US20220090475A1

US20220090475A1 - Use of Far-Field Diverting Compositions For Hydraulic Fracturing Treatments

Info

Publication number: US20220090475A1
Application number: US17/482,931
Authority: US
Inventors: Amr Radwan
Original assignee: Xpand Oil and Gas Solutions LLC
Current assignee: Xpand Oil and Gas Solutions LLC
Priority date: 2020-09-24
Filing date: 2021-09-23
Publication date: 2022-03-24
Also published as: WO2022066861A1

Abstract

The present disclosure provides hydraulic fracturing treatment fluid compositions and systems, and methods of hydraulic fracturing hydrocarbon-bearing formations and/or increasing fracture complexity of a fracture network within a subterranean formation.

Description

FIELD

The present disclosure is directed, in part, to far-field diverting compositions and systems and methods of their use in hydraulic fracturing hydrocarbon-bearing formations and/or increasing fracture complexity of a fracture network within a subterranean formation.

BACKGROUND

Subterranean wells (e.g., hydrocarbon producing wells, gas producing wells, oil producing wells, and the like) are often stimulated by hydraulic fracturing treatments. In traditional hydraulic fracturing treatments, a treatment fluid, which may also function simultaneously or subsequently as a carrier fluid, is pumped into a portion of a subterranean formation (which may also be referred to herein as a “formation”) at a rate and pressure sufficient to break down the formation and create one or more fractures therein. Typically, particulate solids, such as graded sand, are suspended in a portion of the treatment fluid and then deposited into the fractures. The particulate solids, known as “proppant particulates” (which may also be referred to herein as “proppants” or “propping particulates”) prevent the fractures from fully closing once the hydraulic pressure is removed. By keeping the fractures from fully closing, the proppant particulates aid in forming conductive paths through which fluids produced from the formation flow, referred to as a “proppant pack.”
Fracture complexity may be enhanced by stimulation (e.g., fracturing) operations to create new or enhance (e.g., elongate or widen) existing fractures. In such cases, the newly formed fractures may remain open without the assistance of proppants or micro-proppant particulates due to shear offset of the formation forming the fractures, or may have included therein proppant particulates, depending on the size of the fracture, to assist in keeping them open after hydraulic pressure is removed. The inclusion of proppant particulates in the fractures, new or natural, may increase the conductivity of a low permeability formation.
In some cases, subterranean treatment operations (e.g., stimulation, proppant placement, and the like), may be supplemented with enhanced hydrocarbon recovery techniques. Such enhanced oil recovery techniques may operate to enhance the conductivity of fractures. One such technique is acidizing, which involves injecting an acid (e.g., hydrochloric acid) into a subterranean formation to etch channels or create microfractures in the face of the formation and/or within an existing macrofracture or microfracture, thereby enhancing the conductivity of the formation. The acid may create a branched, dendritic-like network of channels through which produced fluids may flow. Another such technique is far-field diversion, which involves injecting a degradable and/or dissolvable diverting material (e.g., aliphatic polyesters, phthalic anhydride, and benzoic acid) into a subterranean formation to bridge off and prevent additional fluid flow into higher permeability zones, allowing other well treatment fluids to be injected into other areas of lesser conductivity, and ultimately enhancing the conductivity of the formation. These diverting materials, however, are often expensive and, therefore, are employed at low concentrations. In addition, diverting agents often burden conductivity in productive zones once the face of such zones have been plugged or blocked with a diverter.

SUMMARY

The present disclosure provides methods of hydraulic fracturing a formation, the methods comprising: injecting a far-field diverting composition into the formation, wherein the far-field diverting composition comprises a carrier fluid, a proppant having an average particle size no larger than about 140 mesh, a non-dissolvable diverting micro-particulate having an average particle size no larger than about 200 mesh, and a viscosity enhancer that increases the viscosity of the carrier fluid to at least about 5 cp; and injecting a pad fluid into the formation after injecting the far-field diverting composition into the formation.
The present disclosure also provides methods of hydraulic fracturing a formation, the methods comprising: injecting a pad fluid into the formation; and injecting a far-field diverting composition into the formation after injecting a pad fluid into the formation, wherein the far-field diverting composition comprises a carrier fluid, a proppant having an average particle size no larger than about 140 mesh, a non-dissolvable diverting micro-particulate having an average particle size no larger than about 200 mesh, and a viscosity enhancer that increases the viscosity of the carrier fluid to at least about 5 cp.
The present disclosure also provides methods of diverting fluids in a formation, the methods comprising injecting a far-field diverting composition into the formation, wherein the far-field diverting composition comprises a carrier fluid, a proppant having an average particle size no larger than about 140 mesh, a non-dissolvable diverting micro-particulate having an average particle size no larger than about 200 mesh, and a viscosity enhancer that increases the viscosity of the carrier fluid to at least about 5 cp.
The present disclosure also provides methods of hydraulic fracturing a formation, the methods comprising: injecting a far-field diverting composition into the formation, wherein the far-field diverting composition comprises a carrier fluid, and a non-dissolvable diverting micro-particulate having an average particle size no larger than about 200 mesh; and injecting a pad fluid into the formation after injecting the far-field diverting composition into the formation.
The present disclosure also provides methods of hydraulic fracturing a formation, the methods comprising: injecting a pad fluid into the formation; and injecting a far-field diverting composition into the formation after injecting a pad fluid into the formation, wherein the far-field diverting composition comprises a carrier fluid, and a non-dissolvable diverting micro-particulate having an average particle size no larger than about 200 mesh.
The present disclosure also provides methods of diverting fluids in a formation, the methods comprising injecting a far-field diverting composition into the formation, wherein the far-field diverting composition comprises a carrier fluid, and a non-dissolvable diverting micro-particulate having an average particle size no larger than about 200 mesh.

DESCRIPTION OF EMBODIMENTS

The embodiments described herein relate to far-field diversion and/or increasing fracture complexity of a fracture network within a subterranean formation penetrated by a wellbore. Specifically, the embodiments described herein relate to constraining excessive fracture growth/propagation in an overstimulated/low stress zone to reduce interwell interference while increasing fracture complexity of the created fracture network by diverting treatment fluids from lower-stress regions to higher-stress regions. The flow of hydraulic fracturing treatment fluids may be diverted from a high permeability zone to a low permeability zone within a fracture network within a subterranean formation.
Although some embodiments described herein are illustrated by reference to far-field diversion treatments (e.g., increased fracture complexity), the methods and compositions disclosed herein may be used in any subterranean formation operation that may benefit from their diversion properties. Such treatment operations can include, but are not limited to, a drilling operation, a stimulation operation, a hydraulic stimulation operation, a proppant control operation, a sand control operation, a completion operation, a scale inhibiting operation, a water-blocking operation, a clay stabilizer operation, a fracturing operation, a frac-packing operation, a gravel packing operation, a wellbore strengthening operation, a sag control operation, or any combination thereof. Furthermore, the embodiments described herein may be used in full-scale subterranean operations or as treatment fluids. The subterranean formation may be any source rock comprising organic matter (e.g., oil or natural gas), such as shale, sandstone, or limestone, and may be subsea. Moreover, the methods and compositions described herein may be used in any non-subterranean operation performed in any industry including, but not limited to, oil and gas, mining, and chemical, and the like.
As used herein, the phrase “treatment fluid” refers to a volume of specially prepared fluid (e.g., drilling fluid) placed or circulated in a wellbore. In some embodiments, the volume is a relatively small volume.
As used herein, the term “microfracture” refers to a natural or secondary discontinuity in a portion of a subterranean formation creating a flow channel. As used herein, the term “macrofracture” refers to a discontinuity in a portion of a subterranean formation creating a flow channel, the flow channel generally having a diameter or flow size opening greater than about the size of a microfracture. The microfractures and macrofractures may be channels, perforations, holes, or any other ablation within the formation.
As used herein, “about” means that the recited numerical value is approximate and small variations would not significantly affect the practice of the disclosed embodiments. Where a numerical value is used, unless indicated otherwise by the context, “about” means the numerical value can vary by ±10% and remain within the scope of the disclosed embodiments.
As used herein, “comprising” (and any form of comprising, such as “comprise”, “comprises”, and “comprised”), “having” (and any form of having, such as “have” and “has”), “including” (and any form of including, such as “includes” and “include”), or “containing” (and any form of containing, such as “contains” and “contain”), are inclusive and open-ended and include the options following the terms, and do not exclude additional, unrecited elements or method steps.
The present disclosure provides far-field diverting systems comprising the following components: a carrier fluid, a proppant having an average particle size no larger than about 140 mesh, a non-dissolvable diverting micro-particulate having an average particle size no larger than about 200 mesh, and a viscosity enhancer. In some embodiments, the components of the far-field diverting system are not mixed together, but form a system of one or more containers containing each of the components.
The present disclosure also provides far-field diverting systems comprising the following components: a carrier fluid, and a non-dissolvable diverting micro-particulate having an average particle size no larger than about 200 mesh. In some embodiments, the components of the far-field diverting system are not mixed together, but form a system of one or more containers containing each of the components.
The present disclosure also provides far-field diverting compositions comprising a carrier fluid, a proppant having an average particle size no larger than about 140 mesh, a non-dissolvable diverting micro-particulate having an average particle size no larger than about 200 mesh, and a viscosity enhancer that increases the viscosity of the carrier fluid to at least about 5 cp.
The present disclosure also provides far-field diverting compositions comprising a carrier fluid, and a non-dissolvable diverting micro-particulate having an average particle size no larger than about 200 mesh.
In some embodiments of the far-field diverting systems and/or compositions, the carrier fluid comprises from about 10% to about 99.9% water. In some embodiments of the far-field diverting systems and/or compositions, the carrier fluid comprises greater than about 50% water. In some embodiments of the far-field diverting systems and/or compositions, the carrier fluid comprises greater than about 60% water. In some embodiments of the far-field diverting systems and/or compositions, the carrier fluid comprises greater than about 70% water. In some embodiments of the far-field diverting systems and/or compositions, the carrier fluid comprises greater than about 80% water. In some embodiments of the far-field diverting systems and/or compositions, the carrier fluid comprises greater than about 90% water. In some embodiments of the far-field diverting systems and/or compositions, the carrier fluid comprises greater than about 95% water. In some embodiments of the far-field diverting systems and/or compositions, the carrier fluid comprises 100% water.
Suitable other carrier fluids include, but are not limited to, oil-based fluids, aqueous-based fluids, aqueous-miscible fluids, water-in-oil emulsions, and oil-in-water emulsions, or any combination thereof. Suitable oil-based fluids include, but are not limited to, alkanes, olefins, aromatic organic compounds, cyclic alkanes, paraffins, diesel fluids, mineral oils, and desulfurized hydrogenated kerosenes, or any combination thereof. Suitable aqueous-based fluids include, but are not limited to, fresh water, saltwater (e.g., water containing one or more salts dissolved therein), brine (e.g., saturated saltwater), and seawater, or any ombination thereof. Suitable aqueous-miscible fluids include, but not be limited to, alcohols (e.g., methanol, ethanol, n-propanol, isopropanol, n-butanol, sec-butanol, isobutanol, and t-butanol), glycerins, glycols (e.g., polyglycols, propylene glycol, and ethylene glycol), polyglycol amines, and polyols, or any derivative thereof, any of which can be in combination with salts (e.g., sodium chloride, calcium chloride, calcium bromide, zinc bromide, potassium carbonate, sodium formate, potassium formate, cesium formate, sodium acetate, potassium acetate, calcium acetate, ammonium acetate, ammonium chloride, ammonium bromide, sodium nitrate, potassium nitrate, ammonium nitrate, ammonium sulfate, calcium nitrate, sodium carbonate, and potassium carbonate), and any of which can be in combination with an aqueous-based fluid, or any combination thereof. Suitable water-in-oil and oil-in-water emulsions may comprise any water or oil component described herein. Suitable water-in-oil emulsions, also known as invert emulsions, may have an oil-to-water ratio from a lower limit of greater than about 50:50, greater than about 55:45, greater than about 60:40, greater than about 65:35, greater than about 70:30, greater than about 75:25, or greater than about 80:20 to an upper limit of less than about 100:0, less than about 95:5, less than about 90:10, less than about 85:15, less than about 80:20, less than about 75:25, less than about 70:30, or less than about 65:35 by volume in the base fluid, where the amount may range from any lower limit to any upper limit and encompass any subset therebetween. Suitable oil-in-water emulsions may have a water-to-oil ratio from a lower limit of greater than about 50:50, greater than about 55:45, greater than about 60:40, greater than about 65:35, greater than about 70:30, greater than about 75:25, or greater than about 80:20 to an upper limit of less than about 100:0, less than about 95:5, less than about 90:10, less than about 85:15, less than about 80:20, less than about 75:25, less than about 70:30, or less than about 65:35 by volume in the base fluid, where the amount may range from any lower limit to any upper limit and encompass any subset therebetween. It should be noted that for water-in-oil and oil-in-water emulsions, any mixture of the above may be used including the water being and/or comprising an aqueous-miscible fluid.
In some embodiments of the far-field diverting systems and/or compositions, the proppant is a metal proppant, a sand proppant, a resin coated sand proppant, a ceramic proppant, or a bauxite proppant, or any combination thereof. In some embodiments, the proppant is a metal proppant. In some embodiments, the proppant is a sand proppant. In some embodiments, the proppant is a resin coated sand proppant. In some embodiments, the proppant is a ceramic proppant. In some embodiments, the proppant is a bauxite proppant, such as sintered bauxite.
Additional proppants include, but are not limited to, a glass material, a polymeric material (e.g., ethylene-vinyl acetate or composite materials), a polytetrafluoroethylene material, nutshell pieces, seed shell pieces, fruit pit pieces, wood, or a composite particulate, or any combination thereof. Suitable composite particulates may comprise a binder and a filler material, wherein suitable filler materials include, but are not limited to, silica, alumina, fumed carbon, carbon black, graphite, mica, titanium dioxide, barite, meta-silicate, calcium silicate, kaolin, talc, zirconia, boron, fly ash, a hollow glass microsphere, or solid glass, or any combination thereof. Suitable proppants for use in conjunction with the embodiments described herein may be any known shape of material, including substantially spherical materials, fibrous materials, or polygonal materials (e.g., cubic materials), or any combinations thereof.
In some embodiments of the far-field diverting systems and/or compositions, the proppant has an average particle size no larger than about 140 mesh.
In some embodiments of the far-field diverting systems and/or compositions, the proppant is coated or uncoated, or a combination thereof. In some embodiments of the far-field diverting systems and/or compositions, the proppant is coated. In some embodiments of the far-field diverting systems and/or compositions, the proppant is uncoated.
In some embodiments of the far-field diverting systems, the proppant is in a dry form. In some embodiments of the far-field diverting systems, the proppant is pre-slurried. In some embodiments, the pre-slurried proppant comprises an aqueous or non-aqueous solvent. Suitable examples of non-aqueous solvents include, but are not limited to: an aromatic compound, such as benzene and toluene; an alcohol, such as methanol; an ester; an ether; a ketone, such as acetone; an amine; a nitrated and halogenated hydrocarbon; liquid ammonia; liquid sulfur dioxide; sulfuryl chloride and sulfuryl chloride fluoride; phosphoryl chloride; dinitrogen tetroxide; antimony trichloride; bromine pentafluoride; hydrogen fluoride; pure sulfuric acid; and another inorganic acid.
In some embodiments of the far-field diverting compositions, the concentration of the proppant is from about 0.01 pounds per gallon (lb/gal) to about 5.0 lb/gal, from about 0.02 lb/gal to about 4.0 lb/gal, from about 0.03 lb/gal to about 3.5 lb/gal, from about 0.04 lb/gal to about 3.0 lb/gal, or from about 0.05 lb/gal to about 2.0 lb/gal. In some embodiments, the concentration of the proppant is from about 0.01 lb/gal to about 5.0 lb/gal. In some embodiments, the concentration of the proppant is from about 0.02 lb/gal to about 4.0 lb/gal. In some embodiments, the concentration of the proppant is from about 0.03 lb/gal to about 3.5 lb/gal. In some embodiments, the concentration of the proppant is from about 0.04 lb/gal to about 3.0 lb/gal. In some embodiments, the concentration of the proppant is from about 0.05 lb/gal to about 2.0 lb/gal.
In some embodiments of the far-field diverting systems and/or compositions, the non-dissolvable diverting micro-particulate is silica, a ceramic, or bauxite, or any combination thereof. In some embodiments, the non-dissolvable diverting micro-particulate is silica. In some embodiments, the non-dissolvable diverting micro-particulate is a ceramic. In some embodiments, the non-dissolvable diverting micro-particulate is bauxite.
In some embodiments of the far-field diverting systems and/or compositions, the non-dissolvable diverting micro-particulate has an average particle size no larger than about 200 mesh. In some embodiments of the far-field diverting systems and/or compositions, the non-dissolvable diverting micro-particulate has an average particle size from about 15 microns to about 50 microns.
In some embodiments of the far-field diverting systems and/or compositions, the non-dissolvable diverting particle is sand, a ceramic, or bauxite, or any combination thereof. In some embodiments, the non-dissolvable diverting particle is sand, such as fracturing sand. In some embodiments, the non-dissolvable diverting particle is a ceramic. In some embodiments, the non-dissolvable diverting particle is bauxite, such as sintered bauxite. Additional non-dissolvable diverting particles include, but are not limited to, a glass material, a polymeric material (e.g., ethylene-vinyl acetate or composite materials), a polytetrafluoroethylene material, nutshell pieces, seed shell pieces, fruit pit pieces, wood, or a composite particulate, or any combination thereof. Suitable composite particulates may comprise a binder and a filler material, wherein suitable filler materials include, but are not limited to, silica, alumina, fumed carbon, carbon black, graphite, mica, titanium dioxide, barite, meta-silicate, calcium silicate, kaolin, talc, zirconia, boron, fly ash, a hollow glass microsphere, or solid glass, or any combination thereof. Suitable non-dissolvable diverting particles for use in conjunction with the embodiments described herein may be any known shape of material, including substantially spherical materials, fibrous materials, or polygonal materials (e.g., cubic materials), or any combination thereof.
In some embodiments of the far-field diverting systems, the non-dissolvable diverting micro-particulate is in a dry form. In some embodiments of the far-field diverting systems, the non-dissolvable diverting micro-particulate is pre-slurried. In some embodiments, the pre-slurried non-dissolvable diverting micro-particulate comprises an aqueous or non-aqueous solvent. Suitable examples of non-aqueous solvents include, but are not limited to: an aromatic compound, such as benzene and toluene; an alcohol, such as methanol; an ester; an ether; a ketone, such as acetone; an amine; a nitrated and halogenated hydrocarbon; liquid ammonia; liquid sulfur dioxide; sulfuryl chloride and sulfuryl chloride fluoride; phosphoryl chloride; dinitrogen tetroxide; antimony trichloride; bromine pentafluoride; hydrogen fluoride; pure sulfuric acid; and another inorganic acid.
In some embodiments of the far-field diverting compositions, the concentration of the non-dissolvable diverting micro-particulate is from about 0.005 lb/gal to about 5.0 lb/gal, from about 0.025 lb/gal to about 3.5 lb/gal, or from about 0.05 lb/gal to about 2.0 lb/gal. In some embodiments, the concentration of the non-dissolvable diverting micro-particulate is from about 0.005 lb/gal to about 5.0 lb/gal. In some embodiments, the concentration of the non-dissolvable diverting micro-particulate is from about 0.025 lb/gal to about 3.5 lb/gal. In some embodiments, the concentration of the non-dissolvable diverting micro-particulate is from about 0.05 lb/gal to about 2.0 lb/gal.
In some embodiments of the far-field diverting compositions, the concentration of the non-dissolvable diverting micro-particulate is from about 0.05 lb/gal to about 12.0 lb/gal, from about 0.25 lb/gal to about 8.0 lb/gal, or from about 1.0 lb/gal to about 5.0 lb/gal. In some embodiments, the concentration of the non-dissolvable diverting micro-particulate is from about 0.05 lb/gal to about 12.0 lb/gal. In some embodiments, the concentration of the non-dissolvable diverting micro-particulate is from about 0.25 lb/gal to about 8.0 lb/gal. In some embodiments, the concentration of the non-dissolvable diverting micro-particulate is from about 1.0 lb/gal to about 5.0 lb/gal. In some embodiments, such far-field diverting compositions can lack a proppant and/or a viscosity enhancer.
In some embodiments of the far-field diverting systems and/or compositions, the viscosity enhancer is a viscosifying polymer or a viscoelastic, or any combination thereof. In some embodiments, the viscosity enhancer is a viscosifying polymer. In some embodiments, the viscosity enhancer is a viscoelastic. In some embodiments, the viscosity enhancer is a combination of a viscosifying polymer and a viscoelastic.
The viscosity enhancer increases the viscosity of the carrier fluid to at least about 5 cp. In some embodiments, the viscosity enhancer increases the viscosity of the carrier fluid to about 1-5000 cp, to about 10-4500 cp, to about 20-4000 cp, to about 30-3500 cp, to about 40-3000 cp, to about 50-2500 cp, to about 60-2000 cp, to about 70-1500 cp, to about 80-1000 cp, to about 90-500 cp, to about 100-400 cp, or to about 5-300 cp. In some embodiments, the viscosity enhancer increases the viscosity of the carrier fluid to about 1 cp to about 5000 cp. In some embodiments, the viscosity enhancer increases the viscosity of the carrier fluid to about 10 cp to about 4500 cp. In some embodiments, the viscosity enhancer increases the viscosity of the carrier fluid to about 20 cp to about 4000 cp. In some embodiments, the viscosity enhancer increases the viscosity of the carrier fluid to about 30 cp to about 3500 cp. In some embodiments, the viscosity enhancer increases the viscosity of the carrier fluid to about 40 cp to about 3000 cp. In some embodiments, the viscosity enhancer increases the viscosity of the carrier fluid to about 50 cp to about 2500 cp. In some embodiments, the viscosity enhancer increases the viscosity of the carrier fluid to about 60 cp to about 2000 cp. In some embodiments, the viscosity enhancer increases the viscosity of the carrier fluid to about 70 cp to about 1500 cp. In some embodiments, the viscosity enhancer increases the viscosity of the carrier fluid to about 80 cp to about 1000 cp. In some embodiments, the viscosity enhancer increases the viscosity of the carrier fluid to about 90 cp to about 500 cp. In some embodiments, the viscosity enhancer increases the viscosity of the carrier fluid to about 100 cp to about 400 cp. In some embodiments, the viscosity enhancer increases the viscosity of the carrier fluid to about 5 cp to about 300 cp. In some embodiments, the viscosity enhancer increases the viscosity of the carrier fluid to at least 1 cp. In some embodiments, the viscosity enhancer increases the viscosity of the carrier fluid to at least 5 cp. In some embodiments, the viscosity enhancer increases the viscosity of the carrier fluid to at least 10 cp. In some embodiments, the viscosity enhancer increases the viscosity of the carrier fluid to at least 20 cp. In some embodiments, the viscosity enhancer increases the viscosity of the carrier fluid to at least 30 cp. In some embodiments, the viscosity enhancer increases the viscosity of the carrier fluid to at least 40 cp. In some embodiments, the viscosity enhancer increases the viscosity of the carrier fluid to at least 50 cp. In some embodiments, the viscosity enhancer increases the viscosity of the carrier fluid to at least 60 cp. In some embodiments, the viscosity enhancer increases the viscosity of the carrier fluid to at least 70 cp. In some embodiments, the viscosity enhancer increases the viscosity of the carrier fluid to at least 80 cp. In some embodiments, the viscosity enhancer increases the viscosity of the carrier fluid to at least 90 cp. In some embodiments, the viscosity enhancer increases the viscosity of the carrier fluid to at least 100 cp.
In some embodiments of the far-field diverting systems and/or compositions, the far-field diverting systems and/or compositions further comprise a friction reducer, a gum, a polymer, a second proppant, a scale inhibitor, an oxygen scavenger, an iron controller, a corrosion inhibitor, a breaker, a surfactant, a de-emulsifier, a biocide, an acid, a clay control agent, a wettability modifier, or an H₂S scavenger, or any combination thereof. In some embodiments of the far-field diverting systems and/or compositions, the far-field diverting systems and/or compositions further comprise a friction reducer, a gum, a polymer, a proppant, a viscosity enhancer, a scale inhibitor, an oxygen scavenger, an iron controller, a corrosion inhibitor, a breaker, a surfactant, a de-emulsifier, a biocide, an acid, a clay control agent, a wettability modifier, or an H₂S scavenger, or any combination thereof. In some embodiments, the far-field diverting systems and/or compositions further comprise a friction reducer. In some embodiments, the far-field diverting systems and/or compositions further comprise a gum. In some embodiments, the far-field diverting systems and/or compositions further comprise a polymer. In some embodiments, the far-field diverting systems and/or compositions further comprise a second proppant. In some embodiments, the far-field diverting systems and/or compositions further comprise a scale inhibitor. In some embodiments, the far-field diverting systems and/or compositions further comprise an oxygen scavenger. In some embodiments, the far-field diverting systems and/or compositions further comprise an iron controller. In some embodiments, the far-field diverting systems and/or compositions further comprise a corrosion inhibitor. In some embodiments, the far-field diverting systems and/or compositions further comprise a breaker. In some embodiments, the far-field diverting systems and/or compositions further comprise a surfactant. In some embodiments, the far-field diverting systems and/or compositions further comprise a de-emulsifier. In some embodiments, the far-field diverting systems and/or compositions further comprise a biocide. In some embodiments, the far-field diverting systems and/or compositions further comprise an acid. In some embodiments, the far-field diverting systems and/or compositions further comprise a clay control agent. In some embodiments, the far-field diverting systems and/or compositions further comprise a wettability modifier. In some embodiments, the far-field diverting systems and/or compositions further comprise an H₂S scavenger. In some embodiments, the far-field diverting systems and/or compositions further comprise a proppant. In some embodiments, the far-field diverting systems and/or compositions further comprise a viscosity enhancer.
In some embodiments of the far-field diverting compositions, the total far-field diverting composition is at least about 5 bbl/perforations cluster or at least about 20 bbl/stage. In some embodiments, the total far-field diverting composition is from about 20 bbl/perforations cluster to about 200 bbl/perforations cluster, from about 40 bbl/perforations cluster to about 180 bbl/perforations cluster, from about 60 bbl/perforations cluster to about 160 bbl/perforations cluster, from about 80 bbl/perforations cluster to about 140 bbl/perforations cluster, or from about 100 bbl/perforations cluster to about 120 bbl/perforations cluster. In some embodiments, the total far-field diverting composition is from about 20 bbl/perforations cluster to about 200 bbl/perforations cluster. In some embodiments, the total far-field diverting composition is from about 40 bbl/perforations cluster to about 180 bbl/perforations cluster. In some embodiments, the total far-field diverting composition is from about 60 bbl/perforations cluster to about 160 bbl/perforations cluster. In some embodiments, the total far-field diverting composition is from about 80 bbl/perforations cluster to about 140 bbl/perforations cluster. In some embodiments, the total far-field diverting composition is from about 100 bbl/perforations cluster to about 120 bbl/perforations cluster. In some embodiments, the total far-field diverting composition is from about 100 bbl/stage to about 5,000 bbl/stage, from about 200 bbl/stage to about 4,000 bbl/stage, from about 300 bbl/stage to about 3,000 bbl/stage, from about 400 bbl/stage to about 2,000 bbl/stage, or from about 500 bbl/stage to about 1,000 bbl/stage. In some embodiments, the total far-field diverting composition is from about 100 bbl/stage to about 5,000 bbl/stage. In some embodiments, the total far-field diverting composition is from about 200 bbl/stage to about 4,000 bbl/stage. In some embodiments, the total far-field diverting composition is from about 300 bbl/stage to about 3,000 bbl/stage. In some embodiments, the total far-field diverting composition is from about 400 bbl/stage to about 2,000 bbl/stage. In some embodiments, the total far-field diverting composition is from about 500 bbl/stage to about 1,000 bbl/stage.
In some embodiments of the far-field diverting compositions, the total far-field diverting composition is at least about 50 lb/perforations cluster or at least about 50 lb/stage. In some embodiments, the total far-field diverting composition is from about 50 lb/perforations cluster to about 2,000 lb/perforations cluster, from about 100 lb/perforations cluster to about 1500 lb/perforations cluster, from about 250 lb/perforations cluster to about 1,000 lb/perforations cluster, from about 400 lb/perforations cluster to about 800 lb/perforations cluster, or from about 500 lb/perforations cluster to about 600 lb/perforations cluster. In some embodiments, the total far-field diverting composition is from about 50 lb/perforations cluster to about 2,000 lb/perforations cluster. In some embodiments, the total far-field diverting composition is from about 100 lb/perforations cluster to about 1500 lb/perforations cluster. In some embodiments, the total far-field diverting composition is from about 250 lb/perforations cluster to about 1,000 lb/perforations cluster. In some embodiments, the total far-field diverting composition is from about 400 lb/perforations cluster to about 800 lb/perforations cluster. In some embodiments, the total far-field diverting composition is from about 500 lb/perforations cluster to about 600 lb/perforations cluster. In some embodiments, the total far-field diverting composition is from about 500 lb/stage to about 20,000 lb/stage, from about 1,000 lb/stage to about 15,000 lb/stage, from about 2,500 lb/stage to about 10,000 lb/stage, from about 5,000 lb/stage to about 7,500 lb/stage, or from about 6,000 lb/stage to about 7,000 lb/stage. In some embodiments, the total far-field diverting composition is from about 500 lb/stage to about 20,000 lb/stage. In some embodiments, the total far-field diverting composition is from about 1,000 lb/stage to about 15,000 lb/stage. In some embodiments, the total far-field diverting composition is from about 2,500 lb/stage to about 10,000 lb/stage. In some embodiments, the total far-field diverting composition is from about 5,000 lb/stage to about 7,500 lb/stage. In some embodiments, the total far-field diverting composition is from about 6,000 lb/stage to about 7,000 lb/stage. In some embodiments, such far-field diverting compositions can lack a proppant and/or a viscosity enhancer.
The present disclosure also provides methods of preparing the far-field diverting compositions described herein. In some embodiments, the far-field diverting compositions described herein are prepared by mixing the carrier fluid, the proppant having an average particle size no larger than about 140 mesh, the non-dissolvable diverting micro-particulate having an average particle size no larger than about 200 mesh, and the viscosity enhancer. In some embodiments, the far-field diverting compositions described herein are prepared by mixing the carrier fluid and the non-dissolvable diverting micro-particulate having an average particle size no larger than about 200 mesh.
The present disclosure also provides methods of hydraulic fracturing a formation, the methods comprising: injecting a far-field diverting composition into the formation, wherein the far-field diverting composition comprises a carrier fluid, a proppant having an average particle size no larger than about 140 mesh, a non-dissolvable diverting micro-particulate having an average particle size no larger than about 200 mesh, and a viscosity enhancer that increases the viscosity of the carrier fluid to at least about 5 cp; and injecting a pad fluid into the formation after injecting the far-field diverting composition into the formation. The far-field diverting composition injected into the formation can be any of the far-field diverting compositions described herein. In some embodiments, the formation is a hydrocarbon-bearing formation.
The present disclosure also provides methods of hydraulic fracturing a formation, the methods comprising: injecting a pad fluid into the formation; and injecting a far-field diverting composition into the formation after injecting a pad fluid into the formation, wherein the far-field diverting composition comprises a carrier fluid, a proppant having an average particle size no larger than about 140 mesh, a non-dissolvable diverting micro-particulate having an average particle size no larger than about 200 mesh, and a viscosity enhancer that increases the viscosity of the carrier fluid to at least about 5 cp. The far-field diverting composition injected into the formation can be any of the far-field diverting compositions described herein. In some embodiments, the method further comprises injecting a proppant-laden slurry into the formation after injecting the far-field diverting composition into the formation. In some embodiments, the far-field diverting composition is injected into the formation prior to or at about the same time as injecting a proppant-laden slurry. In any of the embodiments described herein, the far-field diverting composition can be injected into the formation at any stage during the hydraulic fracturing treatment and prior to injecting at least 90% of a proppant-laden slurry into the formation. In some embodiments, the formation is a hydrocarbon-bearing formation.
In any of the embodiments described herein, the total far-field diverting composition injected into the formation is at least about 5 bbl/perforations cluster or at least about 20 bbl/stage. In any of the embodiments described herein, the total far-field diverting composition injected into the formation is at least about 5 bbl/perforations cluster. In any of the embodiments described herein, the total far-field diverting composition injected into the formation is at least about 20 bbl/stage. In any of the embodiments described herein, the total far-field diverting composition injected into the formation is about 20 bbl/perforations cluster to about 200 bbl/perforations cluster, or about 100 bbl/stage to about 5,000 bbl/stage. In any of the embodiments described herein, the total far-field diverting composition injected into the formation is about 20 bbl/perforations cluster to about 200 bbl/perforations cluster. In any of the embodiments described herein, the total far-field diverting composition injected into the formation is about 100 bbl/stage to about 5,000 bbl/stage.
The present disclosure also provides methods of hydraulic fracturing a formation, the methods comprising: injecting a far-field diverting composition into the formation, wherein the far-field diverting composition comprises a carrier fluid, and a non-dissolvable diverting micro-particulate having an average particle size no larger than about 200 mesh; and injecting a pad fluid into the formation after injecting the far-field diverting composition into the formation. The far-field diverting composition injected into the formation can be any of the far-field diverting compositions described herein. In some embodiments, the formation is a hydrocarbon-bearing formation.
The present disclosure also provides methods of hydraulic fracturing a formation, the methods comprising: injecting a pad fluid into the formation; and injecting a far-field diverting composition into the formation after injecting a pad fluid into the formation, wherein the far-field diverting composition comprises a carrier fluid, and a non-dissolvable diverting micro-particulate having an average particle size no larger than about 200 mesh. The far-field diverting composition injected into the formation can be any of the far-field diverting compositions described herein. In some embodiments, the method further comprises injecting a proppant-laden slurry into the formation after injecting the far-field diverting composition into the formation. In some embodiments, the far-field diverting composition is injected into the formation prior to or at about the same time as injecting a proppant-laden slurry. In any of the embodiments described herein, the far-field diverting composition can be injected into the formation at any stage during the hydraulic fracturing treatment and prior to injecting at least 90% of a proppant-laden slurry into the formation. In some embodiments, the formation is a hydrocarbon-bearing formation.
In any of the embodiments described herein, the total far-field diverting composition injected into the formation is at least about 50 lb/perforations cluster or at least about 50 lb/stage. In some embodiments, the total far-field diverting composition is from about 50 lb/perforations cluster to about 2,000 lb/perforations cluster, from about 100 lb/perforations cluster to about 1500 lb/perforations cluster, from about 250 lb/perforations cluster to about 1,000 lb/perforations cluster, from about 400 lb/perforations cluster to about 800 lb/perforations cluster, or from about 500 lb/perforations cluster to about 600 lb/perforations cluster. In some embodiments, the total far-field diverting composition is from about 50 lb/perforations cluster to about 2,000 lb/perforations cluster. In some embodiments, the total far-field diverting composition is from about 100 lb/perforations cluster to about 1500 lb/perforations cluster. In some embodiments, the total far-field diverting composition is from about 250 lb/perforations cluster to about 1,000 lb/perforations cluster. In some embodiments, the total far-field diverting composition is from about 400 lb/perforations cluster to about 800 lb/perforations cluster. In some embodiments, the total far-field diverting composition is from about 500 lb/perforations cluster to about 600 lb/perforations cluster. In some embodiments, the total far-field diverting composition is from about 500 lb/stage to about 20,000 lb/stage, from about 1,000 lb/stage to about 15,000 lb/stage, from about 2,500 lb/stage to about 10,000 lb/stage, from about 5,000 lb/stage to about 7,500 lb/stage, or from about 6,000 lb/stage to about 7,000 lb/stage. In some embodiments, the total far-field diverting composition is from about 500 lb/stage to about 20,000 lb/stage. In some embodiments, the total far-field diverting composition is from about 1,000 lb/stage to about 15,000 lb/stage. In some embodiments, the total far-field diverting composition is from about 2,500 lb/stage to about 10,000 lb/stage. In some embodiments, the total far-field diverting composition is from about 5,000 lb/stage to about 7,500 lb/stage. In some embodiments, the total far-field diverting composition is from about 6,000 lb/stage to about 7,000 lb/stage.
The present disclosure also provides methods of diverting fluids in a formation, the methods comprising injecting any of the far-field diverting compositions described herein into the formation. In some embodiments, the far-field diverting composition comprises: a carrier fluid, a proppant having an average particle size no larger than about 140 mesh, a non-dissolvable diverting micro-particulate having an average particle size no larger than about 200 mesh, and a viscosity enhancer that increases the viscosity of the carrier fluid to at least about 5 cp (such as any of the far-field diverting compositions described herein). In some embodiments, the far-field diverting composition comprises a carrier fluid, and a non-dissolvable diverting micro-particulate having an average particle size no larger than about 200 mesh (such as any of the far-field diverting compositions described herein). In some embodiments, the formation is a hydrocarbon-bearing formation.
In any of the embodiments described herein, each of the components of any of the far-field diverting systems can be mixed together to form far-field diverting composition which is injected into the formation.
In any of the methods described herein, any of the far-field diverting compositions can be introduced into the formation at a rate and pressure sufficient to create or enhance the diversion of fluids in the formation. In some embodiments, any of the far-field diverting compositions can be introduced into the formation using a hydrojetting tool. The hydrojetting tool can be connected to a tubular member and have a hydrojetting nozzle. The hydrojetting tool can be configured such that the components of any of the far-field diverting systems or any of the far-field diverting compositions flowed therethrough and out the hydrojetting nozzle are at a pressure sufficient to create or enhance the diversion of fluids in the formation. In some embodiments, any of the far-field diverting compositions can be introduced into the formation through the hydrojetting tool and out the hydrojetting nozzle at a rate and pressure sufficient to create or enhance the diversion of fluids in the formation.
In various embodiments, systems configured for delivering any of the far-field diverting compositions described herein to a formation are described. In various embodiments, the systems can comprise a pump fluidly coupled to a tubular member, the tubular member containing any of the far-field diverting compositions described herein.
The pump may be a high pressure pump in some embodiments. As used herein, the term “high pressure pump” will refer to a pump that is capable of delivering a fluid downhole at a pressure of about 1000 psi or greater. A high pressure pump may be used when it is desired to introduce any of the far-field diverting compositions to a subterranean formation at or above a fracture gradient of the subterranean formation, but it may also be used in cases where fracturing is not desired. In some embodiments, the high pressure pump may be capable of fluidly conveying particulate matter, such as any of the far-field diverting compositions described herein, into the formation. Suitable high pressure pumps include, but are not limited to, floating piston pumps and positive displacement pumps.
In other embodiments, the pump may be a low pressure pump. As used herein, the term “low pressure pump” will refer to a pump that operates at a pressure of about 1000 psi or less. In some embodiments, a low pressure pump may be fluidly coupled to a high pressure pump that is fluidly coupled to the tubular member. That is, in such embodiments, the low pressure pump may be configured to convey any of the far-field diverting compositions to the high pressure pump. In such embodiments, the low pressure pump may “step up” the pressure of any of the far-field diverting compositions before reaching the high pressure pump.
In some embodiments, the systems described herein can further comprise a mixing tank that is upstream of the pump and in which the far-field diverting composition is formulated. In various embodiments, the pump (e.g., a low pressure pump, a high pressure pump, or a combination thereof) may convey the far-field diverting composition from the mixing tank or other source of the far-field diverting composition to the tubular member. In other embodiments, however, the far-field diverting composition may be formulated offsite and transported to a worksite, in which case the far-field diverting composition may be introduced to the tubular member via the pump directly from its shipping container (e.g., a truck, a railcar, a barge, or the like) or from a transport pipeline. In either case, the far-field diverting composition may be drawn into the pump, elevated to an appropriate pressure, and then introduced into the tubular member for delivery to the formation.
It is also to be recognized that the disclosed far-field diverting compositions may also directly or indirectly affect the various downhole equipment and tools that may come into contact with the far-field diverting compositions during operation. Such equipment and tools include, but are not limited to, wellbore casing, wellbore liner, completion string, insert strings, drill string, coiled tubing, slickline, wireline, drill pipe, drill collars, mud motors, downhole motors and/or pumps, surface-mounted motors and/or pumps, centralizers, turbolizers, scratchers, floats (e.g., shoes, collars, valves, etc.), logging tools and related telemetry equipment, actuators (e.g., electromechanical devices, hydromechanical devices, etc.), sliding sleeves, production sleeves, plugs, screens, filters, flow control devices (e.g., inflow control devices, autonomous inflow control devices, outflow control devices, etc.), couplings (e.g., electro-hydraulic wet connect, dry connect, inductive coupler, etc.), control lines (e.g., electrical, fiber optic, hydraulic, etc.), surveillance lines, drill bits and reamers, sensors or distributed sensors, downhole heat exchangers, valves and corresponding actuation devices, tool seals, packers, cement plugs, bridge plugs, and other wellbore isolation devices, or components, and the like.
The following representative embodiments are presented:
Embodiment 1. A method of hydraulic fracturing a formation, the method comprising: injecting a far-field diverting composition into the formation, wherein the far-field diverting composition comprises a carrier fluid, a proppant having an average particle size no larger than about 140 mesh, a non-dissolvable diverting micro-particulate having an average particle size no larger than about 200 mesh, and a viscosity enhancer that increases the viscosity of the carrier fluid to at least about 5 cp; and injecting a pad fluid into the formation after injecting the far-field diverting composition into the formation.
Embodiment 2. A method of hydraulic fracturing a formation, the method comprising: injecting a pad fluid into the formation; and injecting a far-field diverting composition into the formation after injecting a pad fluid into the formation, wherein the far-field diverting composition comprises a carrier fluid, a proppant having an average particle size no larger than about 140 mesh, a non-dissolvable diverting micro-particulate having an average particle size no larger than about 200 mesh, and a viscosity enhancer that increases the viscosity of the carrier fluid to at least about 5 cp.
Embodiment 3. The method according to embodiment 2, further comprising injecting a proppant-laden slurry into the formation after injecting the far-field diverting composition into the formation.
Embodiment 4. The method according to any one of embodiments 1 to 3, wherein the far-field diverting composition is injected into the formation at any stage during the hydraulic fracturing treatment and prior to injecting at least 90% of a proppant-laden slurry into the formation.
Embodiment 5. The method according to any one of embodiments 1 to 4, wherein the total far-field diverting composition injected into the formation is at least about 5 bbl/perforations cluster or at least about 20 bbl/stage.
Embodiment 6. The method according to any one of embodiments 1 to 4, wherein the total far-field diverting composition injected into the formation is about 20 bbl/perforations cluster to about 200 bbl/perforations cluster, or about 100 bbl/stage to about 5,000 bbl/stage.
Embodiment 7. The method according to any one of embodiments 1 to 6, wherein the carrier fluid in the far-field diverting composition comprises greater than about 50% water.
Embodiment 8. The method according to any one of embodiments 1 to 7, wherein the proppant is a metal proppant, a sand proppant, a resin coated sand proppant, a ceramic proppant, or a bauxite proppant, or any combination thereof.
Embodiment 9. The method according to any one of embodiments 1 to 8, wherein the proppant is coated or uncoated, or a combination thereof.
Embodiment 10. The method according to any one of embodiments 1 to 9, wherein the concentration of the proppant in the far-field diverting composition is from about 0.01 lb/gal to about 5.0 lb/gal.
Embodiment 11. The method according to any one of embodiments 1 to 9, wherein the concentration of the proppant in the far-field diverting composition is from about 0.05 lb/gal to about 2.0 lb/gal.
Embodiment 12. The method according to any one of embodiments 1 to 11, wherein the non-dissolvable diverting micro-particulate is silica, a ceramic, or bauxite, or any combination thereof.
Embodiment 13. The method according to any one of embodiments 1 to 12, wherein the concentration of the non-dissolvable diverting micro-particulate in the far-field diverting composition is from about 0.005 lb/gal to about 5.0 lb/gal.
Embodiment 14. The method according to any one of embodiments 1 to 12, wherein the concentration of the non-dissolvable diverting micro-particulate in the far-field diverting composition is from about 0.05 lb/gal to about 2.0 lb/gal.
Embodiment 15. The method according to any one of embodiments 1 to 14, wherein the viscosity enhancer is a viscosifying polymer or a viscoelastic, or any combination thereof.
Embodiment 16. The method according to any one of embodiments 1 to 15, wherein the viscosity enhancer increases the viscosity of the carrier fluid in the far-field diverting composition to at least about 50 cp to about 2,000 cp, to at least about 100 cp to about 1,500 cp, to at least about 150 cp to about 1,000 cp, to at least about 200 cp to about 500 cp, or to at least about 5 cp to about 300 cp.
Embodiment 17. The method according to any one of embodiments 1 to 16, wherein the far-field diverting composition further comprises a friction reducer, a gum, a polymer, a second proppant, a scale inhibitor, an oxygen scavenger, an iron controller, a crosslinker, a corrosion inhibitor, a breaker, a surfactant, a de-emulsifier, a biocide, an acid, a clay control agent, a versifier, or an H2S scavenger, or any combination thereof.
Embodiment 18. A method of diverting fluids in a formation, the method comprising injecting a far-field diverting composition into the formation, wherein the far-field diverting composition comprises: a carrier fluid; a proppant having an average particle size no larger than about 140 mesh; a non-dissolvable diverting micro-particulate having an average particle size no larger than about 200 mesh; and a viscosity enhancer that increases the viscosity of the carrier fluid to at least about 5 cp.
Embodiment 19. The method according to embodiment 18, wherein the carrier fluid comprises greater than about 50% water.
Embodiment 20. The method according to embodiment 18 or embodiment 19, wherein the proppant is a metal proppant, a sand proppant, a resin coated sand proppant, a ceramic proppant, or a bauxite proppant, or any combination thereof.
Embodiment 21. The method according to any one of embodiments 18 to 20, wherein the proppant is coated or uncoated, or a combination thereof.
Embodiment 22. The method according to any one of embodiments 18 to 21, wherein the concentration of the proppant is from about 0.01 lb/gal to about 5.0 lb/gal.
Embodiment 23. The method according to any one of embodiments 18 to 21, wherein the concentration of the proppant is from about 0.05 lb/gal to about 2.0 lb/gal.
Embodiment 24. The method according to any one of embodiments 18 to 23, wherein the non-dissolvable diverting micro-particulate is silica, a ceramic, or bauxite, or any combination thereof.
Embodiment 25. The method according to any one of embodiments 18 to 24, wherein the concentration of the non-dissolvable diverting micro-particulate is from about 0.005 lb/gal to about 5.0 lb/gal.
Embodiment 26. The method according to any one of embodiments 18 to 24, wherein the concentration of the non-dissolvable diverting micro-particulate is from about 0.05 lb/gal to about 2.0 lb/gal.
Embodiment 27. The method according to any one of embodiments 18 to 26, wherein the viscosity enhancer is a viscosifying polymer or a viscoelastic, or any combination thereof.
Embodiment 28. The method according to any one of embodiments 18 to 27, wherein the viscosity enhancer increases the viscosity of the carrier fluid to at least about 50 cp to about 2,000 cp, to at least about 100 cp to about 1,500 cp, to at least about 150 cp to about 1,000 cp, to at least about 200 cp to about 500 cp, or to at least about 5 cp to about 300 cp.
Embodiment 29. The method according to any one of embodiments 18 to 28, wherein the far-field diverting composition further comprises a friction reducer, a gum, a polymer, a second proppant, a scale inhibitor, an oxygen scavenger, an iron controller, a crosslinker, a corrosion inhibitor, a breaker, a surfactant, a de-emulsifier, a biocide, an acid, a clay control agent, a versifier, or an H2S scavenger, or any combination thereof.
Embodiment 30. The method according to any one of embodiments 18 to 29, wherein the total far-field diverting composition is at least about 5 bbl/perforations cluster or at least about 20 bbl/stage.
Embodiment 31. The method according to any one of embodiments 18 to 29, wherein the total far-field diverting composition is about 20 bbl/perforations cluster to about 200 bbl/perforations cluster, or about 100 bbl/stage to about 5,000 bbl/stage.
Embodiment 32. The method according to any one of embodiments 1 to 31, wherein the formation is a hydrocarbon-bearing formation.
Embodiment 33. A method of hydraulic fracturing a formation, the method comprising: injecting a far-field diverting composition into the formation, wherein the far-field diverting composition comprises a carrier fluid, and a non-dissolvable diverting micro-particulate having an average particle size no larger than about 200 mesh; and injecting a pad fluid into the formation after injecting the far-field diverting composition into the formation.
Embodiment 34. A method of hydraulic fracturing a formation, the method comprising: injecting a pad fluid into the formation; and injecting a far-field diverting composition into the formation after injecting a pad fluid into the formation, wherein the far-field diverting composition comprises a carrier fluid, and a non-dissolvable diverting micro-particulate having an average particle size no larger than about 200 mesh.
Embodiment 35. The method according to embodiment 34, further comprising injecting a proppant-laden slurry into the formation after injecting the far-field diverting composition into the formation.
Embodiment 36. The method according to any one of embodiments 33 to 35, wherein the far-field diverting composition is injected into the formation at any stage during the hydraulic fracturing treatment and prior to injecting at least 90% of a proppant-laden slurry into the formation.
Embodiment 37. The method according to any one of embodiments 33 to 36, wherein the total far-field diverting composition injected into the formation is at least about 50 lb/perforations cluster or at least about 500 lb/stage.
Embodiment 38. The method according to any one of embodiments 33 to 36, wherein the total far-field diverting composition injected into the formation is about 50 lb/perforations cluster to about 2000 lb/perforations cluster, or from about 500 lb/stage to about 20,000 lb/stage.
Embodiment 39. The method according to any one of embodiments 33 to 38, wherein the carrier fluid in the far-field diverting composition comprises greater than about 50% water.
Embodiment 40. The method according to any one of embodiments 33 to 39, wherein the non-dissolvable diverting micro-particulate is silica, a ceramic, or bauxite, or any combination thereof.
Embodiment 41. The method according to any one of embodiments 33 to 40, wherein the concentration of the non-dissolvable diverting micro-particulate in the far-field diverting composition is from about 0.05 lb/gal to about 12.0 lb/gal.
Embodiment 42. The method according to any one of embodiments 33 to 40, wherein the concentration of the non-dissolvable diverting micro-particulate in the far-field diverting composition is from about 1.0 lb/gal to about 5.0 lb/gal.
Embodiment 43. The method according to any one of embodiments 33 to 43, wherein the far-field diverting composition further comprises a friction reducer, a gum, a polymer, a proppant, a viscosity enhancer, a scale inhibitor, an oxygen scavenger, an iron controller, a crosslinker, a corrosion inhibitor, a breaker, a surfactant, a de-emulsifier, a biocide, an acid, a clay control agent, a versifier, or an H2S scavenger, or any combination thereof.
Embodiment 44. A method of diverting fluids in a formation, the method comprising injecting a far-field diverting composition into the formation, wherein the far-field diverting composition comprises a carrier fluid, and a non-dissolvable diverting micro-particulate having an average particle size no larger than about 200 mesh.
Embodiment 45. The method according to embodiment 44, wherein the carrier fluid comprises greater than about 50% water.
Embodiment 46. The method according to embodiment 44 or embodiment 45, wherein the non-dissolvable diverting micro-particulate is silica, a ceramic, or bauxite, or any combination thereof.
Embodiment 47. The method according to any one of embodiments 44 to 46, wherein the concentration of the non-dissolvable diverting micro-particulate is from about 0.05 lb/gal to about 12.0 lb/gal.
Embodiment 48. The method according to any one of embodiments 44 to 46, wherein the concentration of the non-dissolvable diverting micro-particulate is from about lb/gal to about 5.0 lb/gal.
Embodiment 49. The method according to any one of embodiments 44 to 48, wherein the far-field diverting composition further comprises a friction reducer, a gum, a polymer, a proppant, a viscosity enhancer, a scale inhibitor, an oxygen scavenger, an iron controller, a crosslinker, a corrosion inhibitor, a breaker, a surfactant, a de-emulsifier, a biocide, an acid, a clay control agent, a versifier, or an H2S scavenger, or any combination thereof.
Embodiment 50. The method according to any one of embodiments 44 to 49, wherein the total far-field diverting composition is at least about 50 lb/perforations cluster or at least about 500 lb/stage.
Embodiment 51. The method according to any one of embodiments 44 to 49, wherein the total far-field diverting composition is about 50 lb/perforations cluster to about 2000 lb/perforations cluster, or about 500 lb/stage to about 20,000 lb/stage.
Embodiment 52. The method according to any one of embodiments 1 to 51, wherein the formation is a hydrocarbon-bearing formation.
In order that the subject matter disclosed herein may be more efficiently understood, examples are provided below. It should be understood that these examples are for illustrative purposes only and are not to be construed as limiting the claimed subject matter in any manner.

EXAMPLES

Example 1: A Far-Field Diverting Method Includes Water, Viscosity Enhancer, Non-Dissolvable Diverter Micro-Particulates, and Proppant

A far-field diverting method was conducted in a well penetrating Wolflcamp “C” formation located in Reeves county, Tex. in the Permian basin. The far-field diverting method included 500 bbl of water, 3 gpt friction reducer, 4000-5500 lb of non-dissolvable diverter micro-particulates (delivered in a slurry), and 0.25 lb/gal 100 mesh proppant. The far-field diverting pill was injected immediately after the injection of the pad and right before the injection of the proppant-laden slurry on 8 stages (10 perf cluster/stage), and the performance was compared to offset stages within the same lateral. It was noticed, in all stages with the far-field diverting, that the treatment pressure was consistently increasing after the injection of the diverting system especially towards the end of pumping the proppant-laden slurry, indicating potential far-field diversion and control of excessive fracture growth.

Example 2: A Far-Field Diverting Method Includes Water, Viscosity Enhancer, and Non-Dissolvable Diverter Micro-Particulates

A far-field diverting method was conducted in a well penetrating Wolflcamp “C” formation located in Reeves county, Tex. in the Permian basin. The far-field diverting method included 1000 gal of water, 3 gpt friction reducer, and 4000-4500 lb of non-dissolvable diverter micro-particulates (delivered in a slurry). The far-field diverting pill was injected immediately after the injection of the pad and right before the injection of the proppant-laden slurry on 2 stages (10 perf cluster/stage), and the performance was compared to offset stages within the same lateral. It was noticed, in the 2 stages with the far-field diverting, that the treatment pressure was consistently increasing after the injection of the diverting system especially towards the end of the pumping the proppant-laden slurry, indicating potential far-field diversion and control of excessive fracture growth.
Various modifications of the described subject matter, in addition to those described herein, will be apparent to those skilled in the art from the foregoing description. Such modifications are also intended to fall within the scope of the appended claims. Each reference (including, but not limited to, journal articles, U.S. and non-U.S. patents, patent application publications, international patent application publications, gene bank accession numbers, and the like) cited in the present application is incorporated herein by reference in its entirety.

Claims

1. A method of hydraulic fracturing a formation, the method comprising:

injecting a far-field diverting composition into the formation, wherein the far-field diverting composition comprises a carrier fluid, a proppant having an average particle size no larger than about 140 mesh, a non-dissolvable diverting micro-particulate having an average particle size no larger than about 200 mesh, and a viscosity enhancer that increases the viscosity of the carrier fluid to at least about 5 cp; and

injecting a pad fluid into the formation after injecting the far-field diverting composition into the formation.

2-3. (canceled)

4. The method according to claim 1, wherein the far-field diverting composition is injected into the formation at any stage during the hydraulic fracturing treatment and prior to injecting at least 90% of a proppant-laden slurry into the formation.

5. The method according to claim 1, wherein the total far-field diverting composition injected into the formation is at least about 5 bbl/perforations cluster or at least about 20 bbl/stage.

6. (canceled)

7. The method according to claim 1, wherein the carrier fluid in the far-field diverting composition comprises greater than about 50% water.

8. The method according to claim 1, wherein the proppant is a metal proppant, a sand proppant, a resin coated sand proppant, a ceramic proppant, or a bauxite proppant, or any combination thereof.

9. The method according to claim 1, wherein the proppant is coated or uncoated, or a combination thereof.

10. The method according to claim 1, wherein the concentration of the proppant in the far-field diverting composition is from about 0.01 lb/gal to about 5.0 lb/gal.

11. (canceled)

12. The method according to claim 1, wherein the non-dissolvable diverting micro-particulate is silica, a ceramic, or bauxite, or any combination thereof.

13. The method according to claim 1, wherein the concentration of the non-dissolvable diverting micro-particulate in the far-field diverting composition is from about 0.005 lb/gal to about 5.0 lb/gal.

14. (canceled)

15. The method according to claim 1, wherein the viscosity enhancer is a viscosifying polymer or a viscoelastic, or any combination thereof.

16. The method according to claim 1, wherein the viscosity enhancer increases the viscosity of the carrier fluid in the far-field diverting composition to at least about 50 cp to about 2,000 cp, to at least about 100 cp to about 1,500 cp, to at least about 150 cp to about 1,000 cp, to at least about 200 cp to about 500 cp, or to at least about 5 cp to about 300 cp.

17. The method according to claim 1, wherein the far-field diverting composition further comprises a friction reducer, a gum, a polymer, a second proppant, a scale inhibitor, an oxygen scavenger, an iron controller, a crosslinker, a corrosion inhibitor, a breaker, a surfactant, a de-emulsifier, a biocide, an acid, a clay control agent, a versifier, or an H₂S scavenger, or any combination thereof.

18. A method of diverting fluids in a formation, the method comprising injecting a far-field diverting composition into the formation, wherein the far-field diverting composition comprises:

a carrier fluid;

a proppant having an average particle size no larger than about 140 mesh;

a non-dissolvable diverting micro-particulate having an average particle size no larger than about 200 mesh; and

a viscosity enhancer that increases the viscosity of the carrier fluid to at least about 5 cp.

19. The method according to claim 18, wherein the carrier fluid comprises greater than about 50% water.

20. The method according to claim 18, wherein the proppant is a metal proppant, a sand proppant, a resin coated sand proppant, a ceramic proppant, or a bauxite proppant, or any combination thereof.

21. The method according to claim 18, wherein the proppant is coated or uncoated, or a combination thereof.

22-23. (canceled)

24. The method according to claim 18, wherein the non-dissolvable diverting micro-particulate is silica, a ceramic, or bauxite, or any combination thereof.

25-26. (canceled).

27. The method according to claim 18, wherein the viscosity enhancer is a viscosifying polymer or a viscoelastic, or any combination thereof.

28. (canceled)

29. The method according to claim 18, wherein the far-field diverting composition further comprises a friction reducer, a gum, a polymer, a second proppant, a scale inhibitor, an oxygen scavenger, an iron controller, a crosslinker, a corrosion inhibitor, a breaker, a surfactant, a de-emulsifier, a biocide, an acid, a clay control agent, a versifier, or an H₂S scavenger, or any combination thereof.

30-32. (canceled)

33. A method of hydraulic fracturing a formation, the method comprising:

injecting a far-field diverting composition into the formation, wherein the far-field diverting composition comprises a carrier fluid, and a non-dissolvable diverting micro-particulate having an average particle size no larger than about 200 mesh; and

34-43. (canceled)

44. A method of diverting fluids in a formation, the method comprising injecting a far-field diverting composition into the formation, wherein the far-field diverting composition comprises a carrier fluid, and a non-dissolvable diverting micro-particulate having an average particle size no larger than about 200 mesh.

45-52. (canceled)