, via free carboxylic acid chain-ends to yield carboxylic acids as final degradation products.
- the erosion time may be varied over a broad range of changes in the polymer backbone.
- suitable poly(anhydrides) may include poly(adipic anhydride), poly(suberic anhydride), poly(sebacic anhydride), and poly(dodecanedioic anhydride).
- Other suitable examples include, but are not limited to, poly(maleic anhydride) and poly(benzoic anhydride).
- degradable polymers may depend on several factors such as the composition of the repeat units, flexibility of the chain, presence of polar groups, molecular mass, degree of branching, crystallinity, orientation, etc.
- short chain branches may reduce the degree of crystallinity of polymers while long chain branches may lower the melt viscosity and impart, inter alia, elongational viscosity with tension-stiffening behavior.
- the properties of the material utilized may be further tailored by blending, and copolymerizing it with another polymer, or by a change in the macromolecular architecture (e.g., hyper-branched polymers, star-shaped, or dendrimers, etc.).
- any such suitable degradable polymers may be tailored by introducing select functional groups along the polymer chains.
- poly(phenyllactide) may degrade at about l/5th of the rate of racemic poly(lactide) at a pH of about 7.4 at 55 0 C.
- One of ordinary skill in the art with the benefit of this disclosure will be able to determine the appropriate functional groups to introduce to and the structure of the polymer chains to achieve the desired physical properties of the degradable polymers.
- degradable material In choosing the appropriate degradable material, one should consider the degradation products that may result. These degradation products should not adversely affect other operations or components.
- the choice of degradable material also may depend, at least in part, on the conditions of the well, e.g., well bore temperature. For instance, lactides have been found to be suitable for lower temperature wells, including those within the range of about 60 0 F (15°C) to about 150 0 F (66°C), and polylactides have been found to be suitable for well bore temperatures above this range. Also, poly(lactic acid) may be suitable for higher temperature wells. Some stereoisomers of poly(lactide) or mixtures of such stereoisomers may be suitable for even higher temperature applications.
- the degradable diverting material may be formed into particles of selected sizes. That is, the degradable diverting material polymer may be degraded in a solvent such as methylene chloride, trichloroethylene, chloroform, cyclohexane, methylene diiodide, mixtures thereof and the like. The solvent may then be removed to form a solid material which can be formed into desired particle sizes. Alternatively, fine powders can be admixed and then granulated or pelletized to form mixtures having any desired particle sizes, hi an embodiment, the degradable diverting material may be formed into particulates with a size ranging from about 100 mesh (0.15 mm) to about one-quarter of an inch (6 mm).
- Examples of treating fluids which can be introduced into the subterranean formation containing the degradable diverting material include, but are not limited to, water based foams, fresh water, salt water, formation water, various aqueous solutions and various hydrocarbon based solutions.
- the aqueous solutions include, but are not limited to, aqueous acid solutions, aqueous scale inhibitor material solutions, aqueous water blocking material solutions, aqueous clay stabilizer solutions, aqueous chelating agent solutions, aqueous surfactant solutions, aqueous fracturing fluids, and aqueous paraffin removal solutions.
- the hydrocarbon based solutions may include, but are not limited to, oil, oil-water emulsions, oil based foams, hydrocarbon scale inhibitor material solutions, hydrocarbon based drilling fluids, hydrocarbon emulsified acidizing fluids, and hydrocarbon based fracturing fluids.
- the aqueous treating fluid is an aqueous acid solution
- the aqueous acid solution may include one or more mineral acids such as hydrochloric acid, hydrofluoric acid, or organic acids such as acetic acid, formic acid and other organic acids or mixtures thereof, hi acidizing procedures for increasing the porosity of subterranean producing zones, a mixture of hydrochloric and hydrofluoric acids may be utilized.
- aqueous treating fluid which may be introduced into the subterranean producing zone in accordance with this invention is a solution of an aqueous scale inhibitor material.
