CARBON PARTICLE-BASED LUBRICANT FOR IMPROVING PRODUCTIVITY IN UNCONVENTIONAL FORMATIONS

Abstract

A lubricant composition includes a hydraulic fracturing treatment fluid and 0.5 to 20 wt. % of carbon particles. A method of fracturing a formation includes introducing a hydraulic fracturing treatment fluid into the formation to induce fractures, where the hydraulic fracturing treatment fluid includes carbon particles present in a range of 0.5 to 20 wt. % of the total hydraulic fracturing treatment fluid weight.

Claims

1. A lubricant composition comprising: a hydraulic fracturing treatment fluid; and 0.5 to 20 wt. % of carbon particles.

2. The lubricant composition of claim 1, wherein the carbon particles are present in an amount ranging from 5 to 20 wt. %.

3. The lubricant composition of claim 1, wherein the carbon particles are selected from the group consisting of fullerenes, nanowires, nanorods, graphene, micro-scale particles of diamond, micro-scale particles of graphite, and combinations thereof.

4. The lubricant composition of claim 1, wherein the hydraulic fracturing treatment fluid comprises an aqueous base fluid.

5. The lubricant composition of claim 1, wherein the hydraulic fracturing treatment fluid comprises proppants.

6. The lubricant composition of claim 5, wherein the proppants are present in an amount ranging from 1 to 20 pounds per gallon of the hydraulic fracturing treatment fluid.

7. The lubricant composition of claim 4, wherein the hydraulic fracturing treatment fluid comprises one or more additives selected from the group consisting of clay stabilizers, scale inhibitors, corrosion inhibitors, biocides, friction reducers, thickeners, fluid loss additives, and combinations thereof.

8. The lubricant composition of claim 4, wherein the aqueous base fluid comprises at least one acid.

9. The lubricant composition of claim 8, wherein the at least one acid is selected from the group consisting of hydrochloric acid, sulfuric acid, acetic acid, and hydrofluoric acid.

10. The lubricant composition of claim 1, wherein the carbon particles comprise hydrophilic surface functional groups selected from the group consisting of carboxylic acid, hydroxyl, carbonyl, amino, phosphate, thiol, sulfate, silane and silyl.

11. A method of fracturing a formation, the method comprising: introducing a hydraulic fracturing treatment fluid into the formation to induce fractures, wherein the hydraulic fracturing treatment fluid comprises carbon particles, wherein the carbon particles are present in a range of 0.5 to 20 wt. % of the total hydraulic fracturing treatment fluid weight.

12. The method of claim 11, wherein the carbon particles are selected from the group consisting of fullerenes, nanowires, nanorods, graphene, micro-scale particles of diamond, micro-scale particles of graphite, and combinations thereof.

13. The method of claim 11, wherein the hydraulic fracturing treatment fluid comprises an aqueous base fluid.

14. The method of claim 11, wherein the hydraulic fracturing treatment fluid comprises proppants.

15. The method of claim 11, wherein the hydraulic fracturing treatment fluid comprises one or more additives selected from the group consisting of clay stabilizers, scale inhibitors, corrosion inhibitors, biocides, friction reducers, thickeners, fluid loss additives, and combinations thereof.

16. The method of claim 11, wherein the carbon particles comprise hydrophilic surface functional groups selected from the group consisting of carboxylic acid, hydroxyl, carbonyl, amino, phosphate, thiol, sulfate, silane, and silyl.

17. The method of claim 16, further comprising, prior to the introducing step, functionalizing a surface of the carbon particles through wet oxidation, dry oxidation amination, silanization, or silylation.

18. The method of claim 11, wherein the method further comprises lubricating formation surfaces in induced un-propped fractures, wherein the carbon particles provide the lubrication of formation surfaces in the induced un-propped fractures, and wherein lubrication of the formation surfaces in induced un-propped fractures by the carbon particles results in an increased residual fracture conductivity compared to the formation without lubrication of the induced un-propped fractures.

19. The method of claim 11, wherein the method further comprises recovering hydrocarbons from the formation.

Description

BRIEF DESCRIPTION OF DRAWINGS

[0007] The FIGURE illustrates a formation and surrounding fractures in accordance with one or more embodiments of the present disclosure.

