WO2018226737A1 - Hydraulic fracturing fluid - Google Patents

Abstract

A polymer and hydraulic fracturing fluid provide an improved ability to transport proppant. In an embodiment, a method of designing a hydraulic fracturing fluid includes calculating an elastic modulus of a polymer. The method also includes calculating a critical velocity of a hydraulic fracturing fluid comprising the polymer and proppant based on the elastic modulus of the polymer.

Description

HYDRAULIC FRACTURING FLUID

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application claims the benefit of Application No. 62/657,228, filed April 13, 2018; Application No. 62/630,353, filed February 14, 2018; Application No. 62/630,087, filed February 13, 2018; Application No. 15/614,244, filed June 5, 2017; the entirety of all of which is incorporated by reference herein.

FIELD

[0002] This disclosure relates generally to fracturing fluids. This disclosure relates specifically to a hydraulic fracturing fluid with an improved ability to transport proppant.

BACKGROUND

[0003] Within recent years, the oil and gas industry has developed the use of hydraulic fracturing to produce what was once considered nonproductive oil and gas formations. Typically, most of these formations are made up of low or no porosity shale wherein the oil and gas can exist within micro-fractures present in these formations and not within the shale itself. For this reason, connecting more of these micro fractures and keeping them connected to each other and to the wellbore can be beneficial to the successful and continuous production of the well. The degree of fluid communication though the fractured formation and wellbore can be referred to as conductivity of the formation. This hydraulic fracturing technology can include the use of high volumes of water and a propping agent to be pumped into subterranean wells under tremendous rates and pressures to pry rock apart, thereby allowing the oil and gas that is trapped within the matrix of the oil and gas formations to migrate to the wellbore and production casing. Although the use of this technology may have allowed high volumes of oil and gas recovery, there exists challenges with transport of propping agents through long wellbore conduits.

[0004] Hydraulic fracturing is typically based on three fundamental elements. First, drill horizontally within the reservoir to expose long sections of the oil and gas bearing formation to the pressure conduit. Two, secure the pressure conduit in place using cement or packers, then perforate and isolate 100 to 250-foot sections of the conduit generating a passage from the conduit to the reservoir. Third, using water, sand and pressure, pump through the perforated channels prying the rock apart, then use the sand to prop the formation open and allow the oil and gas to migrate into the well. Thereafter, repeat the process until the entire length has been connected to the reservoir. Although fracturing can be basic in concept, optimizing the process has proven challenging and is continuously evolving.

[0005] There are several issues related to the hydraulic fracturing process that can become problematic when wellbores reach extreme lengths. One challenge is that the pressure that the water needs to be pumped at has to be sufficiently high enough to continuously exert a force on the rock sufficient to pry the rock apart or to exceed the fracture gradient of the reservoir. This force is often needed to be continuously maintained as the water penetrates the reservoir and radiates away from the wellbore. Therefore, the flow rate of fracturing fluid has to be maintained high enough to continuously exert sufficient force to progress the fracture even as the area increases and as leak off occurs as the leading edge of the fracture encounters micro fractures in the formation. Since the oil and gas is believed to exist within these micro-fractures, the more micro-fractures that can be connected to the flow of water and sand the more productive the well can potentially be. However, once the rate of leak off of fluid into the micro-fractures becomes equal to the rate of fluid that is being pumped from surface, the ability to apply enough force to separate the rock and progress the fracture radially from the main borehole can become lost.

[0006] Reducing the friction during pumping can decrease the pressure drop due to friction thereby delivering greater force to the reservoir resulting in higher radial coverage and increased microfracture connectivity. Chemicals such as polyacrylamides have been used in reducing pump friction by lowering the interfacial surface tension between the fluid and the conduit. This lower interfacial surface tension can allow for lower pump pressures and higher rates to be used. The process can become counterproductive when it comes to the transportation of the sand into the fractured cavity. If the fluid rates become too low, then the sand can be left far behind the leading edge of the fracture. The pump rates can be adequate to transport the sand though the conduit area, but once the sand exits into the formation and the area increases, the sand can stop progression into the fracture once the critical velocity drops below about 1,700 feet per minute.

[0007] Some fracturing techniques have incorporated the use of smaller sand particles such as 100 mesh sand to aid in particle transport deeper into the fracture cavity as the 100 mesh, sand can have a lower critical velocity. Other techniques to increase proppant transport includes using man- made proppants that have a lower specific gravity rendering it almost naturally buoyant, which can allow it to be floated into the well without the use of chemicals. However, the cost of these man- made proppants can often far exceed their benefit and use. Furthermore, smaller proppants have often proven problematic when it comes to plugging with contaminates from the water that can flow back from the well or even the chemicals themselves that are used to transport the sand.

[0008] In response to these challenges, rate and pressure in exchange have typically been sacrificed for sand placement near the leading edge of the fracture. Such sacrifice has historically been accomplished through the use of highly viscous crosslinked polymers such as guar crosslinked with a borate or metallic cation, which can create a 3-dimensional polymer structure with much higher suspension characteristics. These viscous mixtures are typically pumped alongside an oxidizing breaker such as persulphate to allow the viscous mixture to be thinned once it has transported the sand into position. However, as these polymer chains are broken, they can generate a solid mass or a precipitant that can damage the formation and can result in reduced permeability by plugging the pore space generated by the fracturing sand and hindering the well's production. The industry's use of viscous fluids to maintain the sand in a state of suspension for extended periods has often proven to be problematic and has sacrificed rate and caused pump horsepower requirements to be very high. These viscous fluids have also historically not functioned well in fluid systems that were not fresh water with a neutral pH, and crosslinked systems can be sensitive to metallic compounds present in the water.

[0009] According to IHS Markit(l) and other industry analysts, U.S. frac sand consumption was expected to reach new heights in 2017, surpassing the previous high-water mark of 2014. More to the point, in its Aug. 1, 2017, quarterly earnings call, leading sand producer U.S. Silica, which estimates frac sand usage has increased 70% over the past four years, predicted 2018 demand will hit 90 million tons or greater. Of that, 45% would come from the Permian basin, with 85% of the increased deliveries comprising finer- grade 40/70- and 100-mesh proppant. Record frac sand consumption coincides with the trend toward appreciably longer horizontal laterals, increased frac stages and proppant loadings of between 2,000 to 5,000 lb/lateral ft. The proportionately higher frac fluid volumes introduce increased pressure and friction values, typically higher in the toe section and decreasing as the fracing operation progresses toward the heel.

[0010] Unprecedented proppant volumes have re-energized attention on carrier fluids capable of optimizing proppant distribution to enhance overall stimulation efficiency and maximize estimated ultimate recovery (EUR). (2,3,4, 5) As the industry has drawn a direct correlation between sand volumes and production, sustained conductivity and proppant placement remains among the most daunting issues confronting the unconventional sector. Unlike conventional formations, which experience more benefit from longfracture half-lengths, impermeable zones perform best when surface area exposure is maximized through the creation of a complex dendritic fracture network. The use of thin fracture fluids— pumped at high rates— helps maximize complexity, while pumping small-grained proppant enables entry into micro-fractures that are inaccessible to large- grained particles.

[0011] Noting that effective placement of proppant in a fracture has a dominant effect on well productivity, Blyton, et al,(3) hold that existing fracture models assume ideal proppant transport, even with low-viscosity fluids, and that often they were found to over-predict propped or effective lengths by 100% to 300%. More specifically, it is commonly assumed that the average proppant velocity due to flow is equal to the average fluid velocity, while the settling velocity calculation relies solely on Stokes' Law, which simply describes the force of viscosity on a small sphere moving through a viscous fluid.

[0012] Therefore, there exists a need in the art for a polymer that does not rely on viscosity and particle suspension ability to transport proppant during a fracturing operation.

SUMMARY OF EMBODIMENTS

[0013] An embodiment of the disclosure is a hydraulic fracturing fluid system comprising a hydraulic fracturing fluid comprising an acrylamide -based polymer with an elastic modulus from 0.2 dyn/cm2 to 60.0 dyn/cm2; a water; and a proppant; wherein the hydraulic fracturing fluid conveys proppant into a reservoir during a hydraulic fracturing without causing a pump rate to be reduced and the pump pressure to be increased. In an embodiment, elastic modulus is between about 30.0 dyn/cm2 and 60.0 dyn/cm2. In an embodiment, the proppant is conveyed at a velocity between about 1,700 ft/min and 1,800 ft/min. In an embodiment, the proppant is sand. In an embodiment, a concentration of the proppant is between 1.75 lb/gal and 3 lb/gal. In an embodiment, the acrylamide-based polymer is present at a concentration of 6 lb/1000 gal. In an embodiment, there is improved proppant progression compared to standard viscous polymers. In an embodiment, the particle size of the polymer is between 60 mesh and 500 mesh. In an embodiment, the water is selected from the group consisting of fresh water and produced water. In an embodiment, oil production from the reservoir increases 25%-30%. In an embodiment, the polymer retains at least 70% conductivity. In an embodiment, the system leaves less material behind to plug and damage pore space than a cross-linked polymer. In an embodiment, operators can transition from slickwater to gelled fluid by elevating the dosage ratio of the polymer as the proppant concentration and particle size increase. In an embodiment, the acrylamide-based polymer is present at a concentration of 6 lb/1000 gal; the elastic modulus is between about 30.0 dyn/cm2 and 60.0 dyn/cm2; the proppant is sand at a concentration of 1.75 lb/gal to 3 lb/gal; and the proppant is conveyed at a velocity between about 1,700 ft/min and 1,800 ft/min.

[0014] An embodiment of the disclosure is a hydraulic fracturing fluid comprising an acrylamide- based polymer with an elastic modulus from 0.2 dyn/cm2 to 60.0 dyn/cm2, wherein the acrylamide-based polymer is present at a concentration of between 0.25 lb/1000 gal and 12 lb/1000 gal; water; and a proppant. In an embodiment, the proppant is sand. In an embodiment, the sand mesh is between 40 mesh and 100 mesh. In an embodiment, a concentration of the sand is between 1.75 lb/gal and 3 lb/gal. In an embodiment the acrylamide-based polymer is present at a concentration of 6 lb/1000 gal.

[0015] An embodiment of the disclosure is a method of hydraulic fracturing comprising preparing an acrylamide-based polymer with an elastic modulus from 0.2 dyn/cm2 to 60.0 dyn/cm2; adding the polymer to water; adding a proppant to the polymer and water to form a hydraulic fracturing fluid; injecting the polymer to a formation; and conveying the proppant at a velocity between about 1,700 ft/min and 1,800 ft/min.

[0016] The foregoing has outlined rather broadly the features of the present disclosure in order that the detailed description that follows may be better understood. Additional features and advantages of the disclosure will be described hereinafter, which form the subject of the claims.

BRIEF DESCRIPTION OF THE DRAWINGS

[0017] These drawings illustrate certain aspects of some of the embodiments of the present disclosure and should not be used to limit or define the disclosure.

[0018] FIG. 1 illustrates a viscous and elastic response to an applied strain in a fluid.

[0019] FIG. 2 illustrates an elastic versus viscous modulus for a fluid.

[0020] FIG. 3 illustrates a bar graph of polymer concentration and its effect of fluid properties.

[0021] FIG. 4 illustrates the operation temperature range of a polymer.

[0022] FIG. 5 illustrates a Lissajou plot for a fluid comprising a polymer.

[0023] FIG. 6 illustrates an elastic modulus test for various polymers. [0024] FIG. 7 illustrates a viscous modulus test for various polymers.

[0025] FIG. 8 illustrates a comparison between elasticities for the polymers of FIG. 6 and FIG. 7.

[0026] FIG. 9 illustrates an elastic modulus test for various polymers.

[0027] FIG. 10 illustrates a viscous modulus test for various polymers.

[0028] FIG. 11 illustrates a comparison between elasticities for the polymers of FIG. 9 and FIG. 10.

[0029] FIG. 12 illustrates elevation of the dosage ratio as the sand concentration and proppant density increase.

[0030] FIG. 13 illustrates a treatment plot for a Wolfcamp treatment with a slickwater frac, using only a standard polyacrylamide friction reducer.

[0031] FIG. 14 illustrates a treatment plot for a proactive linear gel treatment used to increase viscosity of a Wolfcamp well.

[0032] FIG. 15 illustrates replacement of the slickwater and friction reducer with the high- viscosifying friction reducer (HVFR) polymer during various parts of stage 11 in one Wolfcamp well.

DETAILED DESCRIPTION

[0033] The present disclosure can generally relate to a polymer that when hydrated has high viscoelastic properties. Furthermore, methods of designing a fracturing fluid comprising the polymer are provided. The present disclosure can also generally relate to hydraulic fracturing fluids wherein the fluid can comprise water and a soluble polymer that modifies rheological properties of the solution in which it is disposed.

[0034] Reducing the friction factors that can restrict sufficient pumping rates, required for uniform proppant transport, represents a prevailing challenge for high-rate hydraulic fracturing operations. Typically, operators have relied on multi-additive methodologies that increase both the complexity and costs of frac programs designed to stimulate tight-margin unconventional assets.

[0035] More recently, the application of a dual-function high-viscosifying friction reducer (HVFR) polymer in the Permian basin's Wolfcamp shale has demonstrated efficacy at delivering high pump rates and transport capacity, without the need for cross-linked or linear gel additives to provide viscosity for particle suspension. Specifically, a comparative analysis of Wolfcamp offsets shows that the HVFR polymer has helped increase pumping rates 20% to 25%, with up to 6 lb/gal of frac sand. The analysis also shows that it has helped increase initial production (IP) rates by up to 30%, compared to conventionally fraced wells.

[0036] The polymer was engineered to reduce pressure and improve the transfer of energy, from horsepower on the surface, to the hydraulic fractures. Owing to increased average pump rates, the new-generation HVFR polymer effectively distributes proppant further into the fracture network at lower velocities, improving flow capacity and, in turn, the potential for sustainable reservoir drainage.

[0037] The HVFR polymer represents an advancement in hydraulic fracturing fluid technology, because it helps close the gap between pressure reduction, horsepower, and frac sand transportation and distribution. The chemically-driven methodology has resolved many of the intrinsic limitations of cross-linked, slickwater and complex hybrid frac systems.

[0038] CROSS-LINKED VS. SLICKWATER FRACS

[0039] Accordingly, owing to their highly viscous characteristics, cross-linked polymers were introduced into hydraulic fracturing to increase the volumetric loading of the sand and to build fracture width and dimensions. Cross-linked polymers traditionally have been integrated in frac designs to hold the sand in total suspension, and to improve lateral proppant distribution (fracture half-length) at low velocities. Cross-linking generally is described as a bond formed between polymer chains, either between different chains or between different parts of the same chain. To create the viscous fluid, cross-linked gel systems normally combine a guar or modified guar-based fluid with borate, zirconate, titanate or other reagents in the presence of alkali.

[0040] Though cross-linked fluids provide superb suspension and can deliver high proppant pack flow-capacity after cleanup, they come with higher cost and operational complexity. Ironically, the intrinsic suspension benefits of high viscosity prove detrimental, in that the viscous nature of cross-linked polymers generates higher pumping pressure, requiring the frac fluid to be pumped at reduced rates to manage pressure. The economic issues are compounded with the required high concentrations of costly biopolymers, such as guar, which has a history fraught with a supply- demand imbalance. In addition, cross-linked polymers require breakers to dissolve the polymer bond once pumping is completed. While cross-linked polymers function satisfactorily in fresh water, the corresponding low tolerance for chlorides or solids within the carrier fluid severely complicates water recycling and negatively affects operators' environmental profile. [0041] As the industry has evolved, and as unconventional assets have become primary targets, a noticeable shift in the use of slickwater frac systems has occurred. Traditional slickwater treatments incorporate an anionic or cationic polyacrylamide-based polymer to keep the fluid in the appropriate flow regime, and to act as a friction reducing agent, enabling maximum fluid flow at minimum pumping energy.6 Since the wide-scale adoption of hydraulic fracturing, slickwater fracs that incorporate friction reducers have been in vogue as a mechanism for improving pump rates and reducing pressure, to stay within the limits of the casing. The primary drivers for this methodology are reduced costs, minimalized proppant pack damage, increased fracture complexity and a comparatively lowered environmental footprint. The capacity to withstand an extensive variety of fluid conditions, while maintaining an acceptable level of pressure control, also clears the way for the recycling of higher volumes of flowback and produced water.

[0042] However, the diminished capability of these thin fluids to effectively suspend and transport proppant in a fracture (and the wellbore) poses the most significant limitation to slickwater frac designs. (7) Exceptionally low viscosity requires increased pump rates to maintain the turbulence needed for particle transportation. While turbulence can be regulated easily when volumes and velocities are of a known value, such as within the casing, it becomes much less predictable when the fluid exits into the reservoir, and velocity rapidly dissipates. (8) Weakened velocities can dramatically alter the ratio between sand and water, thus limiting proppant distribution and ultimately the generation of effective half-lengths.

[0043] To compensate for the low viscosity and limited carrying capacity of slickwater treatments, best practices typically dictate lower proppant concentrations (3 lb/gal or less) and the use of large volumes of finer mean particle diameter proppant, most commonly 100-mesh and 40/70 mesh. What's more, water recyclability is offset partially by record water consumption/well, as sand volume/lateral ft continues to spiral to accommodate the reduced sand-to-liquid ratio.

[0044] DUAL-FUNCTION METHODOLOGY

[0045] Attempts to capture the respective functions of slickwater and cross-linked gel frac systems in a single well led operators to employ so-called hybrid fracs. (9, 10) Defined as a mix between slickwater and cross -link-type treatments, hybrid fracs transition from slickwater polyacrylamide polymers to a slickwater polymer with a guar-based linear gel viscosifier. The linear gel is used to increase viscosity to improve the ability to transport proppant away from the near wellbore (NWB) region. If necessary, a cross-linked gel can be pumped at the tail end of the treatment to permit higher proppant concentrations, and to promote a conductive fracture network, specifically in the NWB region.

[0046] Complex hybrid fracs require a higher level of project management, because of the multiple polymers that must be added and replaced throughout each of the stages, where concentrations reach as high as 20 lb/1,000 gal. Consequently, issues relating to the compatibility of the various polymers, breaker requirements and chloride tolerances can vary significantly, requiring careful control of not only the chemical compositions and loadings, but also of the base water and the individual mixing requirements. As such, adding multiple polymers together can drive the water pumping cost, per 1,000 gal, into the $80-plus range. Broken down, required dosage rates call for 1 to 2 gal of friction reducer/1,000 gal of water, at a cost of $6 to $10/gal, and the viscosifier rate varies from 18 to 20 lb/1,000 gal of water, or 4 to 5 gal of viscosifier/1,000 gal of water at a cost of $15-$25/gal.

[0047] Operators also have turned to increased dosage rates of standard polyacrylamide friction reducers to build viscosity and improve particle transportation. Although this can be an effective approach, polyacrylamide loadings of more than 6 gallons per thousand gallons (gpt) can be required (depending on water quality) to achieve viscosity levels comparable to that of a 10- to 15- lb guar-based linear gel. Consequently, it became clearly evident that the higher dosage ratio of even the cheapest polyacrylamide often yields negligible economic benefit, with costs often comparable to that of a hybrid frac.

[0048] A high-viscosifying friction reducers (HVFR) has been developed to allow dual functions within the same polymer. With reservoir compatibility and minimizing the amount of solids pumped during a frac among the primary justifications for development, low-solids polymers can replace the multiple-chemical blends previously used, reducing both volume and mass. HVFR technology improves proppant transportation, while reducing pumping pressure or horsepower requirements during pumping operations. HVFRs have reduced the volume of solids/ 1,000 gal of water at an average 25% of the cost of a hybrid frac.

[0049] In an embodiment, the polymer can have any suitable particle size. In embodiments, the polymer can comprise an average particle size determined by API sieving techniques of about 60 to about 100 US mesh size. Particle size can be an important factor to the rate of hydration of the polymer. In general, a smaller particulate size can hydrate quicker than a larger particulate size. Rapid hydration can be important so that the polymer can quickly act to suspend particulates and reduce friction, which can be especially important when pumping at relatively high rates such as 100 or more barrels per minute. Without rapid hydration, partial benefits of the polymer can be lost, and thus the polymer can be provided in a larger quantity to compensate for performance inefficiencies.

[0050] In an embodiment, the polymer can be provided as a dry granular material. The polymer can be directly introduced as a dry material into an aggressive moving body of fluid without high volume resonance requirements. Without limitation, the use of a dry material can reduce the cost as opposed to providing it as an oil-based suspension, which can be typical oil-based polymers presently in use. Further, without limitation, the requirements for transport and storage of a dry material are often less than providing as a liquid. Furthermore, the amount of polymer per unit volume of a dry polymer can be greater than what can be achieved with a liquid suspension (i.e. the moles of a polymer present in a volume of solid dry granules can be greater than the moles of a polymer present in the same volume of a liquid suspension).

[0051] In an embodiment, the polymer can comprise multiple repeating base units or monomers. In embodiments, the polymer comprises acrylamide, sodium amps (2-Acrylamido-2- methylpropane sulfonic acid), acrylic acid, sodium acrylate, vinyl alcohol, vinyl acetate, N- vinylpyrolidone, 2-hydroxymethy methacrylate, or any combinations thereof. In embodiments, the majority composition of the polymer can comprise acrylamide. In some embodiments, acrylamide can be present in an amount of about 96.0 wt.% to about 99.0 wt.%. The polymer can be crosslinked with a cross linking agent. Any suitable cross-linking agent can be used. In embodiments, cross linking agents include N,N'-methylenebis(acrylamide), boric acid, ethylene glycol diacrylate, polyethylene glycol diacrylate, or any combinations thereof. In embodiments, the cross-linking agents can be present in an amount of about 0.1 wt.% to about 0.8 wt.%. Where used, the cross linker can also be combined with a reaction initiator. Any suitable reaction initiator can be used. In an embodiment, the reaction initiator comprises ammonium persulfate, benzoyl peroxide, potassium persulfate, sodium hypochlorite, polyethylene glycol diacrylate, or any combinations thereof. In embodiments, the reaction initiator can be present in an amount of about 0.005 wt.% to about 0.2 wt.%. Additionally, breakers can be used to cleave the cross-linked bonds downhole. Any suitable breaker can be used. Suitable breakers can include ammonium persulfate, sodium persulfate, sodium hypochlorite, perborates, peroxides, enzymes, or any combinations thereof. In embodiments, a breaker can be present in an amount of about 200 ppm to about 600 ppm.

[0052] In some instances, the polymer can be damaged by the conditions of the wellbore. A protective agent can be used in conjunction with the polymer to protect the polymer from adverse temperature, pressure, and chemical species encountered in the wellbore or formation. Any suitable protective agents can be used. In embodiments, suitable protective agents include acrylamide, sodium amps (2-Acrylamido-2-methylpropane sulfonic acid), acrylic acid, sodium acrylate, vinyl alcohol, vinyl acetate, N-vinylpyrolidone, 2-hydroxymethy methacrylate, copolymerizations thereof, or any combinations thereof. A suitable protective agent can comprise AMPS (2-acrylamido-2-methylpropane sulfonic acid). With the addition of AMPS, it can be possible to use the polymer in more adverse pH conditions such as in a range of from about 1 to about 12 and with temperatures up to about 450 °F. In embodiments, the protective agent can be present in an amount of about 5.0 wt.% to about 49.0 wt.%. Additionally, AMPS in conjunction with the polymer can be used in applications where total dissolved solids range from about 0 corresponding to fresh water or to saturation, for example a saturated brine.

[0053] In an embodiment, the dry granular material is added to provide a fracturing fluid with a polymer composition of between about 1.0 wt.% and about 50 wt.% polymer, alternatively between about 30 wt.% and about 40 wt.%, and alternatively about 35 wt.%.

[0054] Due to the wide operating range and conditions of the polymer and AMPS, the water used during fracturing can be from sources that are not freshwater such as produced water or well flow back fluids. The polymer and AMPS can be able to withstand being used in produced water, thereby reducing the freshwater requirement of the fracturing fluid.

[0055] Without being limited by theory, viscoelastic material can comprise both viscous and elastic properties. It is to be understood that in a perfectly elastic material, the stress and strain occur in phase so that the response of one occurs simultaneously with the other. Further, in a perfectly viscous material, there is a phase difference between stress and strain, where strain lags behind stress by about a 90-degree phase lag. A perfectly elastic material experiences the stress and strain simultaneously such that there is not phase lag between stress and strain.

[0056] A rheometric measurement can include applying an oscillatory force to a material, such as a fluid containing a polymer, at a constant frequency, for example 1 Hz, and measuring the resulting displacement. The oscillatory force of stress can then be plotted with the displacement strain against time. FIG. 1 illustrates a typical stress response of a perfectly viscous and perfectly elastic fluid to an oscillating force (strain) on the fluid. A viscoelastic fluid can exhibit behavior somewhere in between that of a purely viscous and purely elastic material as there would be at least some phase lag Θ, where 0° < Θ < 90°. FIG. 2 illustrates how the typical elastic and viscous modulus can plotted for an elastic and viscous fluid.

[0057] In an embodiment, a viscoelastic fluid can comprise properties of both a viscous fluid and an elastic solid. In some embodiments, the polymer included in the viscoelastic fluid can be tuned to have particular viscous and elastic properties in solution. The polymer of this disclosure can be tuned to, for example, have a high degree of elasticity. A particular polymer can comprise properties such as high shear thinning combined with a high viscoelasticity. Such a polymer in solution cannot suspend particles while static as the viscosity can be too low but can lower turbulence while flowing to reduce pressure loss and horsepower requirements during flow. Furthermore, if a polymer comprises a sufficient viscoelastic component, under dynamic flow conditions in a horizontal flow conduit, the polymer can be capable of suspending particulates. In such a flow, the particulates can move as an entire mass with the fluid. In effect, the particulates can be dragged along by the polymer in the fluid. The ability to suspend particulates can be governed by the elastic memory of the polymer in the fluid. As the fluid containing the polymer flows through a conduit, eddy currents and subsequent turbulence can impart energy into the polymer. The polymer can be yielded during flow and the energy buildup subsequently released. This rebound effect can be about equal and about opposite of the energy imparted in the fluid and therefore can effectively suspend particulates within the fluid. Therefore, the polymer allows particulates (i.e. sand) to be transported at low velocities using the elastic modulus.

[0058] As the fluid and polymer flow, the rebound and release of energy stored in the polymer can cause surface disturbances between the flowing fluid and the conduit through which it is flowing. The disturbances can disrupt the interface between the moving body of fluid and the particulates that settle to the lower portion of the fluid bed. Disrupting the interface can allow the particulates to remain fluidized rather than settling out of the flow stream. A viscoelastic fluid with sufficiently high viscoelasticity can under dynamic condition flow horizontally though a conduit such that the entire mass of suspended particulates moves in conjunction with the fluid. Furthermore, disrupting the interface can reduce pipe friction thereby decreasing horsepower requirements for a pump. [0059] Disturbing the interface between the flowing fluid and particulates suspended therein can keep the particulates fluidized and flowing with the bulk fluid rather than settling out. The loading or mass of particulate per unit volume of fluid can be increased to a larger amount than can be possible using conventional polymers that do not have the elastic rebound property as previously described.

[0060] Once the particulates settle out of solution, they can collect and plug the fracture or other flow paths. If too much plugging occurs, further particulate transport cannot be possible leading to a condition known as a screenout. Screenout can cause a sudden and significant restriction to flow causing a potentially dangerous rise in pump pressure. The screenout can occur in any area with a restricted flow area such as perforations in the casing or within fractures. The polymer can reduce the amount of particle settling especially at relatively lower velocities thereby potentially reducing the conditions that enable a screenout to occur.

[0061] In an embodiment, a fluid having extremely high shear thinning characteristics can also poses extreme viscoelastic characteristics. Such a fluid can under static conditions not suspend sand or particles. However, the fluid can be used to allow a lower pump pressure thereby improving the horsepower transfer during pumping operations. Additionally, if the viscoelasticity is high enough, under dynamic conditions in a horizontal flow conduit, a mass of particles disposed in the fluid can form a mass that can move in conjunction with the fluid. This is thought to occur when the elastic memory of the material is yielded, and the energy is released. This rebound is equal to and opposite of the energy that is imparted into the fluid media and is best represented in the form of G prime and G double prime.

[0062] A relationship between stress and strain for an elastic solid can be defined by the following equations:

σ = Gy (1)

γ = 7o sin(6>t) (2)

[0063] A relationship between stress and strain rate of a viscous fluid can be defined by the following equations:

σ = ηγ (3)

γ = γ₀ω cos(iot) (4)

[0064] A viscoelastic fluid contains properties of both a viscous liquid and an elastic solid so the previous equations can be combined to derive an equation describing viscoelastic fluids. σ(ω, t) = G 'Y_Q sin(iot) + G"y₀ sin(iot) (5)

r"

„= - (6)

[0065] The term G' represents the elastic modulus, and the term G" represents the viscous modulus. Typically, the units of G' and G" are in dyn/cm2 or Pascals. Equation 5 can be used to calculate G' and G". Without being limited by theory, it is to be understood that G' and G" are not temperature dependent and can be varied by temperature.

[0066] Furthermore the term σ represents sinusoidal stress with units of dyn/cm2, the term G represents elastic modulus with units of dyn/cm2, the term γ represents sinusoidal strain, the term 7o represents strain amplitude, the term ω represents angular frequency with units of 1/s, the term t represents time with units of seconds, the term η represents dynamic viscosity with units of Pa^»s, and the term γ represents strain rate with units of 1/s.

[0067] A polymer included in the fracturing fluids can have a sufficiently large G' such that particles can be suspended by flow. A suitable polymer is available from Tianfloc Canada Inc. under the name A589T. In particular, G' (elastic modulus) can have a value within the range of about 0.2 dyn/cm2 to about 50 dyn/cm2; alternatively, about 0.2 dyn/cm2 to about 10 dyn/cm2, about 10 dyn/cm2 to about 20 dyn/cm2, about 20 dyn/cm2 to about 30 dyn/cm2, about 30 dyn/cm2 to about 40 dyn/cm2, about 40 dyn/cm2 to about 50 dyn/cm2, alternatively about 0.1 dyn/cm2 to less than about 60 dyn/cm2. Furthermore, G" (viscous modulus) can have a value of about 0.2 dyn/cm2 to about 13 dyn/cm2; alternatively, about 0.2 dyn/cm2 to about 1 dyn/cm2, about 0.2 dyn/cm2 to about 2.0 dyn/cm2, about 2.0 dyn/cm2 to about 5.0 dyn/cm2, about 5.0 dyn/cm2 to about 8.0 dyn/cm2, about 8.0 dyn/cm2 to about 10.0 dyn/cm2, about 1 dyn/cm2 to about 3 dyn/cm2, about 3 dyn/cm2 to about 6 dyn/cm2, about 6 dyn/cm2 to about 10 dyn/cm2, or about 10 dyn/cm2 to about 13 dyn/cm2. In some examples, G' can be greater than about 30 dyn/cm2.

[0068] A hydraulic fracturing fluid can be designed using the previously discussed polymer. There can be several design considerations taken into account during the design process of a fracturing fluid. Some parameters can include the ability of the fluid to transport a proppant, compatibilities of the fluid to the formation, pressure loss due to friction, and cost, among many others. As previously discussed, the fracturing fluid comprising the polymer can have the ability to transport proppant without the use of a viscosifying agent or turbulence. A method for designing the hydraulic fracturing fluid can comprise calculating the desired polymer amount such that the elastic component G' is sufficiently large to be able to transport a desired amount of proppant. [0069] A method of designing a hydraulic fracturing fluid can comprise calculating an elastic modulus of a polymer and calculating a critical velocity of a hydraulic fracturing fluid comprising the polymer and proppant based on the elastic modulus of the polymer. The calculations can be used during a hydraulic fracturing operation to ensure the fluid velocity in a tubular or fracture is above the critical velocity to prevent proppant settling. The method can further comprise calculating a maximum loading of proppant based on a concentration of the polymer and the elastic modulus. The concentration of polymer can be selected based on a desired loading of proppant. The method can further comprise a step of calculating a hydration time for the polymer. As previously discussed, the hydration time can be important as the polymer should hydrate as quickly as possible to increase the effectiveness of the polymer.

[0070] A method of hydraulic fracturing can comprise calculating an elastic modulus of a polymer, calculating a critical velocity of a hydraulic fracturing fluid comprising the polymer and a proppant based on the elastic modulus of the polymer, preparing the hydraulic fracturing fluid comprising the polymer and the proppant, and injecting the hydraulic fracturing fluid through a tubular and into a subterranean formation at a volumetric rate such that a fluid velocity in the tubular is at or above the critical velocity.

[0071] The polymer of the present disclosure can enable particulates to be transported with the fluid at much lower velocities than a standard friction reducer. Without limitation, such a velocity can enable the sand to progress much further into the fractured cavity thereby increasing the amount of area that is connected to the conduit. This increased area can result in higher initial production rates and better overall cumulative production.

[0072] In some embodiments, the use of a polymer that can move larger sand into the cavity along with higher volumes of sand can create additional surface area that is generated by the greater particle transportation. Sand loading can then be increased for longer periods of time to compensate for the increase in surface area, which can facilitate the well to be far more productive. In some embodiments, sand loading can be about 0.25 lb/gal to about 1.0 lb/gal (i.e., A589T dosage was 1.0 ppt (lbs per 1,000 gallons) to 2.0 ppt.

[0073] Without being limited by theory, the polymer can absorb and release energy in a fluid. This storing and releasing of energy within the fluid can set up surface disturbances that disrupt the interface between the moving body of fluid and the sand bed on the lower portion of the fluid bed. This building and releasing of energy within the fluid can fluidize heavy concentrations of sand and other particles allowing a dense media to be transported at velocities below the critical transport velocities as compared to conventional fluids that do not comprise the polymer. The critical transport velocities are based on maintaining mechanical agitation of the sand through the use of turbulent flow. This turbulence can then be used to help transport or carry the particles with the fluid as the fluid travels horizontally. A challenge with the use of turbulence for fluidization of particulates is that once the rate or velocity drops below turbulent levels the particulates can settle and can separate from the fluid. This settlement and separation can occur as the surface area of the formation or fractured area increases. In some embodiments, the critical velocities can be as low as 1,700 feet per min.

EXAMPLES

Example 1

[0074] Samples were prepared and tested for G' and G" . Viscoelastic measurements were taken at various amplitude of about 50% to about 400%, frequency of about 0.5 Hz to about 4.5 Hz, and temperature off about 75°F to about 250 °F.

[0075] FIG. 6 illustrates elastic modulus (G') of A589T, xanthan gum, an emulsion polymer, and guar gum in DI (Deionized) water. The samples were tested at various amplitudes, frequencies, and temperatures. A589T indicated relatively high values of elasticity comparatively to the other chemicals tested. Additionally, A589T had higher heat resistance as compared to the other tested chemicals. FIG. 7 illustrates the elastic modulus (G") of the same samples tested at the same conditions.

[0076] FIG. 8 illustrates the Tan(5) comparison of the samples from FIG. 6 and FIG. 7. When the elastic modulus value is larger than the viscous modulus value, Tan(5) becomes below 1. The lower the value of Tan(5) is, the more elastic property the polymer has. As illustrated in FIG. 8, A589T has the highest elastic properties among the tested chemicals. The Tan(5) can be calculated by the following equation.

Viscous Modulus (G")

Γαη(<5) =

Elastic Modulus (C)

[0077] FIGs. 9, 10, and 11 illustrate the elastic modulus and viscous modulus of the same chemicals tested in FIGs. 5-8 but wherein the deionized water is replaced by 10 lb/gal brine solution. The results show that A589T has the highest elastic and viscous modulus of each of the chemicals tested.

Example 2

[0078] During the development of the HVFR material, a testing platform was developed that could be used to measure cause and effect of the materials application. The testing platform is advantageous over a series of laboratory tests that can only measure the rheology of the fluid under select test criteria. The existing data available from industry and university sources established measurement criteria only focused on the plastic viscosity of the fluid, the yield point, and the funnel viscosity.

[0079] To enable sand progression during a hydraulic fracturing operation, the viscosity of the fluid is used to hold the sand particles within the fluid column to resist settling. The rate has to be high enough to progress the sand before it settles or the velocity of the fluid has to be high enough to generate turbulence to reintroduce the particle into the fluid column to allow progression of the particle to occur. The problem with this methodology is that once the velocity drops below a turbulent level, the ability to reintroduce the particle into the fluid column is lost. If the viscosity of the fluid is too high, then rates are reduced based on the frictional resistance to pumping, causing the pump pressure to be increased and the rates to be reduced. This higher viscosity can also have a negative influence on the amount of hydraulic horsepower required during pumping operations. For this reason, testing during actual operations on the wells needed to be performed to determine all of the variables that could be measured for the purpose of particle progression.

[0080] Due to the lack of available data within the industry that could measure the application of the polymer into the fluid system and their reflective characteristics, a measurement and data collection system was developed and established to determine the effectiveness of the sand transportation. For this purpose, a computer-controlled system was developed that could operate in a steady state environment to provide reliable data on the application of the polymer while recording polymer dosage rates, pressure, fluid rates, viscosity thermal thinning, pH of the water, chloride levels, and total dissolved solids (TDS) level of the water and the volume of sand transported during the operation. Because these characteristics have a significant influence on the transport efficiencies of the sand and ultimately the hydraulic horsepower application and frac performance, it was determined that this information was critical to optimizing polymer performance.

Example 3

[0081] Because the industry uses calculated values generated by lab scale testing and small volume models to represent field operations, a better platform for performance was needed. For this reason, the post stage frac zonal isolation plug removal, better known as drill out, was chosen. The drill out is performed after the hydraulic fracturing is completed and uses smaller dimensional tubulars or coiled tubing to drill and remove these plugs. Because the dimensions of the pipes are reduced, the frictional resistance that the fluid has to pump is exaggerated beyond that of a hydraulic frac. The velocity or pump rate of the fluid is restricted to the throughput capacity of the smaller tubulars and the downhole motors used to drill the plugs out. Typically, it is one tenth of the critical velocity used during a hydraulic fracturing operation. This, coupled with the closed loop system on the actual wellbore geometry that would be present during a frac, made it a suitable platform to develop the polymer. Fluid readings and polymer viscosity measurements were taken as the polymer was introduced into the system and then collected as it was returned to surface, allowing the effect of the fluid and temperature on the polymer to be determined. Sand volumes and transport efficiencies could be measured in addition to any changes to the pumping pressure as those changes were made. These measurements provided actual data (as opposed to predictions based on computer models). Thirty-two data collection units were manufactured and deployed in each horizontal basin within the USA. Large scale models were built to determine best in class polymers to use during the initial testing to establish performance base lines. During this testing, data was collected on over 4,000 wells and water quality samples were taken and analyzed. Working with polymer manufacturers, materials were also tested that were uncommon to the oil and gas industry as were materials that were used in other applications. The focus was on finding characteristics that could be used for particle progression within a horizontal well frac application. It was discovered during this testing that a polymer having a high elastic modulus could provide better particle progression at lower velocities than standard viscous polymers. A shear sensitive polymer having a high elastic modulus can be used to reduce pump pressure through its shear sensitivity by generating relief at the boundary layer between the fluid and the conduit. The polymer could still generate enough resistance to shear so that it generates frictional drag forces on the sand bed causing the sand to progress at almost the exact same velocity of the fluid. During standard frac operations, viscosity is used to keep the sand captive within the fluid while the fluid is being pumped. These viscous fluid mixtures have typically used guars and crosslinkers to prevent slippage of the sand from the fluid. However, slick water fracs use low viscosity fluids pumped at higher rates to generate enough turbulence for the sand to progress with the fluid. In the case of slick water, the progression of the sand at higher velocities is less than a 1 to 1 ratio (the water moves faster than the sand), however, as the velocity reduces so does the transport efficiencies of the sand. Once critical transport velocity is reached, the sand no longer progresses with the fluid and the depositing sand is referred to as a screen out. This normally occurs during slick water operations at a velocity of 1,700' to 1,800' per minute. However, these materials are cheap and provide good pressure reduction or horsepower improvement during the Frac operations. It was also discovered during testing that the use of 2-acrylamido-2-methyl-l- propanesulfonic acid sodium salt (sodium AMPS) during the manufacturing process of the acrylamide polymer could be used to improve the tolerance of the material to chloride and pH changes within the water, making the material well suited for use in recycled fluids or providing the ability to reuse produced water for frac applications. For this reason, these need to be added into the reactor during the manufacturing of the polymer and require the polymer to be run to full reaction, giving the polymer a higher molecular weight and a better performance. These polymers then precipitate and require that the polymer be ground to a small particle size to improve its wettability and viscosity performance. In an embodiment, the sizing and grinding particle range is from 60 mesh to 500 mesh. In an embodiment, the elastic modulus is from 0.2 dyn/cm2 to 60.0 dyn/cm2, depending upon the application.

[0082] It was discovered that these polymers can be used at much lower dosage rates than the guars and crosslinks that they replace during a hydraulic fracturing operation, typically one third to one quarter the dosage ratios. In an embodiment, 20 pounds/1,000 gallons of gels can be replaced with 6 pounds/1,000 gallons of HVFR material while providing lateral performance of sand transportation. In an embodiment, the HVFR material is present at 0.25 pounds/1,000 gallons to 12 pounds/ 1,000 gallons. In an embodiment, the HVFR material is present at 1.5 pounds/ 1,000 gallons. It was also discovered that when testing the retained conductivity of the material, this material had much higher retained conductivity or was much less damaging to the reservoir or the formation and the frac sand pack. It leaves less material behind to plug and damage the pore space that is generated by the frac sand downhole. Example 4

[0083] Conceptually, development of the new-generation HVFR-1405 polymer stepped beyond the circular reasoning of particle transportation, based on the slip velocity of a solid within a viscous fluid. More focus was placed on advancing frac fluid chemistry to develop an enhanced transport fluid. The new generation polymer allows operators to seamlessly transition from slickwater to gelled fluid characteristics, with the same chemistry, by simply elevating the dosage ratio of the HVFR polymer, as the sand concentration and particle size increase. Fig. 12. The polymer functions by creating a drag coefficient between the sand and the moving body of fluid, sufficient to enable the sand to be progressed with the fluid without separation. The shear sensitivity of the polymer provides stable pressure reduction, even as loading ratios are varied.

[0084] During initial polymer development, best-in-class polyacrylamides were used to establish test loop pressures and rate baselines. At the same time, it was determined that a method was required to test and record data from actual jobsites. The ultimate objective was verifying particle transport efficiencies in low velocity conditions, while improving hydraulic horsepower requirements. Accordingly, a closed-loop system was warranted, where control variables could be quantified and recorded, and polymer loading data could be compared to particle transport efficiencies, while measuring thermal thinning, chloride levels, pH shifts and hydraulic horsepower.

[0085] Computer-controlled, steady-state polymer delivery systems were designed and deployed for data collection. This pressure loop data was then compared to known values during plug drill- outs with 2-in. coiled tubing strings of an average length of 20,000 ft. The closed-loop system used during the drill-out process was identified as a suitable post-development test lab to evaluate and refine the polymer.

[0086] Drill-outs are among the most challenging aspects of a completion, as the operator is working with small-diameter tubulars, generating high friction while removing large solids from the wellbore, at velocities much lower than those in a hydraulic fracturing job. Additionally, the recirculation and dilution of flowback during drill-outs affects water quality unfavorably. The ensuing challenges required the polymer be sufficiently shear-sensitive in order to reduce pressure, while also developing ample viscosity to prevent the fluid from separating from the solids.

[0087] With the drill-out trials establishing the variables that control particle transportation efficiencies, adjustments to the polymer design were carried out in more than 3,500 drillouts. Overall, the resulting efficiencies in particle transportation reduced well time and lowered chemical consumptions, while also eventually eliminating short trips.

Example 5

FIELD RECAPS

[0088] General observations from field operations have shown a notable improvement in the ability to place proppant with relatively small increases in viscosity. Utilizing a standard linear gel measurement at 511 sec-1 as a baseline and increasing the viscosity from typical friction loadings of about 2 cp to a minimum of about 7 cp— by use of a viscosifying agent— has resulted in a significant improvement in the ability to place proppant and increase concentrations.

[0089] Figure 13 shows the overall treatment plot for a Wolfcamp B frac in Reeves County, Texas. As shown, efforts to place the treatment, using only slickwater and a standard polyacrylamide friction reducer, were met with consistent resistance, once the 40/70 proppant concentration reached 1.25 to 1.50 lb/gal. Based on the observed pressure responses, the treatment schedule was augmented with multiple unplanned sweeps, but the proppant concentration remained limited to 1.5 lb/gal. At approximately 190 min. into the treatment, a 15-lb linear gel was pumped, and after that, formation clean-up was observed, and pressure was stabilized. From then on, the 40/70 proppant was stepped up successfully to 3.0 lb/gal concentration without incident. This treatment successfully placed 448,000 lb of 100-mesh and 40/70-mesh frac sand, using 12,075 bbl of fluid over the course of 240 min.

[0090] Based on the positive response to the viscous fluid, the decision was made to proactively start the linear gel immediately (Fig. 14) following the 100-mesh proppant. Figure 15 shows how the slickwater and friction reducer were replaced during various parts of stage 11, where the friction reducer was pumped at 70.9 min. at a dosage rate of 3.75 gpt, with no improvement on pressure. At 80 min. into the stage, the HVFR polymer was introduced into the system and ramped up to an identical dosage rate, with marked improvement in both rate and pressure. The addition of the HVFR polymer in Stage 11 of one Wolfcamp well demonstrated noticeable improvements in both rate and pressure. Fig. 15.

[0091] At 100 min. into stage 11, the linear gel was brought back online at a dosage rate of 4.5 gpt (15 lb linear gel) as the sand was being ramped up to 1 lb/gal, with a noticeably negative impact on both rate and pressure. At 155 min. into the stage, the 4.5-gpt (15-lb) linear gel was again replaced with the HVFR-1405 polymer at a dosage rate of 1.5 gpt, resulting in improvements in rate and pressure. Correspondingly, the sand concentration was raised to 1.75 lb/gal. Hence, the new-generation polymer demonstrated the capacity to move higher lateral sand volumes at significantly lower dosage ratios. Additionally, a comparative analysis shows incremental oil production averaging 25% to 30% for Wolfcamp wells treated with the HVFR polymer.

[0092] It is possible that the comparatively improved performance can be attributed to enhanced sand placement or improved conductivity, due to the cleaner breaking of the polymer and the absence of precipitate generated. However, the enhanced production likely can also be explained by considering the retained conductivity values generated by the new-generation polymer, compared to that of a standard linear gel or cross-linked polymer, Table 1. As detailed in the table, the combination of the shear thinning nature of this material and cleaner breaks exhibited a 70% improvement in retained conductivity, compared to a cross-linked polymer.(l 1)

[0093] Using the polymer at a concentration of 6 lb/ 1,000 gal would be less damaging to the formation, rather than using 20 lb/1,000 gal of linear gel or cross-linked polymer. Although sand placement and horsepower transfer are critical components to a well's performance, reducing the amount of damage to the porosity and permeability generated by the sand is equally important.

[0094] Similar responses to pumping a HVFR polymer-enhanced viscous fluid have been observed in the Eagle Ford, Haynesville, Marcellus, Niobrara and other unconventional plays. While treatment character will vary on a well-by-well and even stage -by- stage basis, options are available to help improve proppant placement and operational efficiency. Likewise, reducing plugging clears the way for optimizing many of the variables and mitigating the limitations associated with the frac design to focus on what best maximizes well production.

Table 1. Tabular data for 2.5 gpt sample

[0095] Although the present disclosure has been described with respect to specific details, it is not intended that such details should be regarded as limitations on the scope of the invention, except to the extent that they are included in the accompanying claims. Modifications to the invention can be made as might occur to one skilled in the field of the invention within the scope of the appended claims. All embodiments contemplated hereunder that achieve the objects of the invention have not been shown in complete detail. Other embodiments can be developed without departing from the spirit of the invention or from the scope of the appended claims.

REFERENCES

[0096] 1. Jacob, T., "Frac sand demand expected to exceed peak 2014 levels," IHS Markit Energy Blog, Can 3, 2017.

[0097] 2. Wu, C-H., S. Yi and M. M. Sharma, "Proppant distribution among multiple perforation clusters in a horizontal wellbore," SPE paper 184861-MS, presented at the 2017 SPE Hydraulic Fracturing Technology Conference and Exhibition, The Woodlands, Texas, Jan. 24-26, 2017.

[0098] 3. Blyton, C. A., D. P. Gala and M. M. Sharma, "A comprehensive study of proppant transport in a hydraulic fracture," SPE paper 174973-MS, presented at the 2015 SPE Annual Technical Conference and Exhibition, Houston, Texas, Sept. 28-30, 2015.

[0099] 4. Johnson, K., "Cost-effectiveness, long-term sustainability drive chemistry best practices," American Oil & Gas Reporter, October 2017.

[0100] 5. Bokane, A., S. Jane, Y. Deshpande, and F. Crespo, "Transport and distribution of proppant in multistage fractured horizontal wells: A CFD simulation approach," SPE paper 166096, presented at the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, La., Sept. 30-Oct. 2, 2013.

[0101] 6. Motiee, M., M. Johnson, B. Ward, C. Gradl, M. McKimmy, and J. Meeheib, "High concentration polyacrylamide-based friction reducer used as a direct substitute for guar-based borate cross-linked fluid in fracturing operations," SPE paper 179154-MS, presented at the 2016 SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, Feb. 9-11, 2016.

[0102] 7. Jackson, K., and O. Orekha, "Low-density proppant in slickwater applications improves reservoir contact and fracture complexity - A Permian basin case history," SPE paper 187498- MS2017, presented at 2017 SPE Liquids-Rich Basins Conference - North America, Midland, Texas, Sept. 13-14, 2017. [0103] 8. Wood. W. D., and R. S. Wheeler, "A new correlation for relating the physical properties of fracturing slurries to the minimum flow velocity required for transport," SPE paper 106312, presented at the 2007 SPE Hydraulic Fracturing Technology Conference, College Station, Texas, Jan. 29-31, 2007.

[0104] 9. Handren, P., and T. Palisch, "Successful hybrid slickwater-fracture evolution: An East Texas Cotton Valley Taylor case history," SPE Production and Operations, August 2009.

[0105] 10. Sharma, M. M., P. B. Gadde, R. Sullivan, R. Sigal, R. Fielder, D. Copeland, L. Griffin, and L. Weijers, "Slickwater and hybrid fracs in the Bossier: Some lessons learnt," SPE paper 8876- MS, presented at the 2004 SPE Annual Technical Conference and Exhibition, Houston, Texas, Sept. 26-29, 2004.

[0106] 11. Domelen, M. V., W. Cutrer, S. Collins, and M. Ruegamer, "Applications of viscosity- building friction reducers as fracturing fluids," SPE paper 185084, presented at the 2017 SPE Oklahoma City Oil and Gas Symposium, Oklahoma City, Okla., March 27-30, 2017.

Claims

CLAIMS What is claimed is:

1. A hydraulic fracturing fluid system comprising

a hydraulic fracturing fluid comprising

an acrylamide-based polymer with an elastic modulus from 0.2 dyn/cm² to 60.0 dyn/cm²;

a water; and

a proppant;

wherein the hydraulic fracturing fluid conveys proppant into a reservoir during a hydraulic fracturing without causing a pump rate to be reduced and the pump pressure to be increased.

2. The hydraulic fracturing fluid system of claim 1 wherein the elastic modulus is between about 30.0 dyn/cm² and 60.0 dyn/cm².

3. The hydraulic fracturing fluid system of claim 1 wherein the proppant is conveyed at a velocity between about 1,700 ft/min and 1,800 ft/min.

4. The hydraulic fracturing fluid system of claim 1 wherein the proppant is sand.

5. The hydraulic fracturing fluid system of claim 1 wherein a concentration of the proppant is between 1.75 lb/gal and 3 lb/gal.

6. The hydraulic fracturing fluid system of claim 1 wherein the acrylamide-based polymer is present at a concentration of 6 lb/1000 gal.

7. The hydraulic fracturing fluid system of claim 3 where there is improved proppant progression compared to standard viscous polymers.

8. The hydraulic fracturing fluid system of claim 1 wherein the particle size of the polymer is between 60 mesh and 500 mesh.

9. The hydraulic fracturing fluid system of claim 1 wherein the water is selected from the group consisting of fresh water and produced water.

10. The hydraulic fracturing fluid system of claim 1 wherein oil production from the reservoir increases 25%-30%.

11. The hydraulic fracturing fluid system of claim 1 wherein the polymer retains at least 70% conductivity.

12. The hydraulic fracturing fluid system of claim 1 wherein the system leaves less material behind to plug and damage pore space than a cross-linked polymer.

13. The hydraulic fracturing fluid system of claim 1 wherein operators can transition from slickwater to gelled fluid by elevating the dosage ratio of the polymer as the proppant concentration and particle size increase.

14. The hydraulic fracturing fluid system of claim 1 wherein the acrylamide-based polymer is present at a concentration of 6 lb/1000 gal; the elastic modulus is between about 30.0 dyn/cm² and 60.0 dyn/cm²; the proppant is sand at a concentration of 1.75 lb/gal to 3 lb/gal; and the proppant is conveyed at a velocity between about 1,700 ft/min and 1,800 ft/min.

15. A hydraulic fracturing fluid comprising

an acrylamide-based polymer with an elastic modulus from 0.2 dyn/cm² to 60.0 dyn/cm², wherein the acrylamide-based polymer is present at a concentration of between 0.25 lb/1000 gal and 12 lb/1000 gal;

water; and

a proppant.

16. The hydraulic fracturing fluid of claim 6 wherein the proppant is sand.

17. The hydraulic fracturing fluid of claim 7 wherein the sand mesh is between 40 mesh and 100 mesh.

18. The hydraulic fracturing fluid of claim 7 wherein a concentration of the sand is between 1.75 lb/gal and 3 lb/gal.

19. The hydraulic fracturing fluid of claim 6 wherein the acrylamide-based polymer is present at a concentration of 6 lb/1000 gal.

20. A method of hydraulic fracturing comprising

preparing an acrylamide-based polymer with an elastic modulus from 0.2 dyn/cm² to 60.0 dyn/cm²;

adding the polymer to water;

adding a proppant to the polymer and water to form a hydraulic fracturing fluid;

injecting the polymer to a formation; and

conveying the proppant at a velocity between about 1,700 ft/min and 1,800 ft/min.