- the aqueous scale inhibitor solution may contain one or more scale inhibitor materials including, but not limited to, tetrasodium ethylenediamine acetate, pentamethylene phosphonate, hexamethylenediamine phosphonate and polyacrylate. These scale inhibitor materials may attach themselves to the subterranean zone surfaces whereby they may inhibit the formation of scale in tubular goods and the like when hydrocarbons and water are produced from the subterranean zone.
- aqueous treating solution which may be utilized is a solution of an aqueous water blocking material.
- the water blocking material solution may contain one or more water blocking materials which may attach themselves to the formation in water producing areas whereby the production of water may be reduced or terminated.
- water blocking materials include, but are not limited to, sodium silicate gels, organic polymers cross-linked with metal cross-linkers and organic polymers cross- linked with organic cross-linkers. Of these, organic polymers cross-linked with organic cross-linkers are preferred.
- Suitable fracturing fluids for use in the present invention generally comprise a base fluid, a suitable gelling agent, and proppant particulates.
- a suitable gelling agent for use in the present invention generally comprise a base fluid, a suitable gelling agent, and proppant particulates.
- other components may be included if desired, as recognized by one skilled in the art with the benefit of this disclosure.
- the fluids used in the present invention optionally may comprise one or more additional additives known in the art, including, but not limited to, fluid loss control additives, gel stabilizers, gas, salts (e.g., KCl), pH-adjusting agents (e.g., buffers), corrosion inhibitors, dispersants, flocculants, acids, foaming agents, antifoaming agents, H 2 S scavengers, lubricants, oxygen scavengers, weighting agents, scale inhibitors, surfactants, catalysts, clay control agents, biocides, friction reducers, particulates (e.g., proppant particulates, gravel particulates), combinations thereof, and the like.
- additional additives including, but not limited to, fluid loss control additives, gel stabilizers, gas, salts (e.g., KCl), pH-adjusting agents (e.g., buffers), corrosion inhibitors, dispersants, flocculants, acids, foaming agents, antifoaming agents, H 2 S s
- a gel stabilizer compromising sodium thiosulfate may be included in certain treatment fluids of the present invention.
- additives that may be suitable for a particular application of the present invention.
- the aqueous base fluid used in the treatment fluids of the present invention may comprise fresh water, saltwater (e.g., water containing one or more salts dissolved therein), brine, seawater, or combinations 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 treatment fluids of the present invention, for example, copper ions, iron ions, or certain types of organic materials (e.g., lignin).
- the density of the aqueous base fluid can be increased, among other purposes, to provide additional particle transport and suspension in the treatment fluids of the present invention.
- the pH of the aqueous base fluid may be adjusted (e.g., by a buffer or other pH adjusting agent), among other purposes, to activate a crosslinking agent, and/or to reduce the viscosity of the treatment fluid (e.g., activate a breaker, deactivate a crosslinking agent).
- the pH may be adjusted to a specific level, which may depend on, among other factors, the types of gelling agents, crosslinking agents, and/or breakers included in the treatment fluid.
- a gelling agent may be utilized in a treatment fluid of the present invention and may comprise any polymeric material capable of increasing the viscosity of an aqueous fluid, hi certain embodiments, the gelling agent may comprise polymers that have at least two molecules that may be capable of forming a crosslink in a crosslinking reaction in the presence of a crosslinking agent, and/or polymers that have at least two molecules that are so crosslinked (i.e., a crosslinked gelling agent).
- the gelling agents may be naturally- occurring, synthetic, or a combination thereof.
- suitable gelling agents may comprise polysaccharides, and derivatives thereof that contain one or more of these monosaccharide units: galactose, mannose, glucoside, glucose, xylose, arabinose, fructose, glucuronic acid, or pyranosyl sulfate.
- the derivatized cellulose is a cellulose grafted with an allyl or a vinyl monomer, such as those disclosed in United States Patent Nos. 4,982,793; 5,067,565; and 5,122,549, the relevant disclosures of which are incorporated herein by reference.
- polymers and copolymers that comprise one or more functional groups e.g., hydroxyl, cis-hydroxyl, carboxylic acids, derivatives of carboxylic acids, sulfate, sulfonate, phosphate, phosphonate, amino, or amide groups
- one or more functional groups e.g., hydroxyl, cis-hydroxyl, carboxylic acids, derivatives of carboxylic acids, sulfate, sulfonate, phosphate, phosphonate, amino, or amide groups
- the gelling agent may be present in the treatment fluids of the present invention in an amount sufficient to provide the desired viscosity.
- the gelling agents may be present in an amount in the range of from about 0.10% to about 4.0% by weight of the treatment fluid, hi certain embodiments, the gelling agents may be present in an amount in the range of from about 0.18% to about 0.72% by weight of the treatment fluid.
- the treatment fluid may comprise one or more of the crosslinking agents.
- the crosslinking agents may comprise a metal ion that is capable of crosslinking at least two molecules of the gelling agent.
- suitable crosslinking agents include, but are not limited to, borate ions, zirconium IV ions, titanium IV ions, aluminum ions, antimony ions, chromium ions, iron ions, copper ions, and zinc ions.
- ions may be provided by providing any compound that is capable of producing one or more of these ions; examples of such compounds include, but are not limited to, boric acid, disodium octaborate tetrahydrate, sodium diborate, pentaborates, ulexite, colemanite, zirconium lactate, zirconium Methanol amine, zirconium lactate triethanolamine, zirconium carbonate, zirconium acetylacetonate, zirconium maleate, zirconium citrate, zirconium diisopropylamine lactate, zirconium glycolate, zirconium Methanol amine glycolate, zirconium lactate glycolate, titanium lactate, titanium malate, titanium citrate, titanium ammonium lactate, titanium triethanolamine, and titanium acetylacetonate, aluminum lactate, aluminum citrate, antimony compounds, chromium compounds, iron compounds, copper compounds, zinc compounds, and combinations thereof.
- boric acid disodium oct
- the crosslinking agent may be formulated to remain inactive until it is "activated" by, among other things, certain conditions in the fluid (e.g., pH, temperature, etc.) and/or contact with some other substance.
- the crosslinking agent may be delayed by encapsulation with a coating (e.g., a porous coating through which the breaker may diffuse slowly, or a degradable coating that degrades downhole) that delays the release of the crosslinking agent until a desired time or place.
- crosslinking agent choice of a particular crosslinking agent will be governed by several considerations that will be recognized by one skilled in the art, including but not limited to the following: the type of gelling agent included, the molecular weight of the gelling agent(s), the pH of the treatment fluid, temperature, and/or the desired time for the crosslinking agent to crosslink the gelling agent molecules.
- suitable crosslinking agents may be present in the treatment fluids of the present invention in an amount sufficient to provide, inter alia, the desired degree of crosslinking between molecules of the gelling agent.
- the crosslinking agent may be present in the treatment fluids of the present invention in an amount in the range of from about 0.0005% to about 0.2% by weight of the treatment fluid.
- the crosslinking agent may be present in the treatment fluids of the present invention in an amount in the range of from about 0.001% to about 0.05% by weight of the treatment fluid.
- crosslinking agent to include in a treatment fluid of the present invention based on, among other things, the temperature conditions of a particular application, the type of gelling agents used, the molecular weight of the gelling agents, the desired degree of viscosification, and/or the pH of the treatment fluid.
- a base fluid may contain a gel breaker, which may be useful for reducing the viscosity of the viscosified fracturing fluid at a specified time.
- a gel breaker may comprise any compound capable of lowering the viscosity of a viscosified fluid.
- break refers to a reduction in the viscosity of the viscosified treatment fluid, e.g., by the breaking or reversing of the crosslinks between polymer molecules or some reduction of the size of the gelling agent polymers. No particular mechanism is implied by the term.
- Suitable gel breaking agents for specific applications and gelled fluids are known to one skilled in the arts. Nonlimiting examples of suitable breakers include oxidizers, peroxides, enzymes, acids, and the like. Some viscosified fluids also may break with sufficient exposure of time and temperature.
- the fracturing fluid or a fluid used to place a gravel pack may comprise a plurality of proppant particulates, inter alia, to stabilize the fractures created or enhanced.
- Particulates suitable for use in the present invention may comprise any material suitable for use in subterranean operations. Suitable materials for these particulates may include, but are not limited to, sand, gravel, 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 (11.2 mm) to about 400 mesh (0.037 mm) on the U.S.
- preferred mean particulates size distribution ranges are one or more of 6/12 (3.35/1.68 mm), 8/16 (2.38/1.2 mm), 12/20 (1.68/0.85 mm), 16/30 (1.2/0.60 mm), 20/40 (0.85/0.42 mm), 30/50 (0.60/0.30 mm), 40/60 (0.42/0.25 mm), 40/70 (0.42/0.21 mm), or 50/70 mesh (0.30/0.21 mm).
- particulate includes all known shapes of materials, including substantially spherical materials, fibrous materials, polygonal materials (such as cubic materials), and mixtures thereof. Moreover, 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. In certain embodiments, the particulates included in the treatment fluids of the present invention may be coated with any suitable resin or tackifying agent known to those of ordinary skill in the art.
- the particulates may be present in the fluids of the present invention in an amount in the range of from about 0.5 pounds per gallon ("ppg") (0.06 kgl “1 ) to about 30 ppg (3.6 kg “1 ) by volume of the treatment fluid.
- ppg pounds per gallon
- a method of the present invention may include treating a subterranean formation with a first treatment fluid, where the first treatment fluid treats a first treated zone; introducing a degradable diverting material into the subterranean formation; and treating the subterranean formation with a second treatment fluid, where the degradable diverting material diverts at least a portion of the second treatment fluid away from the first treated zone.
- the treatment of the formation may be a fracturing treatment performed with a fracturing fluid.
- the degradable diverting material may be used to divert fracturing fluid to untreated perforations in order to create a plurality of fractures in the subterranean formation.
- a method of the present invention may include introducing the treating fluid into the subterranean zone to create a fracture.
- a degradable diverting material may then be packed in the perforation tunnels wherein it may degrade over time.
- a treating fluid may be introduced into the subterranean zone by way of the perforation tunnels, wherein it may be diverted by the degradable diverting material and create another fracture. The degradable diverting material may then degrade when exposed to the conditions in the subterranean zone.
- FIG. 1a An exemplary well completed in a subterranean formation is shown in Figure Ia.
- a well bore 10 may penetrate a hydrocarbon-bearing zone 12.
- Figure 1 depicts the well bore 10 as a vertical well bore
- the methods of the present invention may be suitable for use in deviated, horizontal, or otherwise formed portions of well bores.
- exemplary embodiments of the present invention may be applicable for the treatment of both production and injection wells.
- well bore 10 may be lined with casing 16 that may be cemented to the subterranean formation to create a sheath of cement 18.
- a completed well may include perforations 22 in an interval of the well bore 10.
- the perforations 22 may generally comprise holes or passageways through the casing 16 and the cement 18 into the subterranean formation 12. Perforations 22 may generally be formed using perforating guns, which fire shaped charges from within the well bore 10 to form the perforations 22. In another embodiment shown in Figure Ib, a jetting tool may be used create a perforation by utilizing a focused fluid stream containing an abrasive to erode one or more perforations 22 into the subterranean formation 12. The resulting perforations 22 may include perforation tunnels 20 that extend outward from the casing 16 and cement 18 into the formation 12. In an embodiment, the perforations 22 may generally range in size from about 1/10 of an inch (2.5 mm) to about 1.5 inches (37.5 mm) in diameter.
- a well may also include a work string 14 disposed within the well for disposing tools within the well and delivering fluids or materials to a zone within the subterranean formation 12.
- the work string 14 may include, but is not limited to, coiled tubing, jointed pipe, a wireline, or a slickline.
- tools may be disposed within the well bore 10 using the work string 14 including, but not limited to, packers, plugs, perforating tools, and injection tools, such as jetting tools.
- a variety of treatments may be performed using the degradable diverting materials.
- Suitable subterranean applications may include, but are not limited to, drilling operations, production stimulation operations (e.g., hydraulic fracturing), and well completion operations (e.g., gravel packing or cementing). These treatments may generally be applied to the well bore and formation through the perforations in the casing. Each of these treatments may benefit from the ability to divert a portion of a treatment fluid flow from one or more perforations to other perforations using degradable diverting materials. The diversion of the treatment fluids may help ensure that the treatment fluids are more uniformly distributed among the target perforations or treatment interval than if the degradable diverting materials were not used.
- the treatment may be a fracturing operation.
- one or more fractures may be created or enhanced through the subterranean formation to at least partially increase the effective permeability of the surrounding formation.
- An exemplary well bore with a fracture is shown in Figure 2a.
- the fracturing of the subterranean formation 12 may be accomplished by any suitable methodology.
- a hydraulic-fracturing treatment may be used that includes introducing a fracturing fluid into the target zone in the well bore 10 at a pressure sufficient to create or enhance one or more fractures 30.
- the fracturing fluid may be introduced to the target zone by pumping the fluid through the casing 16 to the target zone.
- the fracturing step may utilize a jetting tool 36.
- the jetting tool 36 may be used to initiate one or more fractures 30 in the subterranean formation 12 through one or more perforations 22 in the casing 16 by way of jetting a fluid through the perforations 22, the perforation tunnels 20, and against the formation 12.
- a fracturing fluid may also be pumped down through the annulus 38 between the work string 14 and the casing 16 and then into the formation 12 at a pressure sufficient to create or enhance the one or more fractures 30.
- the fracturing fluid may be pumped down through the annulus 38 concurrently with the jetting of the fluid.
- fracturing treatment is CobraMax SM Fracturing Service, available from Halliburton Energy Services, Inc.
- a packer (not shown) may be placed at or near one or more perforations 22 in the casing 16.
- a fracturing fluid may then be pumped down through the work string 14 into the formation 12 at a pressure sufficient to create or enhance the one or more fractures 30.
- the fracturing fluid may comprise a viscosified fluid (e.g., a gel or a crosslinked gel).
- the fracturing fluid further may comprise proppant 32 that is deposited in the one or more fractures 30 to generate propped fractures
- the proppant 32 may be coated with a consolidating agent (e.g., a curable resin, a tackifying agent, etc.) so that the coated proppant forms a bondable, permeable mass in the one or more fractures , for example, to mitigate proppant flow back when the well is placed into production.
- a consolidating agent e.g., a curable resin, a tackifying agent, etc.
- the proppant may be coated with an ExpediteTM resin system, available from Halliburton Energy Services, Inc.
- a final slug of proppant may be placed in the well bore to create a proppant plug or bridge 34 across the well bore covering one or more perforations 22.
- a jetting tool may be used to place the proppant plug or bridge 34 across the well bore.
- Proppant plugs may be used in deviated, vertical, or horizontal wells.
- one or more wash fluids may be used to wash the well bore, the perforation tunnels, or both.
- the wash fluids may be introduced into the well bore after the fracturing treatment has ceased and the fracture has been allowed to close.
- the wash fluid may, inter alia, be used to displace any excess proppant in the well bore, the perforation tunnels, or both.
- the washing step may be limited in duration in order to ensure that the proppant disposed in a fracture is not displaced.
- the wash fluid may be any fluid that does not undesirably react with the other components used or the subterranean formation.
- the fracturing of a perforated zone in a well bore may generally treat one or more perforations that have the least resistance to fracturing fluid flow, hi general, a fracture created during a fracturing treatment will initiate in the zone or perforation with the lowest stress and propagate away from the well bore in length and height based on several factors.
- the factors may include, inter alia, stresses in the adjacent zones, fluid leakoff, pump rate, fluid used, and formation temperature.
- a fracture created during a fracturing treatment may not intersect all of the productive zones in a perforated interval.
- the carrier fluid and the degradable diverting material may be combined to form a slurry and pumped into the well bore through the work string or the annular space between the work string and the casing.
- the slurry may be pumped into the well bore below the fracture pressure of the formation and at sub-fracture pumping rates.
- Such a fluid flow rate may be sufficient to force fluid into the path of least resistance (e.g., an existing fracture), but not sufficient to create or enhance a fracture.
- This type of flow rate is commonly referred to as a matrix flow rate
- the slurry containing the degradable diverting material may be pumped at a matrix flowrate through a perforation and into a perforation tunnel.
- the perforation tunnel, the fracture, or both may contain proppant particulates that may act as a filter, screening the degradable diverting material out of the carrier fluid as the slurry passes through. This process may result in a layer or pack of degradable diverting material forming on the proppant particulates, the perforation tunnel walls, or both. Pumping at matrix flow rates may ensure that the degradable diverting material is not carried into the fracture where it may not be capable of diverting a subsequent treatment fluid away from the fracture.
- the resistance to flow through the perforation may increase, causing a back pressure that may be measured at the surface of the well.
- a back pressure at the surface sufficient to allow another fracture to be formed in the subterranean formation, which may be below the fracture pressure of the formation, may indicate that a sufficient plug of degradable diverting material has been placed in the well bore.
- the fracturing treatment may result in the placement of a proppant plug 34 within the well bore, which may cover one or more perforations 22.
- the proppant plug 34 may be disposed in the well bore by introducing a fracturing fluid containing a slug of proppant particulates 32 as the fracturing fluid flow rate approaches a matrix flow rate. When a matrix flow rate is achieved, the proppant 32 may no longer be carried into the fracture, but rather form a plug 34 in the well bore.
- a slurry containing a degradable diverting material may be pumped through the proppant plug into the perforations at a matrix flow rate, resulting in the degradable diverting material accumulating on the proppant plug.
- the resulting layer of degradable diverting material 40 may be able to divert at least a portion of the fluid in the well bore away from the proppant plug and, consequently, the perforations covered by the proppant plug.
- Such diversion may result in a back pressure build up that may be detected at the surface to indicate that the degradable diverting material has been substantially placed in the well bore.
- a proppant plug 34 with a degradable diverting material 40 disposed thereon may be useful in deviated, vertical, and horizontal wells.
- the subterranean formation may be treated after the degradable diverting material has been placed in the well bore.
- any one of a variety of treating fluids may be introduced into a subterranean formation in accordance with this invention. Due to the degradable diverting material being placed in the well bore or a plug, a treating fluid may be at least partially diverted into another area of the formation, which may be one or more perforations that have not had a degradable diverting material placed therein.
- a perforation, a perforation tunnel, or a proppant plug covering one or more perforations that has a degradable diverting material placed therein may have an increased resistance to flow relative to a perforation or perforation tunnel that has not had a degradable diverting material placed therein.
- a treating fluid introduced into a subterranean formation may flow to a new zone or perforation that has the least resistance to flow, treating the new zone.
- the perforations 44 or perforation tunnels 46 that are packed with the degradable diverting material 40 may present a greater resistance to flow than an untreated perforation 22 or perforation tunnel 20, thus directing the fracturing fluid to an untreated perforation 22 or perforation tunnel 20.
- a proppant plug 34 with a degradable diverting material 40 disposed thereon may present a greater resistance to flow than an untreated perforation 22 or perforation tunnel 20, thus directing the fracturing fluid to an untreated perforation 22 or perforation tunnel 20.
- This method may be used to at least partially divert the fracturing fluid into a perforation 22 or perforation tunnel 20 that has not been treated with a degradable diverting material 40.
- the fracturing fluid may then create or enhance a new fracture 42 in the zone of interest.
- the process of treating a zone in a well bore followed by introducing a degradable diverting material into the zone may be repeated as many times as necessary to treat as many zones as desired.
- Each treatment may affect one or more perforations or perforation runnels, and a repetition of the method may be used to ensure that all of the perforations, perforation tunnels, or zones in the well bore are treated.
- Such repetition of the method may be performed without moving the work string or placing a plug in the well bore, increasing efficiency and reducing costs.
- the treatment is a fracturing treatment
- the method may be repeated in order to create a fracture in each perforation in each zone of interest in the subterranean formation.
- the degradable diverting material may at least partially degrade, allowing the formation fluids to be produced.
- the degradable diverting materials may degrade according to a variety of mechanisms depending on factors such as well bore conditions (e.g., temperature, pressure, fluid composition, etc.), and any externally introduced fluids or chemicals.
- some of the polymeric compositions useful as degradable diverting materials may degrade in water released from the formation or introduced during a treatment.
- the degradable diverting material may at least partially degrade heated in the subterranean zone.
- an aqueous fluid may be introduced into the formation to aid in degradation of the diverting material.
- salt water, sea water, or steam may be introduced into the subterranean formation to aid in the degradation of the degradable diverting material.
- the degradable diverting material may be suitable even when non- aqueous treating fluids are utilized or when an aqueous treating fluid has dissipated within the formation or when an aqueous fluid has otherwise been removed from the formation such as by flowback.
- a chemical composition may be introduced into the formation to aid in the degradation of the degradable diverting material. Suitable compositions may include, but are not limited to, acidic fluids, basic fluids, solvents, steam, or a combination thereof.
- a wash fluid may be used to clean the well bore after degradation of the degradable diverting material to clear the well bore of any remaining degradable diverting material or proppant that may impede fluid flow through the well bore.
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Abstract
Description
Claims
Priority Applications (5)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
CA2751528A CA2751528C (en) | 2009-02-20 | 2010-02-19 | Method for diversion of hydraulic fracture treatments |
EP10705910A EP2398867A1 (en) | 2009-02-20 | 2010-02-19 | Method for diversion of hydraulic fracture treatments |
AU2010215333A AU2010215333B2 (en) | 2009-02-20 | 2010-02-19 | Method for diversion of hydraulic fracture treatments |
MX2011008782A MX2011008782A (en) | 2009-02-20 | 2010-02-19 | Method for diversion of hydraulic fracture treatments. |
BRPI1008672A BRPI1008672A2 (en) | 2009-02-20 | 2010-02-19 | method for treating a wellbore. |
Applications Claiming Priority (2)
Application Number | Priority Date | Filing Date | Title |
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US12/378,935 | 2009-02-20 | ||
US12/378,935 US20100212906A1 (en) | 2009-02-20 | 2009-02-20 | Method for diversion of hydraulic fracture treatments |
Publications (1)
Publication Number | Publication Date |
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WO2010094932A1 true WO2010094932A1 (en) | 2010-08-26 |
Family
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Family Applications (1)
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PCT/GB2010/000301 WO2010094932A1 (en) | 2009-02-20 | 2010-02-19 | Method for diversion of hydraulic fracture treatments |
Country Status (7)
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US (1) | US20100212906A1 (en) |
EP (1) | EP2398867A1 (en) |
AU (1) | AU2010215333B2 (en) |
BR (1) | BRPI1008672A2 (en) |
CA (1) | CA2751528C (en) |
MX (1) | MX2011008782A (en) |
WO (1) | WO2010094932A1 (en) |
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Also Published As
Publication number | Publication date |
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AU2010215333A1 (en) | 2011-09-08 |
AU2010215333B2 (en) | 2013-05-02 |
US20100212906A1 (en) | 2010-08-26 |
BRPI1008672A2 (en) | 2016-03-08 |
CA2751528C (en) | 2013-08-13 |
MX2011008782A (en) | 2011-11-04 |
EP2398867A1 (en) | 2011-12-28 |
CA2751528A1 (en) | 2010-08-26 |
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