DETAILED DESCRIPTION

[0008] Fracturing processes can enhance formation conductivity by injecting dense fluids at high pressures to generate fractures that ideally propagate deep into the formation. In addition to the primary hydraulic fractures created that can be propped open with typical proppants, a plurality of induced microfractures can be created around the primary hydraulic fractures. These induced microfractures are too small to be propped open using typical proppants. The induced microfractures around the primary hydraulic fractures are collectively referred to as stimulated reservoir volume (SRV). Because these induced microfractures are too small to be propped with typical proppants, they are generally unproductive. Thus, increasing conductivity in the SRV can increase overall productivity in the well.

[0009] The term induced un-propped (IU) fractures refers to fractures created around primary propped fractures during the conventional fracturing process that are too small to accommodate any proppant. The IU fractures are created by the mechanical stresses and strains imposed on the rock fabric during the creation of the primary hydraulic fractures.

[0010] The FIGURE illustrates a formation and surrounding fractures in accordance with one or more embodiments of the present disclosure. Wellhead 101 is disposed over wellbore 103 of well 105. The hydraulic fracturing treatment fluid 107 is pumped into the wellbore 103, surrounded by casing 109. Fracturing plugs 111 may be inserted along the wellbore after flowback in that section. A plurality of primary hydraulic fractures 113 surround the wellbore 103. These primary hydraulic fractures may be propped open with typical proppants. Adjacent to and in conductivity with the primary hydraulic fractures are a plurality of IU fractures 115.

[0011] The IU fractures include microfractures resulting from the slippage along planes of weakness such as bedding planes, the tensile or shear rupture of highly mineralized or closed natural fractures, or the slippage of pre-existing natural faults or fissures. These features are commonly present in most shales and other low permeability rocks. Based on production data, diagnostic methods, and field observations, it is believed that IU fractures created during the hydraulic operation may play a critical role in determining the success of fracture treatments. IU fractures are broadly defined as fractures with widths so small that they cannot accommodate any proppant and, as such, will close over time as the fluid pressure within them is decreased. Primary hydraulic fractures are defined as the fractures that may be held permanently open (or propped) by proppants as opposed to the IU fractures that are much more compliant and will close to near-zero width during flowback and production. In one or more embodiments, IU fractures are created during fracturing a formation.

Lubricant Composition

[0012] Embodiments disclosed herein relate to a lubricant composition and method related to improving well productivity of hydraulically fractured wells by introducing a carbon particle (CP)-based lubricant into the formation's microfractures during the pumping of hydraulic fracturing treatment fluids. The disclosed lubricant increases conductivity in the IU microfractures. In one or more embodiments, due to the lubrication, the microfractures may continually slip upon closure, and generate higher residual fracture conductivity, and therefore a higher well productivity.

[0013] In one or more embodiments, the lubricant composition comprises CPs. In one or more embodiments, the CPs may include fullerenes, carbon nanotubes, carbon nanowires, carbon nanorods, graphene sheets, micro-scale particles of diamond, and microscale particles of graphite, or combinations thereof. The CPs may be selected from a variety of sizes and geometries and combined for optimal performance. In one or more embodiments, the shape, size and concentration of CPs significantly influence the friction reduction and lubrication behaviors of the lubricant composition. The shape and size of the CPs chosen for a particular application may be determined by the reservoir conditions such as temperature, rock strength, pressure, water volume, injecting load, and rate. Also, the structural morphology, adsorption characteristics, chemical functionalization, and chemical reactivity of surface functional groups of carbon particles contribute to determining the CPs used in a particular application.

[0014] The properties of CPs are dependent on particle size because the carbon atoms on the surface are generally stabilized by bonding to hydrogen or other non-carbon elements. Thus, when the particle diameter is relatively small and the percentage of surface atoms is relatively large, the properties of CPs more closely resemble organic molecules rather than bulk carbon. Conversely, when the diameter increases, the percentage of surface-bound carbon atoms decreases, and the bulk carbon character of the CPs becomes more predominant.

[0015] The properties of the CPs can affect the properties of the fracturing fluids described herein. For example, an increase in CP concentration can lead to an increase in thermal conductivity and viscosity of the fracturing fluid. An increase in nanoparticle size generally decreases the viscosity of the nanofluid. Thus, in addition to the lubrication properties further described in the present disclosure, the CPs can be used to tune various other properties of the fracturing fluids.

[0016] The various types of CPs have different properties useful in lubrication which may affect their selection. For example, because the elastic modulus of carbon nanotubes (CNTs) is very high, the ability of the lubricant to avoid metallic contact between surfaces is improved, which leads to reduction of adhesive wear and friction coefficient. Also, if contact pressures are too high, CNTs may deform and adopt a lamellar shape. When this deformation happens, the CNTs can act as a solid lamellar lubricant that forms a transfer layer on the surfaces of the tribological pair. The beneficial role of the transfer film in lubrication is to reduce the shear strength at the interface while maintaining the stiffness of the contact surfaces and improving adhesion between the lamellar solids and the metallic surfaces. In one or more embodiments, CP size is selected to be suitable for the size of fractured formation, where the particles are of a small enough size to penetrate and lubricate a formation's IU fractures. In one or more embodiments, the CPs are selected in order to be compatible with the other injected chemicals, meaning they have appropriate surface chemistry to be readily dispersed for delivery and penetration downhole.

[0017] In one or more embodiments, lubricants are added to a fracturing fluid to reduce friction and wear in the mixed and boundary lubrication regimes. The main mechanism for reducing friction and wear is their small size allowing them to enter the narrow contact area where they can act as physical separators to reduce the contact area and limit direct contact between IU fractures in the rocks.

[0018] In one or more embodiments, fullerenes may be included in the composition in the form of particles that are agglomerated fullerenes. In such embodiments, the agglomerated fullerene particles may have a size ranging from a lower limit of one of 10, 12, 15, 20, 25, 30, 40, and 50 nm to an upper limit of one of 60, 70, 80, 90, or 100 nm where any lower limit can be used in combination with any mathematically compatible upper limit. Fullerenes may have sizes between 30 and 3000 carbon atoms. C24, C28, C32, C36, C50, C60 and C70 are common types of fullerenes, with C60 being the most stable. C60 molecules have an average diameter of 0.7 nm and pore size of 0.03 to 0.05 nm based on theoretical calculations and electron microscopy.

[0019] Nanowires, nanorods, and nanotubes may be considered one dimensional nanostructures, having only one dimension outside the nanometer range. Amongst the three, only nanotubes are hollow. Carbon nanotubes have a hollow core whether they are single-walled or multi-walled nanotubes. Nanotubes essentially consist of graphene sheets rolled into a tube which is more complex structure than nanowires, which are solid carbon. Nanowires and nanorods are made from similar materials but are distinguished by their dimensions, with nanowires having higher aspect ratios than nanorods.

[0020] In one or more embodiments, carbon nanotubes may be included in the composition. Single walled carbon nanotubes (SWCNTs) and multiwalled carbon nanotubes may both be used in the composition described herein. In such embodiments, the carbon nanotubes may have a length ranging from a lower limit of one of 5, 6, 7, 8, 9, or 10 m to an upper limit of one of 25, 26, 27, 28, 29, or 30 m where any lower limit can be used in combination with any mathematically compatible upper limit. In one or more embodiments, carbon nanotubes may have a diameter ranging from a lower limit of one of 0.5, 1, or 2 nm to an upper limit of one of 3, 4, or 5 nm where any lower limit can be used in combination with any mathematically compatible upper limit.

[0021] In one or more embodiments, carbon nanowires may be included in the composition. In such embodiments, the carbon nanowires may have a diameter ranging from a lower limit of one of 0.5, 1, 2, 3, 4, or 5 nm to an upper limit of one of 6, 7, 8, 9, or 10 nm where any lower limit can be used in combination with any mathematically compatible upper limit. In one or more embodiments, the carbon nanowires may have an aspect ratio ranging from a lower limit of one of 40, 50, 60, 70, 80, 90, 100, 200, 300, or 400 to an upper limit of one of 800, 900, 1000, or 1100 where any lower limit can be used in combination with any mathematically compatible upper limit.

[0022] In one or more embodiments, carbon nanorods may be included in the composition. In such embodiments, the carbon nanorods may have a diameter ranging from a lower limit of one of 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 20, or 30 nm to an upper limit of one of 40, 50, 60, 70, 80, 90, or 100 nm where any lower limit can be used in combination with any mathematically compatible upper limit. In one or more embodiments, the carbon nanowires may have an aspect ratio ranging from a lower limit of one of 0.5, 1, or 10 to an upper limit of one of 20, 30, or 40, where any lower limit can be used in combination with any mathematically compatible upper limit.

[0023] In one or more embodiments, graphene sheets may be included in the composition. Graphene is a sheet of sp2 hybridized carbon atoms with a length and a width. Graphene sheets may have multiple layers of graphene stacked on to top each other, with an average interlayer distance of 3.29 angstroms. In one or more embodiments, the graphene sheets may have a length ranging from a lower limit of one of 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 20, 30, 40, 50, 60, 70, 80, 90, 100, or 200 nm to an upper limit of one of 300, 400 500, or 600 nm, where any lower limit can be used in combination with any mathematically compatible upper limit. In one or more embodiments, the graphene sheets may have a width ranging from a lower limit of one of 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 20, 30, 40, 50, 60, 70, 80, 90, 100, or 200 nm to an upper limit of one of 300, 400 500, or 600 nm, where any lower limit can be used in combination with any mathematically compatible upper limit.

[0024] In one or more embodiments, micro-scale particles of diamond may be included in the composition. In such embodiments, the micro-scale particles of diamond may have a diameter ranging from a lower limit of one of 2.5, 3, 4, 5, 6, 7, 8, 9, or 10 m to an upper limit of one of 11, 12, 13, 14, 15, 16, 17, 18, 19, or 20 m, where any lower limit can be used in combination with any mathematically compatible upper limit.

[0025] In one or more embodiments, micro-scale particles of graphite may be included in the composition. In such embodiments, the micro-scale particles of graphite may have a diameter ranging from a lower limit of one of 0.5, 1, 2, 3, 45, 6, 7, 8, 9, or 10 m to an upper limit of one of 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, or 25 m, where any lower limit can be used in combination with any mathematically compatible upper limit. The lubricating properties of graphite are affected by the particle size. In general, as the ratio of graphite diameter to thickness increases, the specific wear of the lubricated material decreases significantly. It can be seen that the diameter-to-thickness ratio affects the lubricating effect of flake nano-graphite.

[0026] In one or more embodiments, the CPs are surface functionalized with hydrophilic surface functional groups to enable dispersion in the aqueous base fluid. The hydrophilic surface functional groups may be selected from the group consisting of carboxylic acid, hydroxyl, carbonyl, amino, phosphate, thiol, sulfate, silane and silyl. Additionally, surfactants and polymers may also be used to modify the surface of the CPs. Any surfactants or polymer used will be selected based on their compatibility and affinity with the CPs to be used and other components of the fracturing fluid. In one or more embodiments, surfactants may include anionic surfactants, cationic surfactants, amphoteric surfactants, and nonionic surfactants comprising a hydrophobic tail. In one or more embodiments, polymers may include polypyrrole (PPy), 1-pyrenebutanoic acid, succinimidyl ester (PBSE), 1-(2-anthraquinonylamino-methyl) pyrene, [bis(2-anthraquinonyl)-aminomethyl]pyrene, adamantane-pyrene, biotin-pyrene, nitrilotriacetic acid (NTA)-pyrene, ferrocene, anthracene, anthrarobin, 9,10-dibromoanthracene, 9,10-anthracene-dicarbonitrile, 9-anthracenemethanol, thionine, porphyrin, hydroxyferriproto-porphyrin (hematin), triphenylene (TP), 1,10-phenanthroline-5,6-dione (PD), polypyrrole (PPy), adamantane-pyrrole, and polyaniline (PANI). While only these possibilities are listed here, one with ordinary skill in the art will understand other hydrophilic groups may be useful. Example functionalization or surface modification methods may include wet functionalization (e.g., oxidation using nitric acid, sulfuric acid, hydrogen peroxide, potassium permanganate, etc.), dry functionalization (e.g., oxidation with air, ozone, plasma, etc.), amination, silanization, silylation, surfactant grafting, polymer grafting, polymer adsorption, and surfactant adsorption. Modification with polymers and surfactants may include covalent bonds, such as in grafting, or surface modification may be achieved through non-covalent intermolecular interactions such as in adsorption. Surfactant and polymer adsorption may be controlled such that percentage of the CP that is covered may vary from partial coverage to full coverage. For example, less surfactant or polymer may be adsorbed resulting in partial coverage of the CP surface. Alternatively, when higher quantities of surfactant or polymer are adsorbed, the resultant CP may be wrapped or encapsulated in the polymer or surfactant.

[0027] In one or more embodiments, the CPs are dispersed in an aqueous base fluid before incorporation into the hydraulic fracturing treatment fluid. The stability of CPs in the lubricant composition is determined by the properties of the aqueous base fluid, CP size, and CP surface-modification type and level.

[0028] In one or more embodiments, the lubricant composition comprises a hydraulic fracturing treatment fluid. The hydraulic fracturing treatment fluid of one or more embodiments may include, for example, water-based fracturing fluids. The hydraulic fracturing treatment fluid may include acid stimulation fluids or EOR fluids or among others. In one or more embodiments, the water-based fracturing fluids may comprise an aqueous base fluid. The aqueous base fluid may include at least one of fresh water, seawater, brine, water-soluble organic compounds, and mixtures thereof. The aqueous base fluid may contain fresh water formulated to contain various salts. The salts may include, but are not limited to, alkali metal halides and hydroxides. In one or more embodiments, brine may be any of seawater, aqueous solutions wherein the salt concentration is less than that of seawater, or aqueous solutions wherein the salt concentration is greater than that of seawater. Salts that are found in seawater may include sodium, calcium, aluminum, magnesium, potassium, strontium, and lithium salts of halides, carbonates, chlorates, bromates, nitrates, oxides, phosphates, among others. Any of the aforementioned salts may be included in brine. In one or more embodiments, the density of the aqueous base fluid may be controlled by increasing the salt concentration in the brine, though the maximum concentration is determined by the solubility of the salt. In particular embodiments, brine may include an alkali metal halide or carboxylate salt and/or alkaline earth metal carboxylate salts.

[0029] The aqueous base fluid may also include one or more acids. Acids may be particularly included when the hydraulic fracturing treatment fluid is to be used in a matrix stimulation process, as described below. The acid may be any suitable acid known to a person of ordinary skill in the art, and its selection may be determined by the intended application of the fluid. In some embodiments, the acid may be one or more selected from the group consisting of hydrochloric acid, sulfuric acid, carboxylic acids such as acetic acid, and hydrofluoric acid. In some embodiments, the hydrofluoric acid may be included as a hydrogen fluoride source, such as ammonium fluoride, ammonium bifluoride, fluoroboric acid, hexafluorophosphoric acid, and the like.

[0030] The aqueous base fluid of one or more embodiments may comprise the one or more acids in a total amount of the range of about 0.01 to 30.0 wt. %. For example, the aqueous base fluid may contain the acids in an amount ranging from a lower limit of one of 0.01, 0.05, 0.1, 0.5, 1.0, 5.0, 10, 15, 20, and 25 wt. % to an upper limit of one of 0.5, 1.0, 5.0, 10, 15, 20, 25, and 30 wt. %, where any lower limit can be used in combination with any mathematically-compatible upper limit.

[0031] In one or more embodiments, the lubricant composition may comprise the previously described CPs in a total amount of the range of about 0.5 to 20.0 wt. %. For example, the aqueous base fluid may contain the CPs in an amount ranging from a lower limit of one of 0.5, 1, 2, 3, 4, 5, 6, 7, 8, 9, and 10 wt. % to an upper limit of one of 3, 5, 7, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, and 20 wt. %, where any lower limit can be used in combination with any mathematically-compatible upper limit. This quantity of CPs enhances the lubrication properties of the composition as compared to smaller amounts of CPs typically present in fracturing fluid compositions.

[0032] The hydraulic fracturing treatment fluid may be used alone to fracture the formation. Alternatively, they may be used with a sufficient quantity of a proppant. Such proppants may include gravel, sand, bauxite, or glass beads. Proppants may be uncoated or coated with resins such as epoxy, furan, novolak, polyepoxide resins, furan/furfuryl alcohol resins, phenoloic resins, urea-aldehyde resins, urethane resins, phenolic/latex resins, phenol formaldehyde resins, polyester resins, acrylate resins and copolymers, and mixtures thereof. The particle size of the proppants may be from about 2 to about 400 mesh U.S. Sieve Series. The resulting fluid slurry may have a weight of proppant particulate material per gallon of slurry ranging from as low as about 1 ppg, up to about 20 ppg, or from about 5 ppg to about 20 ppg. Ppg is pounds of proppant to gallons of hydraulic fracturing treatment fluid.

[0033] The hydraulic fracturing treatment fluid of one or more embodiments may include one or more additives. The additives may be any conventionally known and one of ordinary skill in the art will, with the benefit of this disclosure, appreciate that the selection of said additives will be dependent upon the intended application of the hydraulic fracturing treatment fluid. In some embodiments, the additives may be one or more selected from clay stabilizers, scale inhibitors, corrosion inhibitors, biocides, friction reducers, thickeners, fluid loss additives, and the like.

[0034] The hydraulic fracturing treatment fluid of one or more embodiments may comprise the one or more additives in a total amount of the range of about 0.01 to 15.0 wt. %. For example, the hydraulic fracturing treatment fluid may contain the additives in an amount ranging from a lower limit of one of 0.01, 0.05, 0.1, 0.5, 1.0, 2.5, 5.0, 1.5, 10.0 and 12.5 wt. % to an upper limit of one of 0.1, 0.5, 1.0, 2.5, 5.0, 7.5, 10.0, 12.5, 15.0, 20.0 and 30.0 wt. %, where any lower limit can be used in combination with any mathematically-compatible upper limit.

[0035] In one or more embodiments, the hydraulic fracturing treatment fluid may have a density that is greater than 0.90 g/cm.sup.3. For example, the hydraulic fracturing treatment fluid may have a density that is of an amount ranging from a lower limit of one of 0.90, 0.95, 1.00, 1.05, 1.10, 1.15, and 1.20 g/cm.sup.3 to an upper limit of one of 1.00, 1.05, 1.10, 1.15, 1.20, and 1.25 g/cm.sup.3, where any lower limit can be used in combination with any mathematically-compatible upper limit.

[0036] In one or more embodiments, the hydraulic fracturing treatment fluid may have a viscosity that is of an amount ranging from a lower limit of one of 2, 3, 4, 5, 6, 7, 8, 9, 10, 20, 30, 40, 50, 60, 70, 80, or 90 centipoise (cPs) to an upper limit of one of 100, 200, 300, 400, or 500 cPs.

[0037] The hydraulic fracturing treatment fluid may be prepared in any suitable manner. For example, in one or more embodiments, the CPs are dispersed into the aqueous base fluid through mechanical mixing and/or sonication. Then, the other components of the hydraulic fracturing treatment may be added in any suitable manner such as mechanical mixing. In some embodiments, the CPs may be added to all of the other components of the hydraulic fracturing treatment pre-mixed and dispersed into said mixture through mechanical mixing and/or sonication. Thus, the components of the hydraulic fracturing treatment fluid may be added in any order. Standard mixing techniques may be used in addition to any specialized mixing or sonication that may be required to disperse the CPs.

Method of Fracturing a Formation

[0038] A formation may be fractured by using the hydraulic fracturing treatment fluid 107 according to one or more embodiments. Referring back to the FIGURE, the hydraulic fracturing treatment fluid 107 may be injected into the wellbore 103 through wellhead 101 at a pressure that may overcome the native overburden pressure of the formation, thus resulting in fracturing. The well 105 may first be treated with a salt solution to help stabilize the formation prior to injection of the hydraulic fracturing treatment fluid 107.

[0039] Methods in accordance with the present disclosure may include the injection of a hydraulic fracturing treatment fluid 107 into a well 105. In one or more embodiments, the hydraulic fracturing treatment fluid 107 may be a single treatment fluid that is injected into the wellbore 103 in one pumping stage. In other embodiments, methods in accordance with one or more embodiments may involve the injection of the hydraulic fracturing treatment fluid 107 and one or more additional stimulation fluids. The additional stimulation fluids may, in some embodiments, be co-injected with the hydraulic fracturing treatment fluid 107. In some embodiments, the stimulation fluids may be injected after the hydraulic fracturing treatment fluid 107. A plurality of primary hydraulic fractures 113 are created, distributed along the wellbore 103 during fracturing. In addition to the plurality of primary hydraulic fractures 113 that are able to be propped, there are a plurality of IU fractures 115. Fracturing plugs 111 may be inserted along the wellbore 103 after flowback in that section.

[0040] The methods of one or more embodiments may be used for well stimulation. A well stimulation process in accordance with one or more embodiments of the present disclosure may include the step of injecting the hydraulic fracturing treatment fluid 107 into a hydrocarbon-bearing formation at a well 105. In some embodiments, the injection of the hydraulic fracturing treatment fluid 107 may be performed at a pressure that is below the fracturing pressure of the formation. The formation may be stimulated by the hydraulic fracturing treatment fluid 107, creating pathways for hydrocarbon production. According to some embodiments, the displaced hydrocarbons may be recovered through the stimulated reservoir. In one or more embodiments, the hydrocarbons may be recovered at a wellhead 101.

[0041] The well stimulation process of one or more embodiments may be a matrix stimulation process. In the matrix stimulation process of one or more embodiments, the aqueous base fluid, or one of the stimulation fluids, contains an acid. The acid fluid may react with the formation, dissolving rock, and creating wormholes that create a pathway for hydrocarbons to be displaced from deeper within the rock.

[0042] In one or more embodiments, the well stimulation process may be repeated one or more times to increase the amount of hydrocarbons recovered. In some embodiments, subsequent well stimulation processes may involve the use of different amounts of the CNPs and/or additives than the first.

[0043] In one or more embodiments, during the fracturing process, the primary hydraulic fractures may be propped open by typical proppants such as those described above. As is known to one with ordinary skill in the art, the proppants will hold the primary hydraulic fracture open during flowback and production. In one or more embodiments, adjacent to the primary hydraulic fractures there may exist a plurality of IU microfractures that have connectivity to the primary hydraulic fractures. While these IU fractures are too small to be propped open, maximizing conductivity through these IU fractures may increase formation productivity during flowback and production. The CPs of the present disclosure are small enough that they can fit into the IU fractures, thereby lubricating the IU fractures.

[0044] In one or more embodiments, when CPs of the lubricant composition are present in the IU fractures in a formation, the IU faces of the fractures may be more prone to slip upon closure after pressure is reduced. This slippage or higher displacement along fracture faces creates a more significant mismatch between roughness and asperities of the two faces of the fracture, which leads to higher residual fracture conductivity. In addition, in the production phase, as the pore pressure decreases the total stress in the reservoir decreases with time, and subsequently the stress acting on the fracture plane decreases with time. With the fracture plane having a lower friction coefficient due to the presence of the CPs, the decreased stress on the fracture plane can cause slippage along the fracture later on in the life of the well. This subsequent slippage can also contribute to increased fracture conductivity and well production, which may continue over the lifetime of the well.

[0045] Embodiments of the present disclosure may provide at least one of the following advantages. When the lubricant composition has been supplied to IU fractures in a formation, the formation may have increased production over the lifetime of the well due to the fracture planes having a lower friction coefficient and prolonged slippage when compared to the same formation without the lubricating composition present in IU fractures. The presence of the CPs in the IU fractures may increase conductivity through the IU fractures to the primary hydraulic fractures compared to when the lubricant composition is absent. Increased conductivity through the IU fractures to the primary hydraulic fractures may lead to increased production in the well.

[0046] Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims.