Title:
Method for diversion of hydraulic fracture treatments
Kind Code:
A1


Abstract:
Disclosed herein are methods that include a method for treating a well bore including treating a subterranean formation with a first treatment fluid, wherein the first treatment fluid treats a first treated zone. A degradable diverting material may then be introduced into the subterranean formation. The subterranean formation may be treated 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.



Inventors:
Fulton, Dwight D. (Duncan, OK, US)
Terracina, John (Duncan, OK, US)
Milson, Shane L. (Duncan, OK, US)
Application Number:
12/378935
Publication Date:
08/26/2010
Filing Date:
02/20/2009
Assignee:
Halliburton Energy Services, Inc.
Primary Class:
International Classes:
E21B43/26
View Patent Images:
Related US Applications:



Primary Examiner:
RUNYAN, SILVANA C
Attorney, Agent or Firm:
Robert, Kent A. (P.O. BOX 1431, DUNCAN, OK, 73536, US)
Claims:
What is claimed is:

1. A method for treating a well bore comprising: 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.

2. The method of claim 1 wherein the degradable diverting material comprises at least one substance selected from the group consisting of: a, a chitin, a chitosan; a protein, an aliphatic polyester a poly(lactide), a poly(lactic acid); a poly(glycolide), a poly(ε-caprolactones), a poly(hydroxybutyrate), a poly(anhydride), an aliphatic polycarbonate; a poly(orthoester), a poly(amino acid), a poly(ethylene oxide), a polyphosphazene, and a derivative thereof.

3. The method of claim 1 wherein the degradable diverting material comprises a particulate, wherein the particulate has a diameter of about 100 mesh to about one-quarter of one inch.

4. The method of claim 1 wherein the first treatment fluid comprises at least one fluid selected from the group consisting of: an acid solutions, a scale inhibitor material solutions, a water blocking material solutions, a clay stabilizer solutions, a chelating agent solutions, a surfactant solutions, a fracturing fluid, a paraffin removal solution, an oil based foam, a drilling fluid, and a derivative thereof.

5. The method of claim 1 further comprising: introducing a first treatment fluid to the subterranean formation prior to introducing the degradable diverting material into the subterranean formation.

6. The method of claim 1 further comprising: reintroducing the degradable diverting material into the subterranean formation after the second treatment fluid; and treating the subterranean formation with a third treatment fluid, wherein the degradable diverting material diverts at least a portion of the third treatment fluid.

7. The method of claim 1 further comprising: degrading at least a portion of the degradable diverting material to allow it to be removed from the well bore.

8. 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.

9. The method of claim 8 wherein the degradable diverting material comprises at least one substance selected from the group consisting of: a, a chitin, a chitosan; a protein, an aliphatic polyester a poly(lactide), a poly(lactic acid); a poly(glycolide), a poly(ε-caprolactones), a poly(hydroxybutyrate), a poly(anhydride), an aliphatic polycarbonate; a poly(orthoester), a poly(amino acid), a poly(ethylene oxide), a polyphosphazene, and a derivative thereof.

10. The method of claim 8 wherein the introducing a degradable diverting material into the first perforation tunnel occurs at a matrix flow rate.

11. The method of claim 8 further comprising: introducing the degradable diverting material into the subterranean formation after the second treatment fluid; and treating the subterranean formation with a third treatment fluid, wherein the degradable diverting material diverts at least a portion of the third treatment fluid away from the first treated zone and the second treated zone.

12. The method of claim 8 further comprising: degrading at least a portion of the degradable diverting material to allow it to be removed from the well bore.

13. The method of claim 8 wherein the fracturing the subterranean formation comprises using a jetting tool to create or enhance the first fracture.

14. The method of claim 10 wherein the proppant particulate is substantially coated with a resin or tackifying agent.

15. 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.

16. The method of claim 15 wherein the degradable diverting material comprises at least one substance selected from the group consisting of: a, a chitin, a chitosan; a protein, an aliphatic polyester a poly(lactide), a poly(lactic acid); a poly(glycolide), a poly(ε-caprolactones), a poly(hydroxybutyrate), a poly(anhydride), an aliphatic polycarbonate; a poly(orthoester), a poly(amino acid), a poly(ethylene oxide), a polyphosphazene, and a derivative thereof.

17. The method of claim 16 wherein the degradable diverting material comprises a plasticizer selected from the group defined by the formula: wherein R comprises at least one substance selected from the group consisting of: hydrogen, alkyl, aryl, alkylaryl, acetyl, and a derivative thereof; where R′ comprises at least one substance selected from the group consisting of: hydrogen, alkyl, aryl, alkylaryl, acetyl, and a derivative thereof; wherein R and R′ cannot both be hydrogen; and wherein q is an integer between about 2 and 75.

18. The method of claim 15 further comprising: washing the well bore with a washing fluid.

19. The method of claim 15 further comprising: degrading at least a portion of the degradable diverting material to allow it to be removed from the well bore.

20. The method of claim 15 wherein the fracturing the subterranean formation comprises using a jetting tool to create or enhance the first fracture.

21. The method of claim 15 wherein the fracturing fluid comprises least one substance selected from the group consisting of: a fluid loss control additive, a gelling agent, a viscosifier, a gel stabilizer, a gas, a salt, a pH-adjusting agent, a corrosion inhibitor, a dispersant, a flocculent, an acid, a foaming agent, an antifoaming agent, an H2S scavenger, a lubricant, an oxygen scavenger, a weighting agent, a scale inhibitor, a surfactant, a catalyst, a clay control agent, a biocide, a friction reducer, a particulate, and a derivative thereof.

Description:

BACKGROUND

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.

After a well bore is drilled and completed in a zone of a subterranean formation, it may often be necessary to introduce a treating fluid into the zone. As used herein “zone” simply refers to a portion of the formation and does not imply a particular geological strata or composition. For example, 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. To insure that the producing zone is uniformly treated with the treating fluid, some form of diversion within or among zones in the subterranean formation may be useful. For example, a packer or bridge plug may be used between sets of perforations to divert a treatment fluid between the perforations. In another technique, solid diverting agents may be used, such as proppant particulates, to form bridges or plugs in the casing to divert fluid within or among zones. In another technique, balls may be used to seal off individual perforations to divert fluid within or among zones. Such techniques may be only partially successful in diverting fluid and ensuring uniform distribution of fluid among the various producing zones and perforations within a subterranean formation.

One of many problems in the use of the some or all of the above described procedures may be that 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. For example, a bridge plug generally is removed or drilled out at the end of the operation to allow for production. Similarly, sand plugs or bridges are cleaned out for production; sealing balls are often recovered for production. These may entail additional steps in the treatment process leading to additional time and expenses.

SUMMARY

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.

An embodiment of the present invention provides a method for treating a well bore comprising treating a subterranean formation with a first treatment fluid, wherein 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, wherein the degradable diverting material diverts at least a portion of the second treatment fluid away from the first treated zone.

Another embodiment of 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.

Still another embodiment of 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 features and advantages of the present invention will be apparent to those skilled in the art. While numerous changes may be made by those skilled in the art, such changes are within the spirit of the invention.

BRIEF DESCRIPTION OF THE DRAWINGS

These drawings illustrate certain aspects of some of the embodiments of the present invention, and should not be used to limit or define the invention.

FIG. 1a illustrates a cross-sectional, side view of an exemplary embodiment of the present invention.

FIG. 1b illustrates a cross-sectional, side view of an exemplary alternate embodiment of the present invention where the fracturing treatment is placed using a downhole jetting tool.

FIG. 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.

FIG. 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.

FIG. 3a 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.

FIG. 3b 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 alternate embodiment of the present invention where the fracturing treatment is placed using a downhole jetting tool.

FIG. 4a illustrates a cross-sectional, side view of an exemplary embodiment of the present invention after a second treatment in accordance with an embodiment of the present invention.

FIG. 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 downhole jetting tool.

DESCRIPTION OF THE PREFERRED EMBODIMENTS

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 term “particulate” 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.

The terms “degrade,” “degradation,” “degradable,” and the like when used herein refer 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.

As used herein, the term “treatment,” or “treating,” refers to any subterranean operation that uses a fluid in conjunction with a desired function and/or for a desired purpose. The term “treatment,” or “treating,” does not imply any particular action by the fluid or any particular component thereof.

As used in this disclosure, the term “enhancing” a fracture refers to the extension or enlargement of a natural or previously created fracture in the formation.

“Zone,” as used herein, simply refers to a portion of the formation and does not imply a particular geological strata or composition.

While numerous advantages of the present invention exist, only some may be described or alluded to herein. In an embodiment, 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. In an embodiment, 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.

In an embodiment, 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.

In an embodiment, 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. Polycondensation reactions, ring-opening polymerizations, free radical polymerizations, anionic polymerizations, carbocationic polymerizations, coordinative ring-opening polymerizations, and any other suitable process may prepare such suitable polymers. Specific examples of suitable polymers may include polysaccharides such as dextran or cellulose; chitins; chitosans; proteins; aliphatic polyesters; poly(lactides); poly(glycolides); poly(ε-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:

where n is an integer between 75 and 10,000 and R is selected from the group consisting of hydrogen, alkyl, aryl, alkylaryl, acetyl, heteroatoms, and mixtures thereof.

Of the suitable aliphatic polyesters, poly(lactide) 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:

where m is an integer: 2≦m≦75. Preferably 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. The stereoisomers of lactic acid may be used individually or combined to be used in accordance with the present invention. Additionally, they may be copolymerized with, for example, glycolide or other monomers like ε-caprolactone, 1,5-dioxepan-2-one, trimethylene carbonate, or other suitable monomers to obtain polymers with different properties or degradation times. Additionally, the lactic acid stereoisomers may be modified to be used in the present invention by, inter alia, blending, copolymerizing or otherwise mixing the stereoisomers, blending, copolymerizing or otherwise mixing high and low molecular weight polylactides, or by blending, copolymerizing or otherwise mixing a polylactide with another polyester or polyesters.

Further plasticizers may be used in the compositions and methods of the present invention, and include derivatives of oligomeric lactic acid, selected from the group defined by the formula:

where 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. As used herein the term “derivatives of oligomeric lactic acid” may include derivatives of oligomeric lactide.

The plasticizers may be present in any amount that provides the desired characteristics. For example, the various types of plasticizers discussed herein provide for (a) more effective compatibilization of the melt blend components; (b) improved processing characteristics during the blending and processing steps; and (c) control and regulate the sensitivity and degradation of the polymer by moisture. For pliability, a plasticizer may be present in higher amounts while other characteristics are enhanced by lower amounts. The compositions may allow many of the desirable characteristics of pure nondegradable polymers. In addition, the presence of a plasticizer may facilitate the melt processing, and enhances the degradation rate of the compositions in contact with the environment. The intimately plasticized composition may be processed into a final product in a manner adapted to retain the plasticizer as an intimate dispersion in the polymer for certain properties. These may include: (1) quenching the composition at a rate adapted to retain the plasticizer as an intimate dispersion; (2) melt processing and quenching the composition at a rate adapted to retain the plasticizer as an intimate dispersion; and (3) processing the composition into a final product in a manner adapted to maintain the plasticizer as an intimate dispersion. In certain embodiments, the plasticizers may be at least intimately dispersed within the aliphatic polyester.

An aliphatic polyester may be poly(lactic acid). D-lactide is a dilactone, or cyclic dimer, of D-lactic acid. Similarly, 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. When used alone herein, the term “D,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. Examples of 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).

The physical properties of 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. For example, 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.). The properties of any such suitable degradable polymers (e.g., hydrophobicity, hydrophilicity, rate of degradation, etc.) may be tailored by introducing select functional groups along the polymer chains. For example, poly(phenyl)actide) may degrade at about ⅕th of the rate of racemic poly(lactide) at a pH of about 7.4 at 55° C. One of ordinary skill in the art with the benefit of this disclosure will be able to determine the appropriate functional groups to introduce to and the structure of the polymer chains to achieve the desired physical properties of the degradable polymers.

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° F. to about 150° F., 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.

In an embodiment of the present invention, 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. In an embodiment, the degradable diverting material may be formed into particulates with a size ranging from about 100 mesh to about one-quarter of an inch.

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.

When 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. In acidizing procedures for increasing the porosity of subterranean producing zones, a mixture of hydrochloric and hydrofluoric acids may be utilized.

Another 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.

Another 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. Examples of water blocking materials that may be used 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. Optionally, other components may be included if desired, as recognized by one skilled in the art with the benefit of this disclosure. For example, 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, H2S 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. For example, a gel stabilizer compromising sodium thiosulfate may be included in certain treatment fluids of the present invention. Individuals skilled in the art, with the benefit of this disclosure, will recognize the types of 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. Generally, 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). In certain embodiments, 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. In certain embodiments, 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). In these embodiments, 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. One of ordinary skill in the art, with the benefit of this disclosure, will recognize when such density and/or pH adjustments are appropriate.

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. In 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. In certain embodiments, 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. Examples of suitable polysaccharides include, but are not limited to, guar gums (e.g., hydroxyethyl guar, hydroxypropyl guar, carboxymethyl guar, carboxymethylhydroxyethyl guar, and carboxymethylhydroxypropyl guar (“CMHPG”)), cellulose derivatives (e.g., hydroxyethyl cellulose, carboxyethylcellulose, carboxymethylcellulose, and carboxymethylhydroxyethylcellulose), and combinations thereof. In certain embodiments, the gelling agents comprise an organic carboxylated polymer, such as CMHPG. In certain embodiments, the derivatized cellulose is a cellulose grafted with an allyl or a vinyl monomer, such as those disclosed in U.S. Pat. Nos. 4,982,793; 5,067,565; and 5,122,549, the relevant disclosures of which are incorporated herein by reference. Additionally, 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) may be used.

The gelling agent may be present in the treatment fluids of the present invention in an amount sufficient to provide the desired viscosity. In some embodiments, 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. In 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.

In those embodiments of the present invention wherein it is desirable to crosslink the gelling agent, 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. Examples of 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. These 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 triethanol amine, zirconium lactate triethanolamine, zirconium carbonate, zirconium acetylacetonate, zirconium maleate, zirconium citrate, zirconium diisopropylamine lactate, zirconium glycolate, zirconium triethanol 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. In certain embodiments of the present invention, 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. In some embodiments, 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. The 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.

When included, 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. In certain embodiments, 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. In certain embodiments, 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. One of ordinary skill in the art, with the benefit of this disclosure, will recognize the appropriate amount of 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.

In an embodiment, 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. The term “break” (and its derivatives) as used herein 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.

In some embodiments, 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. 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. In particular embodiments, 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. It should be understood that 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 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. In certain embodiments, 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”) to about 30 ppg by volume of the treatment fluid.

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. In an embodiment, the treatment of the formation may be a fracturing treatment performed with a fracturing fluid. In this embodiment, 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.

In another embodiment, 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.

An exemplary well completed in a subterranean formation is shown in FIG. 1a. As shown, a well bore 10 may penetrate a hydrocarbon-bearing zone 12. Even though FIG. 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. Moreover, as those of ordinary skill in the art will appreciate, exemplary embodiments of the present invention may be applicable for the treatment of both production and injection wells. In the illustrated embodiment, 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 FIG. 1b, 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 to about 1.5 inches in diameter. The perforation tunnels 20 may extend through the casing 16 into the subterranean formation 12 from about 6 inches to about 36 inches. As shown in FIG. 1b, 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. For example, the work string 14 may include, but is not limited to, coiled tubing, jointed pipe, a wireline, or a slickline. A variety of 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.

In an embodiment of the present invention, 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.

In an embodiment, the treatment may be a fracturing operation. In this embodiment, 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 FIG. 2a. The fracturing of the subterranean formation 12 may be accomplished by any suitable methodology. By way of example, 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. In an exemplary embodiment, the fracturing fluid may be introduced to the target zone by pumping the fluid through the casing 16 to the target zone. In certain exemplary embodiments, as shown in FIG. 2b, the fracturing step may utilize a jetting tool 36. By way of example, 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. One example of a suitable fracturing treatment is CobraMaxSM Fracturing Service, available from Halliburton Energy Services, Inc. In another embodiment, 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. In certain exemplary embodiments, the fracturing fluid may comprise a viscosified fluid (e.g., a gel or a crosslinked gel). In certain embodiments, the fracturing fluid further may comprise proppant 32 that is deposited in the one or more fractures 30 to generate propped fractures. In certain exemplary embodiments, 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. By way of example, the proppant may be coated with an Expedite™ resin system, available from Halliburton Energy Services, Inc. In an embodiment shown in FIG. 3a, 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. As shown in FIG. 3b, 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.

Optionally, or in conjunction with, the fracturing treatment, one or more wash fluids may be used to wash the well bore, the perforation tunnels, or both. When used, 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. However, the washing step may be limited in duration in order to ensure that the proppant disposed in a fracture is not displaced. Generally, the wash fluid may be any fluid that does not undesirably react with the other components used or the subterranean formation. For example, the wash fluid may be an aqueous-based fluid (e.g., a brine or produced water), a non-aqueous based fluid (e.g., kerosene, toluene, diesel, or crude oil), or a gas (e.g., nitrogen or carbon dioxide).

In an embodiment, 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. In 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. As such, the initial fracturing treatment in the well bore may not fracture all of the zones desired in the formation, and any subsequent attempts at refracturing may result in the existing fractures taking fluid without opening new fractures. The use of proppant in the fractures may decrease the resistance of the existing fractures to fluid flow as the proppant may create a permeable passage for fluids.

A degradable diverting material may be placed in the subterranean zone or packed into perforation tunnels in the subterranean formation by introducing a carrier fluid containing the degradable diverting materials into the subterranean zone. The degradable diverting material may be carried into the well-bore using a carrier fluid. The carrier fluid may contain a gelling agent or viscosifier as necessary in order to suspend the degradable diverting material in solution. A variety of carrier fluids may be utilized including, but not limited to, fresh water, brines, seawater, formation water, or a combination thereof. In an embodiment, the carrier fluid may be a base fluid used in fracturing treatments, including optional additives commonly used in base fluid compositions. In an embodiment, 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. In an embodiment, 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. Once the degradable diverting material is disposed within the perforation tunnel, 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.

In another embodiment shown in FIGS. 3a and 3b, 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. Methods of forming proppant plugs or bridges are known to those skilled in the arts. In this embodiment, 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.

In an embodiment, the subterranean formation may be treated after the degradable diverting material has been placed in the well bore. As understood by those skilled in the art, 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. In an embodiment, 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. As such, 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.

In an embodiment, the treatment may be a fracturing treatment using a fracturing fluid. An exemplary embodiment of a well bore that may be treated with a fluid after having degradable diverting material being placed therein is shown in FIGS. 4a and 4b. As discussed above, the fracturing of the subterranean formation 12 may be accomplished by any suitable methodology. For example, 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, 42. In another embodiment shown in FIG. 4b, 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, 42. In still another embodiment, a packer (not shown) may be used to pump down through the work string 14 into the formation 12 at a pressure sufficient to create or enhance the one or more fractures 30, 42. A fracture 30, 42 may be formed in the zone or perforation with the least resistance, and the resistance in the treated zone may decrease upon the formation of a fracture. Upon introducing the fracturing fluid into the 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. As similarly shown in FIGS. 3a and 3b, 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 tunnels, 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. For example, in an embodiment in which 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.

After the treating fluid has been used to treat the zone as desired, 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. For example, some of the polymeric compositions useful as degradable diverting materials may degrade in water released from the formation or introduced during a treatment. When the degradable diverting material is self-degradable, the degradable diverting material may at least partially degrade heated in the subterranean zone. If the subterranean formation does not contain water that may be released, an aqueous fluid may be introduced into the formation to aid in degradation of the diverting material. For example, salt water, sea water, or steam may be introduced into the subterranean formation to aid in the degradation of the degradable diverting material. Thus 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. In an embodiment, 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.

In another embodiment, other treatments know to those skilled in the arts may be performed along with those of the disclosed method. For example, 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.

Therefore, the present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present invention. 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. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the element that it introduces. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee.