WO2006088603A1 - Agents de deviation solubles - Google Patents

Agents de deviation solubles Download PDF

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Publication number
WO2006088603A1
WO2006088603A1 PCT/US2006/001916 US2006001916W WO2006088603A1 WO 2006088603 A1 WO2006088603 A1 WO 2006088603A1 US 2006001916 W US2006001916 W US 2006001916W WO 2006088603 A1 WO2006088603 A1 WO 2006088603A1
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WO
WIPO (PCT)
Prior art keywords
diverting
fluid
poly
collagen
water
Prior art date
Application number
PCT/US2006/001916
Other languages
English (en)
Inventor
A. Richard Sinclair
Syed Akbar
Patrick R. Okell
Original Assignee
Fairmount Minerals, Ltd.
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Fairmount Minerals, Ltd. filed Critical Fairmount Minerals, Ltd.
Priority to GB0714796A priority Critical patent/GB2437869B/en
Priority to MX2007008850A priority patent/MX2007008850A/es
Priority to CN2006800093692A priority patent/CN101146888B/zh
Priority to CA2595686A priority patent/CA2595686C/fr
Publication of WO2006088603A1 publication Critical patent/WO2006088603A1/fr
Priority to NO20074239A priority patent/NO20074239L/no

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Classifications

    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/80—Compositions for reinforcing fractures, e.g. compositions of proppants used to keep the fractures open
    • C09K8/805—Coated proppants
    • 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
    • C09K8/42—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells
    • C09K8/46—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells containing inorganic binders, e.g. Portland cement
    • C09K8/467—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells containing inorganic binders, e.g. Portland cement containing additives for specific purposes
    • C09K8/487—Fluid loss control additives; Additives for reducing or preventing circulation loss
    • 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
    • C09K8/80—Compositions for reinforcing fractures, e.g. compositions of proppants used to keep the fractures open
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/14—Obtaining from a multiple-zone well
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/25—Methods for stimulating production
    • E21B43/26—Methods for stimulating production by forming crevices or fractures
    • E21B43/261—Separate steps of (1) cementing, plugging or consolidating and (2) fracturing or attacking the formation

Definitions

  • the present invention provides methods and compositions for treating subterranean wells and, more specifically, provides methods and compositions for stimulating multiple intervals in subterranean wells.
  • this invention provides methods and compositions for diverting well treatment fluids into multiple intervals by introducing propping materials coated with a water soluble polymer e.g. collagen, polyvinyl acetate/polyvinyl alcohol, polyalkyl oxides, poly(lactic acid), periodic chart elements of group I or II (alkali metal or alkaline earth metal) silicate polymer, or combinations thereof with materials that are slowly water soluble for use in redirecting the flow of stimulation fluids from a tubing string into the subterranean environment.
  • a water soluble polymer e.g. collagen, polyvinyl acetate/polyvinyl alcohol, polyalkyl oxides, poly(lactic acid), periodic chart elements of group I or II (alkali metal or alkaline earth metal) silicate polymer, or combinations thereof with materials that are slowly water soluble for use in
  • a subterranean formation may include two or more intervals having varying permeability and/or injectivity. Some intervals may possess relatively low injectivity, or ability to accept injected fluids, due to relatively low permeability, high in-situ stress, and/or formation damage. Such intervals may be completed through preparations in a cased wellbore and/or may be completed open hole.
  • such formation intervals may be present in a highly deviated or horizontal section of a wellbore, for example, a lateral open hole section, hi any case, when treating multiple intervals having variable injectivity it is often the case that most, if not all, of the introduced well treatment fluid will be displaced into one, or only a few, of the intervals having the highest injectivity. Even if there is only one interval to be treated, the tendency for the growth of the fracture can be either up or down. This depends on the in situ formation stress and the permeability variation in the formation layer. Below the created fracture can be a water zone. If the created fracture breaks into this zone, the well can be ruined due to excess water and a cut off of the petroleum components of the productive interval. Above the created fracture zone a gas cap may exist which would cause harm to the production of the well because of gas bypassing the liquid petroleum components of the well.
  • Naphthalene (moth balls) and sodium chloride particles have also been described to be useful as effective diverting agents. Naphthalene particles are readily soluble in oil, but melt at about 180 0 F, thereby limiting their use to applications in lower-temperature formations.
  • Sodium chloride having a melting point of about 1,470 0 F, while useful at high temperatures, requires that the well be cleaned with water or dilute acid after the formation has been treated in order to fully remove the sodium chloride particles.
  • sodium chloride cannot be used with hydrofluoric acid to treat subterranean wells due to the formation of insoluble precipitates which can problematically block the wellbore.
  • diversion agents such as polymers, suspended solid materials and/or foam have been employed when simultaneously treating multiple intervals of variable injectivity.
  • diversion agents are typically pumped into a subterranean formation prior to a well treatment fluid in order to seal off intervals of higher permeability and divert the well treatment fluid to intervals of lower permeability.
  • the diverting action of such diversion agents is often difficult to predict and monitor, and may not be successful in diverting treatment fluid into all desired intervals. These problems may be further aggravated in open hole completions, especially in highly deviated completions having large areas of a formation open to the wellbore. The presence of natural fractures may also make diversion more difficult.
  • U.S. Patent No. 3,797,575 assigned to Halliburton discloses diverting-forming additives comprised of relatively water insoluble solid material dissolved in a solvent such as methanol or isopropanol. When the additive is combined with an aqueous treatment fluid, the solid material, dissolved in the additive, is precipitated in the aqueous treating fluid into a finally divided form, which then act as a diverting agent.
  • U.S. Patent No. 3,724,549, also assigned to Halliburton describes a diverting agent material for diverting aqueous treatment fluids into progressively less permeable subterranean formations.
  • the material is composed of a carrier liquid and graded particles of cyclic or linear hydrocarbon resins having between about 20 and about 1,400 carbon atoms, and a melting point of about 200 0 F.
  • This material is described as being largely water and acid insoluble, but soluble in oil, such that the resin can be removed by the produced oil after the completion of the oil treatment operation.
  • the use of radiation-induced polymers as either temporary or permanent diverting agents has been described by Knight, et al. in U.S. Patent No. 3,872,923.
  • temporary or permanent reductions in permeability can be obtained by injecting an aqueous solution containing a water-soluble polymer obtained by radiation-induced polymerization of acrylamide and/or methacrylamide and acrylic acid, methacrylic acid, and/or alkali metal salts of such acids.
  • the resultant polymeric diverting agent has properties, such as temperature and pH stability, so as to effect a reduction of permeability of the porous medium. Permeability within the formation can be restored by subsequent treatment with a chemical to break down the polymer, such as hydrazine hypochlorite solution or strong mineral acids.
  • U.S. Patent Nos. 3,954,629 and 4,005,753 to Scheffel, et al offer polymeric diverting agents, and methods of treating subterranean formations with such polymeric diverting agents, respectively.
  • the polymeric composition is described to comprise solid particles of a homogenous mixture of polyethylene, ethylene-vinyl acetate copolymer, a polyamide, and a softening agent such as long chain aliphatic diamides. These polymeric diverting agents are reported to be suitable for use in subterranean formations where formation temperatures are 350 0 F or greater.
  • the diverting agent is preferably Hansa Yellow G (Fanchon Yellow YH-5707 pigment) or Fast Yellow 4RLF dye, both of which have an azo component and a methylenic component and are further characterized as having a melting point of at least 332.6 °F, a degree of solubility in water at a temperature of water from about 200 to about 425 °F, and a degree of solubility in kerosene at a temperature of from about 200 °F to about 425 °F.
  • Hansa Yellow G Franchon Yellow YH-5707 pigment
  • Fast Yellow 4RLF dye both of which have an azo component and a methylenic component and are further characterized as having a melting point of at least 332.6 °F, a degree of solubility in water at a temperature of water from about 200 to about 425 °F, and a degree of solubility in kerosene at a temperature of from about 200 °F to about 425 °F.
  • TMFUD Technique of Multi-Fracture Fracturing Using a Diverting Agent
  • SPE 30816, pp. 80-86 (1988) the latter of which has shown an average oil production improvement of 15.0 t/d for each well, and a cumulative production improvement of 340.3 x 10 4 tons.
  • a viscoelastic surfactant-based diverting agent for use in acid stimulations has also been described (Alleman, D., et ah, SPE 80222 (2003)), which is a VES gel (polyQuat) characterized by a distinctive vesicle structure stable at high pH and a thermal stability of about 250 °F.
  • This gel-type diversion agent is typically pumped into a subterranean formation prior to a well stimulation fluid in order to seal off intervals of high permeability and divert the well treatment fluid to intervals of low permeability.
  • the present invention provides a method of using particles having a soluble outer coating as diverting agents in subterranean formations.
  • the soluble outer coating will dissolve after a desired period of time at downhole temperatures and pressures in the presence of standard downhole fracturing fluids and breaker compositions.
  • Examples of the soluble outer coating include collagen, poly(alkylene) oxides, poly(lactic acid), polyvinylacetate, polyvinyl alcohol, polyvinylacetate/polyvinylalcohol, polylactone, polyacrylate, latex, polyester, group I or II silicate polymer or mixtures thereof.
  • the present invention provides water soluble polymer coated proppants as diverting agents and methods of using such diverting agents for treating a subterranean formation.
  • the diverting agent together with a carrier liquid is introduced into a subterranean formation.
  • the liquid carrier flows into fractures and/or intervals within the subterranean formation.
  • the fractures or intervals present varying degrees of permeability.
  • the liquid carrier with diverting agent will flow to the most permeable interval first.
  • the temperature of the formation will cause the water soluble polymer coating of the diverting agent to soften and swell, thereby plugging the fracture.
  • a diverting agent suitable for diverting well treatment fluids into a single or a multiple interval wherein the diverting agent is comprised of a particulate substrate and a water-soluble outer layer.
  • water soluble outer layer polymer is exemplified, without limitation, by collagen, poly(alkylene) oxides, poly(lactic acid) polyvinylacetate, polyvinylalcohols, polyvinylacetate/polyvinylalcohol, polymeric lactones, water-soluble acrylics, latex, polyester, group I or II silicate polymer, and admixtures thereof.
  • a diverting agent suitable for diverting well treatment fluids into a single or a multiple interval wherein the diverting agent is comprised of a particulate substrate an intermediate water insoluble layer and a water soluble polymer outer layer.
  • the water soluble outer layer polymer is exemplified, without limitation, by collagen, poly(alkylene) oxides, poly(lactic acid), polyvinylacetate, polyvinylalcohols, polyvinylacetate/polyvinylalcohol, polymeric lactones, water-soluble acrylics, latex, polyester, group I or II silicate polymer and admixtures thereof.
  • the water insoluble intermediate layer is exemplified by phenol-aldehyde novolac polymers and phenol-aldehyde resole polymers.
  • a diverting agent suitable for diverting well treatment fluids into a single or a multiple interval within a wellbore wherein the diverting agent is substantially a water-soluble polymer particle such as a collagen bead or granular particles of poly(alkylene) oxide, poly(lactic acid), polyvinylacetate, polyvinylalcohol, polyvinylacetate/polyvinylalcohol, polymeric lactones, water-soluble acrylics, latex, polyester, group I or II silicate polymer, or mixtures thereof.
  • a method of stimulating individual intervals of a subterranean formation including the steps of introducing a diverting agent having a water-soluble component on its outer layer into an inner pipe of a wellbore in combination with a low viscosity fluid or a fracturing fluid; displacing the diverting agent and fracturing fluid into the subterranean formation, allowing the diverting agent to progressively plug portions of the formation being treated; and repeating the process as necessary, adding the diverting agent to the carrier fluid in slugs during the fracturing operation.
  • FIG. 1 shows an elevational cross-sectional view of a downhole portion of a subterranean formation having a vertical casing and a single treatment interval, wherein variously coated diverting agents are being injected into the hydrocarbon-bearing formation in accordance with an aspect of the present disclosure.
  • FIG. 2 illustrates the elevational cross-sectional view of the subterranean formation of FIG. 1, wherein proppants are being injected into a hydrocarbon-bearing formation having diverting agents of the present invention injected.
  • FIG. 3 shows a well with a vertical casing and multiple treatment intervals 58, 60 and 62 and variously coated diverting agents being injected, in accordance with an aspect of the present disclosure.
  • carrier liquid refers to oil or water based liquids that are capable of moving particles (e.g., proppants) that are in suspension.
  • Low viscosity carrier fluid have less carrying capacity and the particles can be affected by gravity so that they either rise if they are less dense than the liquid or sink if they are more dense than the liquid.
  • High viscosity liquids can carry particles with less settling or rising since the viscosity overcomes gravity effects.
  • crosslinker or "cross-linking agent”, as used herein, refers to those compounds used to covalently modify proteins, such as collagen, and includes both homobifunctional crosslinkers that contain two identical reactive groups, and heterobifunctional crosslinkers which contain two different reactive groups.
  • splitting agent means and refers generally to an agent that functions to prevent, either temporarily or permanently, the flow of a liquid into a particular location, usually located in a subterranean formation, wherein the agent serves to seal the location and thereby cause the liquid to "divert" to a different location.
  • proppant refers to those sized particles that are used in well work-overs and treatments, such as hydraulic fracturing operations, to hold fractures open following the treatment. Such sized particles are often mixed with fracturing fluid(s) to hold fractures open after a hydraulic fracturing treatment or similar downhole well treatment.
  • proppant includes man-made or specially engineered proppants, such as resin-coated sand or high-strength ceramic materials like sintered bauxite.
  • Resin coated proppants are typified by those that are coated with phenol- aldehyde novolac polymers or phenol-aldehyde resole polymers. Typically, but not necessarily, proppant materials are carefully sorted for size and sphericity to provide an efficient conduit for production of fluid from the reservoir to the wellbore.
  • introducing includes pumping, injecting, pouring, releasing, displacing, spotting, circulating, or otherwise placing a fluid or material within a well, wellbore, or subterranean formation using any suitable manner known in the art.
  • combining includes any known suitable methods for admixing, exposing, or otherwise causing two or more materials, compounds, or components to come together in a manner sufficient to cause at least partial reaction or other interaction to occur between the materials, compounds, or components.
  • water soluble refers to resins, polymers, or coatings which are stable (do not dissolve) under ambient, surface conditions, but which become soluble after a given time (usually over several hours or several days) when placed in a subterranean environment.
  • treatment refers to any of numerous operations on or within the downhole well, wellbore, or reservoir, including but not limited to a workover type of treatment, a stimulation type of treatment, such as a hydraulic fracturing treatment or an acid treatment, isolation treatments, control of reservoir fluid treatments, or other remedial types of treatments performed to improve the overall well operation and productivity.
  • a workover type of treatment such as a hydraulic fracturing treatment or an acid treatment
  • isolation treatments such as a hydraulic fracturing treatment or an acid treatment
  • control of reservoir fluid treatments or other remedial types of treatments performed to improve the overall well operation and productivity.
  • stimulation refers to productivity improvement or restoration operations on a well as a result of a hydraulic fracturing, acid fracturing, matrix acidizing, sand treatment, or other type of treatment intended to increase and/or maximize the well's production rate or its longevity, often by creating highly conductive reservoir flow paths.
  • single and multiple intervals of a subterranean formation can be treated or stimulated in stages by successively introducing the diverting agent comprising a particulate substrate and a slowly water-soluble outer coating comprising collagen or a combination of collagen and a slowly water-soluble, non-collagenous material.
  • the invention provides particle compositions comprising soluble material coatings comprising collagen, as well as processes for preparing such compositions. These compositions are useful in subterranean formations for diverting well treatment fluids in a single interval to increase the fracture length or in multiple intervals of a subterranean formation having varying permeability and/or injectivity during a hydraulic fracturing operation.
  • the proppant (or particulate substrate) coated with a slowly water-soluble coating such as a collagen alone or in combination with a non-collagenic water-soluble, plastic coating material acts to divert the fracture, as the coatings on the proppants act as the defining boundaries of the initial fracture.
  • the coating can be removed due to the slow-dissolution characteristics of the coating, leaving standard propping agents with high permeability to flow into the fracture and act as proppants.
  • compositions and methods are described in terms of “comprising” various components or steps, the compositions and methods can also “consist essentially of or “consist of the various components and steps.
  • Particulate material also referred to herein as substrate material, suitable for use with the present invention includes a variety of particulate materials known to be suitable or potentially suitable propping agents which can be employed in downhole operations.
  • the particulate material (or substrate material) which can be used include any propping agent suitable for hydraulic fracturing known in the art. Examples of such particulate materials include, but are not limited to, natural materials, silica proppants, ceramic proppants, metallic proppants, synthetic organic proppants, mixtures thereof, and the like.
  • Natural products suitable for use as proppants include, but are not limited to, nut shells such as walnut, brazil nut, and macadamia nut, as well as fruit pits such as peach pits, apricot pits, olive pits, and any resin impregnated or resin coated version of these.
  • Typical resin coatings or impregnations include bisphenols, bisphenol homopolymers, blends of bisphenol homopolymers with phenol-aldehyde polymer, bisphenol-aldehyde resins and/or polymers, phenol-aldehyde polymers and homopolymers, modified and unmodified resoles, phenolic materials including arylphenols, alkylphenols, alkoxyphenols, and aryloxyphenols, resorcinol resins, epoxy resins, novolak polymer resins, novolak bisphenol-aldehyde polymers, and waxes, as well as the precured or curable versions of such resin coatings.
  • Silica proppants suitable for use with the present invention include, but are not limited to, glass spheres and glass microspheres, glass beads, silica quartz sand, and sands of all types such as white or brown.
  • Typical silica sands suitable for use include Northern White Sands (Fairmount Minerals, Chardon, OH), Ottawa, Jordan, Brady, Hickory, Arizona, St. Peter, Wonowoc, and Chalfort, as well as any resin coated version of these sands.
  • the fibers can be straight, curved, crimped, or spiral shaped, and can be of any grade, such as E-grade, S-grade, and AR-grade.
  • suitable resin-coated silica proppants for use with the present invention include deforniable proppants such as FLEXSAND LSTM and FLEXSAND MSTM (available from BJ Services, Inc., Houston, TX) and Tempered HS®, Tempered LC®, Tempered DC®, and Tempered TF® tempered proppants, all available from Santrol, Fresno, TX.
  • deforniable proppants such as FLEXSAND LSTM and FLEXSAND MSTM (available from BJ Services, Inc., Houston, TX) and Tempered HS®, Tempered LC®, Tempered DC®, and Tempered TF® tempered proppants, all available from Santrol, Fresno, TX.
  • Ceramic proppants suitable for use with the methods of the present invention include, but are not limited to, ceramic beads; spent fluid-cracking catalysts (FCC) such as those described in U.S. Patent No. 6,372,378, which is incorporated herein in its entirety; ultra lightweight porous ceramics; economy lightweight ceramics such as "ECONOPROPTM” (Carbo Ceramics, Inc., Irving, TX); lightweight ceramics such as "CARBOLITETM”; intermediate strength ceramics such as “CARBOPROPTM” (available from Carbo Ceramics, Inc., Irving, TX); high strength ceramics such as "CARBOHSPTM” and “Sintered Bauxite” (Carbo Ceramics, Inc., Irving, TX), and HYPERPROP G2TM, DYNAPROP G2TM, or OPTIPROP G2TM encapsulated, curable ceramic proppants (available from Santrol, Fresno, TX) as well as any resin coated or resin impregnated versions of these, such
  • Metallic proppants suitable for use with the embodiments of the present invention include, but are not limited to, aluminum shot, aluminum pellets, aluminum needles, aluminum wire, iron shot, steel shot, and the like, as well as any resin coated versions of these metallic proppants.
  • Synthetic proppants are also suitable for use with the present invention.
  • suitable synthetic proppants include, but are not limited to, plastic particles or beads, nylon beads, nylon pellets, SDVB (styrene divinyl benzene) beads, carbon fibers such as PANEXTM carbon fibers from Zoltek Corporation (Van Nuys, CA), and resin agglomerate particles similar to "FLEXSAND MSTM” (BJ Services Company, Houston, TX), as well as resin coated versions thereof.
  • soluble materials suitable for use as proppants are also envisioned to be useful with the methods of the present invention.
  • soluble proppants which are placed in the channels of the created perforations include, but are not limited to, marble or limestone chips or any other suitable carbonate particulates.
  • wax, plastic, or resin particles, either coated or uncoated, which are either soluble through contact with a treatment chemical or can melt and flowback from the fracture are suitable for use as proppants with the present invention.
  • propping agents are typically used in concentrations from about 1 to about 18 pounds per gallon (about 120 g/L to about 2,160 g/L) of fracturing fluid composition, but higher or lower concentrations may also be used as required.
  • the particulate substrate suitable for use with the present invention has a particle size in the range of USA Standard Testing screen numbers from about 4 to about 200 (i.e., screen openings of about 0.18 inch to about 0.003 inch). More particularly, particulate substrate sizes suitable for use with the present invention include size ranges from about 4 mesh (4750 microns) to about 200 mesh (75 microns).
  • particulate materials or proppants having size designations of 6/12, 8/16, 12/18, 12/20, 16/20, 16/30, 20/40, 30/50, 40/70 and 70/140, although any desired size distribution can be used, such as 10/40, 14/20, 14/30, 14/40, 18/40, and the like, as well as any combination thereof (e.g., a mixture of 10/40 and 14/40).
  • the preferred mesh size in accordance with the present invention, is 20/40 mesh.
  • the soluble coatings used in accordance with the present invention can be any number of known soluble agents that are slowly soluble in downhole, subterranean formations over a period of time.
  • Soluble polymer materials used in accordance with the present invention should be soluble (that is, capable of dissolving in) in brines, water, oil, organic solvents, acid or acidic media, and/or in fluids having a pH in the range from about 1 to about 14, as well as mixtures thereof under the conditions found in downhole, subterranean formation.
  • the soluble coating is a structural protein such as collagen or atelocollagen, a vegetable protein such as found in wheat, maize, oat or almonds, or a collgen originating from a marine environment.
  • the latter type of collagen can be extracted from fish, algae, plankton, micro-plankton, and the like.
  • the soluble coating is collagen, including Type I collagen, Type II collagen, Type III collagen, Type IV, or Type V collagen, as well as combinations thereof.
  • the soluble coating is a Type I collagen or an atelocollagen.
  • Type I collagens or atelocollagens suitable for use as soluble coatings in accordance with the present invention are those collagens containing at least one hydroxyproline residue.
  • Such Type I collagens or atelocollagens include collagens found in tendons, skin, bone, scar tissue, and the like, such as tropocollagens, as well as products derived from the controlled, enzymatic or chemical reduction of collagen proteins.
  • Such collagens preferably have a molecular weight from about 10,000 Daltons to about 500,000 Daltons, and more preferably from about 100,000 Daltons to about 300,000 Daltons.
  • a preferred Type I collagen suitable for use with the present invention is tropocollagen with a molecular weight of about 250,000 as supplied by Milligans and Higgins, Inc. (Johnstown, NY).
  • Collagens suitable for use within the present invention have Bloom strengths from about 100 psi to about 900 psi, and more preferably from about 300 psi to about 700 psi. Most preferably, collagens suitable for use with the present invention have Bloom strengths from about 400 psi to about 600 psi.
  • Suitable Bloom strengths are about 400 psi, about 410 psi, about 420 psi, about 430 psi, about 440 psi, about 450 psi, about 460 psi, about 470 psi, about 480 psi, about 490 psi, about 500 psi, about 510 psi, about 520 psi, about 530 psi, about 540 psi, about 550 psi, about 560 psi, about 570 psi, about 580 psi, about 590 psi, and about 600 psi, as well as Bloom strengths between any two of these values, e.g., from about 400 psi to about 520 psi, such as 512 psi.
  • Bloom strength refers to the measured value of the strength and/or rigidity of a gelatinous substance, such as collagen, formed by a standard solution of definite concentration that has been retained at a constant temperature for a specified period of time, in accordance with standardized bloom testing procedures, such as BS757:1975, GMIA Testing Standard B5757, International Standard ISO9665 for testing adhesive animal glues, or similar standards as described in "Official Methods of Analysis of AOAC INTERNATIONAL (OMA) ", 17th Edition, Volume II; AOAC International Publications (2003).
  • Bloom strength values are typically given in "pounds per square inch” (psi) or grams, reflecting the force required to depress a chosen area of the surface of the sample a distance of 4 mm.
  • a gel product such as collagen or gelatin, is formed to a specified consistency (e.g., 6 and 2/3 % solution) and kept at a constant temperature in a constant temperature bath at 10 C for 18 hours.
  • a device called a Texture Analyzer e.g., the TA.XT2i Texture Analyzer, Scarsdale, NY
  • a Texture Analyzer measures the weight in grams (or the pressure, in psi) required to depress a standard AOAC® [Associateion of Official Analytical Chemists] gelometer plunger having a sharp, lower edge 4 mm into the gel; alternatively, a BS plunger which has a bottom edge rounded to a radius of 0.4 mm can be used as the plunger. For example, if this procedure requires 200 grams to depress the plunger, then the gelatin has a Bloom strength of 200.
  • Type I collagens suitable for use within the present invention have a sieve distribution /size designation of 6/12, 8/16, 12/18, 12/20, 16/20, 16/30, 20/40, 30/50, 40/70 and 70/140, as well as sieve distributions between any two of these designations, although any desired size distribution can be used, such as 8/40, 10/40, 14/20, 14/30, 14/40, 18/40, and the like, as well as any combination thereof (e.g., a mixture of 10/40 and 14/40).
  • the preferred mesh size, in accordance with the present invention is 8/40 mesh.
  • Collagens as used herein as soluble coatings, can be either cross-linked, uncross-linked, or a combination of both, and the type and degree of cross-linking will depend upon the specific application of the collagen-based soluble coating. There are four fundamental strategies for fixing collagenous materials and materials constructed of processed collagen fibers or purified collagen.
  • the collagen used as a soluble coating is preferably cross-linked using chemical cross-linking techniques. These include, but are not limited to, aldehyde-based cross-linking techniques, polyepoxy compound- based cross-linking techniques, the use of isocyanates, carbodiimide cross- linking, and acyl azide based crosslinking. More preferably, the collagen is cross-linked using aldehyde-based cross- linking techniques, such as by using glutaraldehyde or formaldehyde.
  • Aldehyde-based cross-linking techniques includes those techniques using a reagent containing two reactive aldehyde groups to form covalent cross-links between neighboring collagen proteins, especially the e-amino groups of lysine residues in collagen [Khor, E., Biomaterials, Vol. 18: pp. 95-105 (1997)].
  • Aldehydes suitable for use with the present invention include but are not limited to glutaraldehyde, formaldehyde, propionaldehyde, and butyraldehyde.
  • Polyepoxy based cross-linking techniques and agents include the use of compounds, such as short, branched polymers, terminating in reactive epoxy functionalities.
  • Polyepoxy compounds suitable for use as cross-linking agents in the present invention include but are not limited to glycerol ethers, glycol, and glycerol polyglycidyl ethers.
  • Isocyanates are also suitable for use as cross-linking agents in the present invention.
  • the isocyanates (R-NCO) react with primary amines to form a urea bond (R — H — CO — NH — R); difunctional isocyanates therefore have the ability to cross-link collagen via its lysine side chains.
  • Isocyanates suitable for use as cross-linking agents in the present invention are preferably diisocyanates, including biphenyl diisocyanate, dimethoxy-4,4'-biphenyl diisocyanante, dimethyl-4,4' -biphenyl diisocyanate, l,3-bis(isocyanatomethyl)benzene, phenyl diisocyanate, toluene diisocyanate, tolylene diisocyanate, diisocyanato hexane, diisocyanato octane, diisocyanato butane, isophorone diisocyanante, xylene diisocyanate, hexamethylene diisocyanante, octamethylene diisocyanante, phenylene diisocyanate, and poly(hexamethylene diisocyanate).
  • the isocyanate used as a cross-linking agent of the collagen molecules of the present invention is hex
  • Carbodiimide cross-linking agents and techniques can also be used within the scope of the present invention. These agents react with the carboxyl groups of aspartic and glutamic acid side chains within the collagen to form isoacylurea derivatives/iso-peptide bonds [Khor, E., ibid.].
  • Carbodiimides suitable for use as cross-linking agents with the collagen of the present invention include but are not limited to NjN'-dicyclohexylcarbodiimide (DCC); N 9 N'- diisopropylcarbodiimide (DIC); N,N'-di-tert-butylcarbodiimide; l-ethyl-3-(3- dimethylamino ⁇ ropyl)carbodiimide (EDC; EDAC); water-soluble EDC (WSC); l-tert-butyl-3- ethylcarbodiimide; 1 -(3-dimethylaminopropyl)-3-ethylcarbodiimide; bis(trimethylsilyl)- carbodiimide; l,3-bis(2,2-dimethyl-l,3-dioxolan-4-ylmethyl)carbodiimide (BDDC, as described in U.S.
  • DCC NjN'-dicyclohex
  • Patent No. 5,602,264 N-cyclohexyl-N'-(2-morpholinoethyl) carbodiimide; N,N'- diethylcarbodiimide (DEC); l-cyclohexyl-3-(2-morpholinoethyl)carbodiimide methyl-p- toluenesulfonate [e.g., Sheehan, J.C., et al, J. Org. Chem., Vol. 21: pp. 439-441 (1956)]; oligomeric alkyl cyclohexylcarbodiimides, such as those described by Zhang, et al. [J. Org. Chem., Vol. 69: pp.
  • polymer bound DCC polymer bound EDC, such as cross-linked N-ethyl-N'-(3-dimethylaminopropyl)carbodiimide on JAND AJELTM.
  • EDC cross-linked N-ethyl-N'-(3-dimethylaminopropyl)carbodiimide on JAND AJELTM.
  • N-hydroxysuccinimide (NHS), 1 -hydroxy- 7-azabenzotriazole (HOAt), or similar reagents can be utilized in conjunction with the carbodiimide to minimize internal rearrangement of the activated isoacylurea derivative and provide more efficient cross-linking.
  • acyl azide crosslinking agents produce covalent bonds between the carboxylic acid side chains of aspartic acid and glutamic acids and the ⁇ -amino groups of the lysines of collagen [Petit, H., et al., J. Biomed. Mater. Res., Vol. 24: pp. 179-187 (1990)].
  • the biomaterial is treated with hydrazine to form the corresponding hydrazide; sodium nitride is then added to react with the hydrazide and form the acyl azide.
  • Any number of hydrazines known in the art can be used in this method, including maleimidopropionic acid hydrazide (MPH).
  • Other chemical cross-linking agents suitable for use in the present invention to provide cross-linked collagen molecules which act as soluble coatings on proppant particles include but are not limited to homobifunctional cross-linkers such as BMME, BSOCOES, DSP (a thio- cleavable cross-linker), DSS, EGS, water-soluble EGS, and SATA, as well as heterobifunctional cross-linking agents including GMB, MBS, PMPI, SMCC, SPDP, and MPH (maleimidopropionic acid hydrazide), MCH, EMCH (maleimidocaprionic acid hydrazide), KMUH (N-(k-Maleimidoundecanoic acid)hydrazide), and MPBH (4-(4-N- MaleimidoPhenyl)butyric acid hydrazide), all available from Interchim (Cedex, France).
  • homobifunctional cross-linkers such as BMME, BSOCOES, DSP (a thi
  • Other techniques suitable for crosslinking the collagen fibers for use as soluble proppant coatings include but are not limited to dehydration, UV irradiation at 254 nm, glucose-mediated cross-linking (glycation) in conjunction with UV irradiation, and biological cross-linking.
  • the latter technique includes using natural products such as genipin and its related iridoid compounds which are isolated from the fruits of the gardenia plant (Gardenia jasminoides), which are dialdehydes in aqueous solution and thereby can react with the ⁇ -amino groups on lysine side chains of neighboring collagen molecules to provide a cross-link.
  • NDGA nordihydroguaiaretic acid
  • the slowly water-soluble coatings on the particulate substrates can also be non-collagenic materials such as synthetic polymers that are slowly water soluble.
  • non-collagenic materials include but are not limited to: polyethylene oxides, polypropylene oxides, polycaprolactones; grafts of polyethylene/polypropylene and polycaprolenes; grafts of polyethylene/polypropylene oxides and polycaprolactones; water soluble or water reducible acrylics; water reducible phenoxy resin; latex; polyesters; soluble block copolymers; grafts of polyvinyl alcohol (PVA) and polyvinyl acetates; polyactides and derivatives of polylactic acid; polyglycolic acid (PGA); polyglycoliclactic acid (PGLA).
  • PVA polyvinyl alcohol
  • PGA polyglycoliclactic acid
  • PGLA polyglycoliclactic acid
  • Periodic chart elements of group I or II (alkali metal or alkaline earth metal) silicate polymers e.g. SOLOSILTM (Foseco International, Ltd., Great Britain), a sodium silicate polymer.
  • single or multiple intervals of a subterranean formation may be treated or stimulated in stages by successively introducing diverting agent of the present invention into the formation followed by introduction of well treatment fluid into the formation.
  • wellbore includes cased and/or open hole sections of a well, it being understood that a wellbore may be vertical, horizontal, or a combination thereof.
  • pipe string refers to any conduit suitable for placement and transportation of fluids into a wellbore including, but not limited to, tubing, work string, drill pipe, coil tubing, etc.
  • the disclosed diversion agents and diversion treatment techniques are suitable for use with any type of well treatment fluid including, but not limited to, acid treatments, condensate treatments, hydraulic fracture treatments, and the like. Furthermore, it will be understood that the benefits of the disclosed methods and compositions may be realized with well treatments performed below, at, or above a fracturing pressure of a formation.
  • WELLBORE USE In this aspect of the invention, the use of fully soluble particles in the wellbore (such as collagen or other water soluble polymer plastics or mixtures of these) to divert fluid flow from one zone to another and then dissolve is disclosed.
  • the use of collagen (in both the uncrosslinked and crosslinked form) and soluble plastics are useful in diverting the flow of fluids in the well.
  • These diverting materials should be in the range of 1 to 100 mesh size, preferably 4 to 50 mesh size and can be used in combination with other additives or plastic materials to enhance performance by diverting the flow of fluids from one zone to another.
  • These materials have been used as diverting ball sealers but recent tests have shown that the material could be used as a diverting agent to block fluid from flowing into one zone and into another of either higher pore pressure or lower permeability.
  • the present invention provides a method treating a cased wellbore to divert flow of fluids from one zone to another.
  • the method involves pumping into a wellbore a diverting fluid that is made up of an aqueous carrier liquid having dispersed therein a particulate form of a water soluble polymer and wherein the particulate polymer has a density greater than or less than the density of the carrier liquid.
  • the diverting fluid is pumped into the wellbore the particulate polymer settles into zones of the wellbore and thereby diverts flow of a treating fluid from one zone to another.
  • the treating fluid is diverted or blocked from flowing into a zone of higher pore pressure or lower permeability.
  • the water-soluble particulate polymer is collagen, poly(alkylene) oxide, poly(lactic acid), polyvinylacetate, polyvinylalcohol, polyvinylacetate/polyvinylalcohol, polylactone, polyacrylate, latex, polyester, periodic chart elements of group I or II (alkali metal or alkaline-earth metal) silicate polymer or mixtures thereof.
  • the particulate polymer is present in the carrier liquid in an amount from about 0.001 pounds per gallon to about 10 pounds per gallon of the carrier liquid.
  • the particulate polymer is comprised of varying densities greater or less than the density of the carrier fluid.
  • the carrier liquid is water, brine, aqueous acid solutions, or gelled acid solutions.
  • the use of coated particles of various propping agents can be pumped into the fractured formations to prevent fractures from diverting out of the producing zone.
  • a dense sintered bauxite particle with a soluble or partially soluble coating would fall to the bottom of the fracture and divert the fracture from the lower strata or a water zone.
  • a low- density walnut shell with a soluble or partially soluble coating would tend to rise inside the fracture to divert the fracture from upward growth into a gas or water zone.
  • the coating can be either fully or partially soluble since the proppant will remain in place in the fracture and provide conductivity in the fracture after the frac job is completed. Some of the coating on the proppant should be soluble but a mixture of both soluble and insoluble plastics or collagen is desirable to prevent movement of the propping agent in the fracture.
  • a proppant or propping agent would be coated with a soluble or partially soluble coating - using a collagen and/or polymeric plastic coating material or any mixture of these.
  • the fracture would be diverted by using these soluble coatings on proppants as the defining boundaries of the initial fracture. After the fracturing treatment, the coating would disappear and the previously coated particles would return to normal propping agents, which have high permeability.
  • Coatings on various density proppants could cause the fracture boundaries to be set early in the fracture process since a low viscosity fluid would allow a high density coated proppant to settle or fall inside the fracture to make a lower boundary on the fracture and divert it out from the wellbore to make a longer fracture and increase the productivity of the well.
  • a low density coated proppant would tend to rise to the top part of the growing fracture to form a top boundary and divert the growing fracture away from upper zones that may harm the production of the well. With the fracture contained at top and bottom the fracture could grow outward and a longer contained fracture would improve the well potential productivity.
  • Figure 1 illustrates a well with a vertical cased wellbore section and a single interval formation that is to be treated in accordance with one embodiment of the present disclosure.
  • the well 10 of FIG. 1 has a casing 12 extending from the wellhead 11 for at least a portion of its length and is cemented around the outside with cement sheath 14 to hold the casing 12 in place and isolate the penetrated formation or intervals.
  • the cement sheath 14 extends upward from the bottom of the wellbore in the annulus between the outside of the casing 12 and the inside wall of the wellbore at least to a point above the producing strata/hydrocarbon bearing formation 18.
  • this sheath 14 helps to ensure the integrity of the well-bore (i.e., so it does not collapse), or to isolate specific, different geologic zones (i.e., an oil-bearing zone from an (undesirable) water-producing zone).
  • the wellbore is also optionally equipped with a casing or liner shoe 16 so as to help guide the casing string 12 past ledges or obstacles during its placement in the wellbore.
  • a casing or liner shoe 16 so as to help guide the casing string 12 past ledges or obstacles during its placement in the wellbore.
  • perforations 15 made through casing 12 and the cement sheath 14 by means known to those of ordinary skill in the art.
  • Such means include, but are not limited to, perforation guns, shaped charge devices, and phase charge devices, such as those described in U.S. Patent Nos. 6,755,249, 5,095,099, and 5,816,343; Horizontal Oriented Perforating Systems (HOPS), such as those manufactured by Owen Oil Tubes, Inc. (Ft. Worth, TX); mechanical perforating devices such as laterally movable punches (U.S. Patent No. 2,482,913), needle punch perforators, and toothed wheel perforators such as those described in U.S. Patent No. 4,220,201; and shearable plugs such as described in U.S. Patent No. 4,498,543.
  • the perforations 15 form a flow path for fluid from the formation into the casing 12, and vice- versa.
  • the hydrocarbons flowing out of the producing strata 18 through the perforations 15 and into the interior of the casing 12 can be transported to the surface through a production tubing 20.
  • a production packer, 22, can optionally be installed near the lower end of the production tubing 20 and above the highest perforation 15 in order to achieve a pressure seal between the production tubing 20 and the casing 12.
  • production tubings 20 need not be used, in which case the entire volume of casing 12 is used to conduct the hydrocarbons to the surface of the earth.
  • heavy weight proppant diverting agents 26a and/or light weight proppant diverting agents 26b are used to substantially seal the upper and lower sections of the producing strata 18. This substantial sealing, or border formation, occurs when the temporary diverting agents 26a and/or 26b are introduced into the casing 12 at a predetermined time during the treatment.
  • the diverting agents 26a and/or 26b are introduced into the fluid upstream of the perforated parts of the casing 12, they are carried down the production tubing 20 or casing 12 by the treating fluid 24 flow.
  • the treating fluid 24 arrives at the perforated interval in the casing, it flows outwardly through the perforations 15 and into the strata 18 being treated.
  • the flow of the treating fluid 24 through the perforations 15 carries the temporary diverting agents 26a and/or 26b through the perforations and out into the strata 18.
  • the heavy weight proppant diverting agents 26a having a density greater than that of the treating fluid 24, settle to the bottom of the created fracture (as indicated by the arrows), forming a temporary "lower border" between the fracture and, for example a sand, shale or clay layer 19 or other area to which it is desirable to seal off from the producing strata.
  • light weight proppant diverting agents 26a having a density less than that of treating fluid 24, rise to the top of the created fracture (as indicated by the arrows), thereby forming another temporary "upper border” between the fracture and an undesirable layer, such as a shale or clay band of strata.
  • Figure 2 illustrates the next step of this aspect of the present invention.
  • FIG. 3 illustrates a further embodiment of the present invention.
  • a well 50 having a vertical cased wellbore with a casing 54 extended from the wellhead 52 for at least a portion of the length of the wellbore, and a cement sheath 56 extending upwards from the bottom of the wellbore in the annulus between the outside of the casing 54 and the inside wall of the wellbore, at least to a point above the existing strata, similar to that shown in FIG. 1.
  • FIG. 3 illustrates a fully cased wellbore
  • disclosed treatment methods may be utilized with virtually any type of wellbore completion scenario.
  • the disclosed methods may advantageously be employed to treat well configurations including, but not limited to, vertical wellbores, fully cased wellbores, horizontal wellbores, wellbores having multiple laterals, and wellbores sharing one or more of these characteristics.
  • treatment intervals 58, 60 and 62 represent identified intervals of a subterranean formation that have been identified for treatment. In this regard, any number of intervals or only a portion thereof present in the subterranean formation may be so identified. Alternatively, such intervals may also represent perforated intervals in a cased wellbore. As shown in FIG. 3, perforations 66 extend through casing 54 and cement sheath 56 by means known to those of skill in the art, and in doing so form a flow path for fluid from the formation into the casing 54, and vice- versa.
  • the hydrocarbons flowing out of the producing strata in treatment intervals 58, 60 and 62 through the perforations 66 and into the interior of the casing can be transported to the surface through a production tubing, 64.
  • a production packer 68 can be optionally installed substantially near the lower end of the production tubing 64 and above the highest perforation 66 in order to achieve a pressure seal between the production tubing 64 and the casing 54.
  • Production tubing 64 need not always be used, and in those instances the entire interior volume of casing 54 is used to conduct the hydrocarbons to the surface to wellhead 52.
  • diverting agents 72 are used to substantially seal some of the perforations 66.
  • diverting agents 72 are preferred to be substantially spherical in shape, although other geometries can be used.
  • Using diverting agents 72 of the present invention to plug some of the perforations 66 is accomplished by introducing the diverting agents 72 into the casing 12 at a pre-determined time during the treatment. When the diverting agents 72 are introduced into the fluid upstream of the perforated parts (66) of the casing 12, they are carried down the production tubing 64 or casing 12 by a flowing fracturing fluid 70.
  • the fracturing fluid 70 arrives at the perforated interval in the casing, it flows outwardly through perforations 66 and into the treatment intervals 58, 60, and 62 being treated.
  • the flow of the fracturing fluid 70 through the perforations 66 carries the diverting agents 72 toward the perforations 66, causing them to seat on the perforations 66.
  • diverting agents 72 are held onto the perforations 66 by the fluid pressure differential which exists between the inside of the casing 54 and the treatment intervals 58, 60 and 62 on the outside of casing 54.
  • the diverting agents 72 are preferentially sized to substantially seal the perforations 66 when seated upon them.
  • the seated diverting agents 72 thereby serve to effectively close those perforations 66 until such time as the pressure differential is reversed and the diverting agents released, or the diverting agents 72 dissolve over a period of time due to changes in their environment (e.g., the introduction of water).
  • the diverting agents 72 will tend to first seal the perforations 66 through which the fracturing fluid 70 is flowing most rapidly.
  • the preferential closing of the high flow rate perforations 66 tends to equalize treatment of the treatment intervals 58, 60 and 62 over the entire, perforated interval.
  • the diverting agents 72 should have a density less than the density of the treating fluid 70 in the wellbore at the temperature and pressure conditions encountered in the perforated area downhole.
  • the diverting agent 72 will have at least a substantial outer surface comprised of collagen or a mixture of collagens.
  • the number of diverting agents 72 needed during a workover or well treatment depends upon the objectives and characteristics of the individual well and the stimulation treatment to be used, and can be determined by one skilled in the art.
  • the diverting agent or medium suitable for achieving diversion of fluids into the identified treatment intervals that is employed is the diverting agent of the present invention comprising a particulate substrate and a slowly water-soluble collagen outer layer.
  • a neutrally buoyant variation of this collagen-containing diverting system can be employed, so as to reduce the chance of segregation of the diverting agent and particulate diverting agent carrier fluid.
  • a "neutrally buoyant" diverting system is a system in which a particulate diverting agent is suspended in a carrier fluid having sufficiently close density or specific gravities to result in a mixture in which solid components of the diverting agent do not substantially settle or rise in the system under static conditions.
  • Neutrally buoyant diverting systems may be of particular advantage in highly deviated or horizontal wells, where gravity segregation of a non-neutrally buoyant diverting system may prevent efficient blockage or reduction in permeability of the entire circumference of formation face exposed in the wellbore due, for example, to migration of diverting agent upwards or downwards in the highly deviated or horizontal section of the wellbore.
  • Diverting agents which may be employed include the diverting agents of the present invention, having a slowly water-soluble outer coating, alone or in combination with any diverting agent (e.g., oil soluble, acid soluble, etc.) suitable for diverting subsequent treatment fluids into intervals having lower injectivity.
  • Any diverting agent e.g., oil soluble, acid soluble, etc.
  • One suitable diverting agent in accordance with the present invention is a diverting agent that is substantially collagen.
  • Suitable diverting agents which can be combined with the diverting agent of the present invention include, but are not limited to, benzoic acid flakes, wax (such as "Divert VI” available from BJ Services), cement grade gilsonite or unitaite, polymers (including, but not limited to, natural polymers such as guar, or synthetic polymers such as polyacrylate), rock salt, and the like.
  • Other types of suitable diverting agents that can be employed include, but are not limited to, acid soluble diverting agents such as those described in U.S. Pat. No. 3,353,874, and phtalimide particles such as those as described in U.S. Pat. No. 4,444,264.
  • any type of carrier fluid having a density suitable for forming a neutrally buoyant diverter system may be employed, including natural or synthetic brines (such as KCl water, etc.) and carrier fluids including gelling agents (such as normal or synthetic polymers) or other weighting materials known in the art.
  • Cement grade gilsonite also known as "Uintate" is a natural variety of asphalt that is crushed and sorted into multiple-size particles.
  • This diverting agent composition may be blended at the well site with specific chemically-modified fresh water (water containing for example, about 0.05% to about 1% of a wetting surfactant) to disperse the gilsonite and optionally, a weighting agent (including but not limited to salts such as KCl, NH 4 Cl, NaCl, CaCl 2 , etc.) for density adjustment and/or formation-clay control, and a gelling agent (a polymer such as guar gum, hydroxy propylguar, carboxy methylhydroxy proprylguar, carboxy methyl hydroxyethyl cellulose, xanthan gum, carboxy methyl cellulose, etc.) for viscosity adjustment and/or drag reduction.
  • a weighting agent including but not limited to salts such as KCl, NH 4 Cl, NaCl, CaCl 2 , etc.
  • a gelling agent a polymer such as guar gum, hydroxy propylguar, carboxy methylhydroxy propryl
  • the diverting agent of the present invention is preferably present in the carrier fluid in concentrations of from about 0.001 pounds per gallon to about 10 pounds per gallon of carrier liquid but concentrations outside this range can also be used.
  • concentrations outside this range can also be used.
  • the most preferred concentrations of diverting agents are from about 0.01 to about 6 pounds per gallon of carrier fluid. Diverting agent concentrations of less than about 0.001 pound per gallon will not as readily plug formations when used in carrier fluids volumes which are normally available at an oil well site. A progressively large volume of carrier fluid would be required to create adequate formation plugs at concentrations of less than 0.001 pounds per gallon.
  • the carrier liquid is typically composed of water, brine, aqueous acid solutions, or gelled acid solutions.
  • the acid solutions can be gelled with a celluloses, gums, polysaccharides, polyacrylamides, alkoxylated fatty amines and mixtures thereof.
  • the diverting agent may be added to the carrier fluid as the treatment is started, continuously as the treating fluid is pumped into the well bore or may be added in intervals in the carrier fluid between stages of the treatment. For instance, in acidizing procedures the diverting agent may be added to the acidizing fluid continuously. Thus, the diverting agent will progressively plug portions of the formation being treated, thereby frustrating the tendency of the acid to flow only into the most permeable portions of the formation and, instead, creating an evenly acidized formation.
  • the first stage is followed by a volume of the diverting material composed of a carrier fluid, usually gelled or emulsified water or acid, containing the bridging agent.
  • the diverting agent seals off the portion of the formation penetrated by the first stage of treating fluid.
  • the second stage of treating fluid is then pumped into another portion of the formation. Alternating volumes of treating fluid and diverting material may be continued to provide a uniformly acidized formation.
  • the same technique of continuously introducing the diverting agent in the carrier fluid may be used for fracturing treatments, it is usual for the diverting agent to be added to the carrier fluid in slugs during fracturing operations.
  • a fracturing liquid is known to preferentially flow into the portion of the subterranean formation which most readily accepts the liquid.
  • the bridging agent may be added to the fracturing liquid so that it will plug the already fractured portion of the formation. Because the fracturing fluid is preferentially flowing into the fracture zone, it will carry the bridging agent with it. The fractured zone is thereby plugged and the fracturing fluid is diverted to the most permeable portion of the formation that is still accepting fluids.
  • This method of fracturing and diverting can, in one aspect of the present invention, be repeated to obtain multiple fractures.
  • the diverting agent is removed from the formation by means of sublimation of the diverting agent or by solubilization of the diverting agent by the produced fluids.
  • Increasing formation temperatures result in a greater rate of dissolution or sublimation of the diverting agent. For instance, it has been found that at about 250 0 F, approximately 80 percent by weight of the slightly water-soluble collagen sublimates in 24 hours, while at 300 °F, about 95 percent by weight sublimates in 24 hours, and at a temperature of about 400 °F, about 99% of the slightly water-soluble collagen sublimates/dissolves in about 24 hours. This shows that the rate of sublimation/dissolution of the diverting agent increases with increasing formation temperature.
  • Example 1 Prophetic Example
  • the following prophetic example describes a method of how the soluble coating on the propping agent or agents of the present invention can be used to divert fracture growth and extend the fractures into the productive zone of an oil or gas well.
  • the primary purpose of the soluble coated proppant is to define an upper and lower boundary in the hydraulically generated vertical fracture so that the main direction of growth continues to extend outward in length away from the wellbore. This additional length of the conductive fracture aids in draining additional areas of the productive formation, allowing oil, gas, and/or water recovery production to be improved and greater flow rates to be established as a result of longer fracture length.
  • a fracture injection rate is established with a low viscosity fracturing fluid.
  • a soluble coated proppant such as walnut hulls coated with a cross-linked collagen, bauxite coated with cross-linked collagen, or a combination of both, is added at the blender tub in order to form a slurry in the fracturing fluid.
  • the fracturing fluid containing the soluble coated proppant is pumped downhole.
  • the first part of the slurry enters the initial crack, taking the most fluid, hi doing so, it slowly plugs the borders of the created fracture due to the use of a soluble diverting agent, such as collagen, that slowly softens and swells in the fluid.
  • both the top and the bottom of the fracture need to be contained by the soluble coated proppant, two different proppant densities are preferably used.
  • a high density bauxite particle is coated with a soluble, collagen coating that slowly softens and swells as it falls in the fracture to the bottom of the vertically-created fracture.
  • a second proppant of low density such as a soluble-coated walnut hull, is added to the injection fluid.
  • the low-density, soluble-material coated proppant rises in the vertical fracture and slows down fluid loss and growth in an upward direction.
  • Standard, non-soluble coated proppants such as Ottawa Sand (20/40), ceramic, or any number of resin-coated proppants, are injected into the formation, once the top and bottom growth is diminished. Pumping is continued until the full amount of designated proppant (or proppants) are placed in the created fractures.
  • the well is returned to production, and the soluble collagen-coating on the walnut hulls or bauxite is removed as the water in the formation dissolves the soluble coating on the proppant over time.
  • compositions, methods, and/or processes disclosed and claimed herein can be made and executed without undue experimentation in light of the present disclosure. While the compositions and methods of this invention have been described in terms of preferred embodiments, it will be apparent to those of skill in the art that variations may be applied to the compositions, methods, and/or processes and in the steps or in the sequence of steps of the methods described herein without departing from the concept and scope of the invention. More specifically, it will be apparent that certain agents which are both chemically and physiologically related may be substituted for the agents described herein while the same or similar results would be achieved. All such similar substitutes and modifications apparent to those skilled in the art are deemed to be within the scope and concept of the invention.

Abstract

L'invention concerne des procédés et des compositions permettant de stimuler des intervalles uniques et multiples dans des puits souterrains par déviation des fluides de traitement de puits dans une direction particulière ou dans de multiples intervalles à l'aide d'agents de déviation revêtus solubles dans l'eau. Le revêtement soluble dans l'eau du matériau de déviation est de préférence un polymère de collagène, d'oxyde de poly(alkylène), de poly(acide lactique), de polyvinylacétate, de polyvinylalcool, de polyvinylacétate/polyvinylalcool ou un mélange de ceux-ci appliqué en tant que revêtement sur un nombre quelconque d'agents de soutènement. Le procédé permet de dévier l'écoulement de fluides dans une formation de fond de trou au cours d'un traitement de puits, tel qu'au cours d'une fracturation. Après achèvement d'un traitement tel qu'une stimulation hydraulique, l'agent de déviation soluble peut être dissous et éliminé par le constituant eau de la production du puits.
PCT/US2006/001916 2005-01-21 2006-01-20 Agents de deviation solubles WO2006088603A1 (fr)

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GB0714796A GB2437869B (en) 2005-01-21 2006-01-20 Soluble diverting agents
MX2007008850A MX2007008850A (es) 2005-01-21 2006-01-20 Agentes solubles de derivacion.
CN2006800093692A CN101146888B (zh) 2005-01-21 2006-01-20 可溶性转向剂
CA2595686A CA2595686C (fr) 2005-01-21 2006-01-20 Agents de deviation solubles
NO20074239A NO20074239L (no) 2005-01-21 2007-08-20 Loselige avledningsmidler

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Cited By (10)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2008050286A1 (fr) * 2006-10-24 2008-05-02 Schlumberger Canada Limited Diversion assistée en matériau dégradable
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CA2595686A1 (fr) 2006-08-24
US20060175059A1 (en) 2006-08-10
CN101146888A (zh) 2008-03-19
CN101146888B (zh) 2012-08-08
RU2433157C2 (ru) 2011-11-10
MX2007008850A (es) 2008-01-16
GB0714796D0 (en) 2007-09-12
CA2595686C (fr) 2012-09-18
GB2437869B (en) 2010-06-16
GB2437869A (en) 2007-11-07
NO20074239L (no) 2007-10-15

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