WO2020051204A1

WO2020051204A1 - High-performance treatment fluid

Info

Publication number: WO2020051204A1
Application number: PCT/US2019/049488
Authority: WO
Inventors: Jose Hilario GUZMAN JAIMES
Original assignee: Prime Eco Group, Inc.
Priority date: 2018-09-04
Filing date: 2019-09-04
Publication date: 2020-03-12

Abstract

This disclosure provides compositions and methods for an oriented film that may include a core layer consisting essentially of biaxially oriented linear low-density polyethylene, wherein the core layer has a first side and a second side. Further, the film may include a first sealant layer consisting essentially of biaxially oriented linear low-density polyethylene on the first side, and a second sealant layer consisting essentially of biaxially oriented linear low- density polyethylene on the first side, wherein the linear low-density polyethylenes in each of the film's layers may be of more than one type/grade, have the same or different densities, or both. Further still, the film is 30 pm or less in thickness, has a water-vapor transmission rate of ≤ 1 g/m²/d at 38°C and 90% relative humidity, and has an oxygen transmission rate of ≤ 100 cm³/m²/d at 23°C and 0% relative humidity.

Description

HIGH-PERFORMANCE TREATMENT FLUID

REFERENCE TO RELATED APPLICATIONS

[0001] This application is a Patent Cooperation Treaty application, which claims priority to United States provisional patent application serial number 62/726,458 filed on 4 September 2018 that is hereby incorporated by this reference.

FIELD

[0002] This application relates to high-performance treatment fluids for potential use in a wide variety of subterranean treatment operations.

BACKGROUND

[0003] A common practice in hydraulic fracturing of gas-producing reservoirs is the use of non- viscous, slickwater fluids pumped at high rates, e.g. , > 60 bpm, to generate narrow fractures with low concentrations of proppant. In recent years, these uses have become a standard technique in fracture stimulation of several U.S. shales, including the Barnett, Marcellus, and Haynesville, and yield economically viable production. The low-proppant concentration, high- fluid efficiency, and high pump rates in slickwater treatments yield highly complex fractures. Additionally, compared to a traditional bi-wing fractures, slickwater fractures often find the primary fracture connected to multiple orthogonal (secondary) and parallel (tertiary) fracture networks. Coupled with multistage fracture completions and multiple wells located on a pad, complex fracture networks yield a high degree of reservoir contact.

[0004] The most critical chemical additive for slickwater fracturing is a polyacrylamide- based friction reducer (“FR”). The high pump rates for slickwater treatments e.g., 60-100 bbl/minute, necessitate the action of FR additives to reduce friction pressure up to 70%; this effect helps to moderate the pumping pressure to a manageable level during proppant injection. Common chemistries for friction reduction include polyacrylamide derivatives and copolymers added to water at low concentrations. Additional additives for slickwater fluids may include biocides, surfactants, scale inhibitors, and others. Other advantages of slickwater fracturing fluids as compared to crosslinked, linear, gelled, fracturing fluids, which are viscous and known in the art, may include high-retained conductivity due to no filter cake present, reduced sensitivity to salinity and contaminants in mix-water, and reduced number of fluid additives required for slickwater fracturing fluid. [0005] As proppant-suspension capacity of slickwater fluids is known to be quite low, another solution known in the art is the use of linear, non-crosslinked gels. These fluids, based on non-crosslinked solutions of polysaccharides, e.g., guar, derivatized-guar, HEC, and xanthan, have viscosities of up to 100 cP at 100 sec ¹ at surface temperature that depend on polymer concentration. As this viscosity is several orders of magnitude higher than slickwater, linear gels have improved proppant-suspension. When non-crosslinked gels are used in late- slurry stages of a fracturing treatment, i.e., where the pad and early-slurry stages used slickwater, these are often referred to as“hybrid” fracturing treatments. Noteworthy is that “hybrid” may also refer to fracture treatments using crosslinked gel to follow slickwater, crosslinked gel following linear/non-crosslinked, and other variations.

[0006] Additional use for the above-mentioned fluids include coiled tubing operations with displacement of so-called sweeps that are required to clean up bottom hole casing or carrying gravel pack sand over completion screens in conventional workover. Each one related to slick water (pump horse power) or linear, non-crosslinked gels.

[0007] In addition to foregoing discussion about some of the drawbacks of briefly introduced slickwater and gel fluids, also discussed are desirous properties of fracturing fluids (a.k.a.“treatment fluids”), especially in relation to viscosity and proppant capacity. Viscosity of fracturing fluids is an important point of differentiation. For example, slickwater treatments use low- viscosity fluids pumped at high rates to generate narrow, complex fractures with low- concentrations of proppant agent, e.g., 0.2-5.0 lb of proppant added (“PPA”) per gallon. To minimize risk of premature screen out in fracturing fluids, pumping rates must be sufficiently high to transport proppant over long distances, often along horizontal wellbores where sand drops out of the fracturing fluid and creates dunes, which may prevent proppant transport deep into the fracture. One thing to remember: a fluid may have high viscosity but not suspension properties. For suspension, adding polymers of guar gum and derivatives that are crosslinked with borates in a sequential process that continues with the addition of different breakers, e.g., peroxides, chlorites and equivalents, allows flow back from the fractured zones to surface. These chemicals get into the produced water together with polyacrylamides that do not degrade and become an environmental problem, regardless of its low cost. Fracturing-fluid additives that increase viscosity can be costly, and their chemistry can result in lower productivity, e.g., formation damage and in proppant pack poor conductivity. Engineers may also choose an alternative mesh size to achieve better transport such as 100 mesh and 40/70 mesh proppant sand. By comparison, for conventional wide-biwing fractures, the carrier fluid must be sufficiently viscous, e.g., normally 50 to 1000 cP at nominal shear rates from 40-lOOsec ¹ to transport higher proppant concentrations, e.g., 1-10 PPA per gallon. These treatments are often pumped at lower pump rates and may create wider fractures, e.g. , 0.2 to 1.0 in.

[0008] Some disadvantages of slickwater fluids, including high- viscosity slickwater fluids, as compared to that of gelled fracturing fluids are detailed below: Larger volumes of fresh water often required for fracture design compared to gelled fracturing fluids.

Larger horsepower requirement to maintain high pump rates, e.g. , 60-110 bpm.

Limited fracture-width due to low maximum concentration proppant in low viscosity. Reduced %-flowback-water recovery due to imbibement of fracturing fluid in complex fracture network far from wellbore.

SUMMARY

[0009] In one aspect, disclosed is a composition consisting of a polymer blend consisting of 0 to 90 wt.% of flour polysaccharides, 0 to 80 wt. % of biopolymers, and 0 to 50 wt.% of modified natural starches, wherein the polymer blend is capable of being suspended for carrying proppants. The polymer blend, optionally suspended as a powder into mineral oil, may mixed in an aqueous fluid, such as fresh or salt water, with optional components including pH control additives, surfactants, breakers, bactericides, crosslinkers, fluid loss control additives, stabilizers, friction reducers or combinations thereof.

BRIEF DESCRIPTION OF THE DRAWINGS

[0010] So that the manner in which the above recited features, advantages and objects of this disclosure are attained and may be understood in detail, a more particular description, briefly summarized above, may be had by reference to the embodiments thereof which are illustrated in the appended drawings.

[0011] It is to be noted, however, that the appended drawings illustrate only typical embodiments of this disclosure and are therefore not to be considered limiting of its scope, for the disclosure may admit to other equally effective embodiments.

[0012] FIG. 1 depicts proppant size and total settling results in equivalent concentrations of the disclosed treatment fluid and an HVER fluid in accordance with the disclosed methods, structures, and compositions.

[0013] FIG. 2 depicts proppant settling results in equivalent concentrations of the disclosed treatment fluid and an HVER fluid in accordance with the disclosed methods, structures, and compositions. [0014] FIG. 3 depicts lack of proppant settling in the disclosed treatment fluid in accordance with the disclosed methods, structures, and compositions.

[0015] FIG. 4 depicts rheological test results of four different concentrations of the disclosed treatment fluid and an HVER fluid in accordance with the disclosed methods, structures, and compositions.

[0016] FIG. 5 depicts rheological test results of four different concentrations of the disclosed treatment fluid and an HVER fluid in accordance with the disclosed methods, structures, and compositions.

[0017] FIG. 6 depicts rheological test results for elastic and storage moduli of the disclosed treatment fluid in accordance with the disclosed methods, structures, and compositions.

[0018] FIG. 7 depicts the friction reduction obtained by the disclosed treatment fluid in accordance with the disclosed methods, structures, and compositions

DETAILED DESCRIPTION

[0019] Below, directional terms, such as“above,”“below,”“upper,”“lower,”“front,” “back,”“top,”“bottom,” etc., are used for convenience in referring to the accompanying drawings. In general,“above,”“upper,”“upward,”“top,” and similar terms refer to a direction away the earth’ s surface, and“below,”“lower,”“downward,”“bottom,” and similar terms refer to a direction toward the earth’ s surface, but is meant for illustrative purposes only, and the terms are not meant to limit the disclosure.

[0020] Various specific embodiments, versions and examples are described now, including exemplary embodiments and definitions that are adopted herein for purposes of understanding. While the following detailed description gives specific preferred embodiments, those skilled in the art will appreciate that these embodiments are exemplary only, and that the disclosure can be practiced in other ways. For purposes of determining infringement, the scope of the invention will refer to the any claims, including their equivalents, and elements or limitations that are equivalent to those that are recited.

[0021] Embodiments of the disclosed treatment fluid may provide the following aspects: Be able to transport the proppant agent, e.g., proppant sand or similar, into the fracture zones.

Be compatible with the formation rock and fluid.

Generate enough pressure drop along the fracture to create a wide fracture.

Minimize friction pressure losses during injection.

Be formulated using chemical additives that are approved by the local environmental regulations. Exhibit controlled-break to a low- viscosity fluid for cleanup after the treatment

Be cost-effective.

Use any kind of water (Notably, public opinion is against the use of water from public utilities as aqueducts or drilled water wells that are important for human consumption.)

[0022] The disclosed treatment fluids may be useful in a wide variety of subterranean treatment operations such as well drilling, completion, workover, and stimulation, e.g., fracturing. In industrial and oil field operations, treatment fluids are often used to carry particulates into subterranean formations for various purposes, e.g., to deliver particulates to a desired location within a well bore. Examples of subterranean operations that use such treatment fluids include servicing and completion operations such as fracturing and gravel packing. In fracturing, generally, a treatment fluid is used to carry proppant to fractures within the formation, inter alia, to maintain the integrity of those fractures to enhance the flow of desirable fluids to a well bore. In sand control operations, such as gravel packing operations, oftentimes a screen, slotted liner, or other mechanical device is placed into a portion of a wellbore. A gravel pack fluid is used to deposit particulates referred to as gravel into the annulus between the mechanical device and the formation or casing to inhibit the flow of particulates from a portion of the subterranean formation to the well bore.

[0023] This disclosed treatment fluids, which may be used in industrial and oil field operations including those having wellbores with elevated temperatures, including up to 295 °F and higher, act as gelling and rheology modifier agents and comprise, consist essentially of, or consist of natural polymer blends (a.k.a.“polymer blends” herein). The dry ingredients forming the natural polymer blend of the treatment fluid comprises, consists essentially of, or consists of any combination of biopolymers, natural flours, and/or modified, natural starches that sum a concentration from about 0.1 wt.% through about 1.0 wt.% natural polymer blend of the treatment fluid, wherein the balance of the treatment fluid is further discussed later herein. Examples of biopolymers include diutan and xanthan. Examples of natural flours include green plantain, green banana, cassava, and konjac. Examples of natural modified starches include com, rice, potato and tapioca among others. There are three different ways of modifying starch, e.g., cooking and/or roasting, which are called physical modifications, treated with enzymes and called enzymatic modifications, and/or with various chemicals called chemical modifications. Chemically modified starches, in part cellulose (polysaccharides) molecules, can be extracted from their source tuber or fruit, purified and made react with certain precursors such as carboxylic acid or lactic acid, introducing the carboxymethyl radical into the starch molecule, forming for example carboxymethyl cellulose or CMC. The amount of the natural polymer blend in the treatment fluid is largely responsible for the viscosity of the treatment fluid. Accordingly, tuning the concentration within the about 0.01 wt.% through about 1.0 wt.% range will largely determine the viscosity, such that a less viscous treatment fluid results towards the lower limit of about 0.1 wt% and a more viscous treatment fluid results towards the upper limit of about 1.0 wt.%. In some embodiments, the natural polymer blend may comprise two to ten natural polymers, in proportions such as flour polysaccharides at 0.01 - 0.15 %, biopolymers at 0.01 - 0.25 %, and modified natural starches at 0.01 - 0.60 %. As another example, the dry-weight combination of the polymer blend may be: flour polysaccharides from 0 through 90 wt.%, biopolymers at from 0 through 80 wt.%, and modified natural starches from 0 through 50 wt.%. Accordingly, one example combination from this range for the polymer blend from a dry- weight perspective would be 30 wt.% flour polysaccharides from 30 wt.% biopolymers and 60 wt.% modified natural starches.

[0024] Flours’ starting materials are usually commercial products available from several sources: tubers, fruits, and grains. Basically, the process involves slicing, drying, milling followed by pulverization of the resulting powder to produce a“flour,” which is sifted and air classified. These flours, when hydrated for some time with agitation, release encapsulated hydrocolloids to form a solution, which is characterized principally by its viscosity, even at diluted concentrations. Viscosities in the range of thousands to one hundred thousand cP at a 1% by weight solution were measured on a Brookfield^® RV2T Viscometer using a spindle RV # 2 at 0.3 rpm.

[0025] Mixing during lab testing of the polymer blend (ppb equivalent/g per final volume of 350 ml) may be done for either its dry powder or a suspension of the same in mineral oil. Oil suspensions prepared in viscosified mineral oil may have a proportion of < 45-47 wt. % active solids, /._<?., < 50 wt.%. Mixing may be performed at high shear rate, e.g. , 17,000 rpm, for at least 10 minutes. Calculated concentrations of any formulation are weighed in a mixing cup with 750 mL capacity (solids and water-based fluid) in a lab balance with at least 0.001 g detection. High-shear speed on a Hamilton Beach Multimixer for 5-10 minutes as mixing time was used to assure complete hydration of the blend. Density at lab room temperature by means of a 50 mL pycnometer or a field density balance. In the case of mineral oil suspension preparations, syringes with calibrated volume readings (1.00 mL +/- 0.05 mL; 5.0 mL +/- 0.1 mL and 10.0 mL +/- 0.2 mL) were used. Due to high shear rate mixing there will be bubbles formed on the fluids, so allow to stand for 30 minutes or in an ultrasonic bath for 10 minutes. Aging of prepared fluids is performed using pressurized metal cells in a roller oven at l50°F for 4-16 hours depending on the type of fluid testing. [0026] The treatment fluids may further include an aqueous fluid, such as those discussed later herein. The treatment fluids may vary widely in density. For example, the density of the treatment fluids may range from about 8.4 pounds per gallon (“ppg”) to about 20.5 ppg and any specific range therebetween. One of ordinary skill in the art with the benefit of this disclosure will recognize the particular density that is most appropriate for a particular application. The desired density for a particular treatment fluid may depend on characteristics of the subterranean formation, including, inter alia, the hydrostatic pressure required to control the fluids of the subterranean formation during placement of the viscosified treatment fluids, and the hydrostatic pressure which will damage the subterranean formation.

[0027] In the aqueous fluid, the natural polymer blend may be a hydrophilic colloid, which tends to thicken and stabilize water-based systems by conferring on them a relatively high viscosity, generally higher than that obtained in the case of xanthan and diutan gums, for example, at temperatures at or above about 200°F, for identical concentrations of active compounds. Viscosity data show that dilute solutions, e.g., about 0.5%, may be shear-thinning and stable to at least 300°F. These viscosities illustrate, inter alia, that the above-disclosed natural polymer blends, i.e., combinations of biopolymers, natural flours, and/or modified, natural starches that sum a concentration from about 0.1 wt.% through about 1.0 wt.%, are suitable for sand suspension and transport applications.

[0028] The aqueous fluids of the disclosed treatment fluid may comprise fresh water, salt water, or a brine, i.e. , heavily saturated salt water. Other water sources may be used, including those comprising divalent or trivalent cations, e.g., magnesium, calcium, zinc, or iron brackish water. If a water source is used which contains such divalent or trivalent cations in concentrations sufficiently high to be problematic, then such divalent or trivalent salts may be removed, either by a process such as reverse osmosis, or by raising the pH of the water in order to precipitate out such divalent salts to lower the concentration of such salts in the water before the water is used.

[0029] Monovalent brines may be used, and when so, they may be of any weight. Salts may be added to the water source, inter alia, to provide a brine to produce a treatment fluid having a desired density or other characteristics. One of ordinary skill in the art with the benefit of this disclosure will recognize the particular type of salt appropriate for a particular application, given considerations such as protection of the formation, the presence or absence of reactive clays in the formation adjacent to the well bore, and the factors affecting wellhead control. [0030] A wide variety of salts may be suitable. Examples of suitable salts include, inter alia, potassium chloride, sodium bromide, ammonium chloride, cesium formate, potassium formate, sodium formate, sodium nitrate, calcium bromide, zinc bromide, sodium chloride, potassium citrate and potassium acetate. An artisan of ordinary skill with the benefit of this disclosure will recognize the appropriate concentration of a particular salt to achieve a desired density given factors such as the environmental regulations that may pertain. Also, the composition of the water used also will dictate whether and what type of salt is appropriate.

[0031] In certain embodiments, the treatment fluids may include any or all of the following in a pad or added separately for combination with the natural polymer blend: aqueous fluid, pH control additives, surfactants, breakers, bactericides, crosslinkers, fluid loss control additives, stabilizers, combinations thereof, or the like. In some instances, the treatment fluid should maintain its viscosity in a subterranean operation until that operation is completed, after which the fluid may be“broken,” i.e., its viscosity may be reduced, e.g., so as to drop particulates from the fluid into a desired location within the subterranean formation and/or to reclaim it from the subterranean formation. It is noted that rheological profiles obtained from the disclosed treatment fluids show that they are close to water’s rheological properties. As a result, backflow sometimes occurs without the necessity of using breakers.

[0032] Suitable pH control additives, in certain embodiments, may comprise bases, chelating agents, acids, or combinations of chelating agents and acids or bases. A pH control additive may be necessary to maintain the pH of the treatment fluid at a desired level, e.g., to improve the dispersion of the gelling agent in the aqueous fluid. In some instances, it may be beneficial to maintain the pH at neutral or above 7.

[0033] In some embodiments, the pH control additive may be a chelating agent. When added to the treatment fluids of the present disclosure, the chelating agent may chelate any dissolved iron that may be present in the water. The chelating may prevent free iron from crosslinking the gelling agent molecules. Crosslinking may be problematic because, inter alia, it may cause severe filtration problems. Any suitable chelating agent may be used with the present disclosure. Examples of suitable chelating agents include an anhydrous form of citric acid, nitrilotriacetic acid, hydrochloric acid, acetic acid, formic acid and any acid form of ethylenediaminetetraacetic acid (“EDTA”). One of ordinary skill in the art with the benefit of this disclosure will be able to determine the proper concentration of chelating agents for an application.

[0034] The pH control additive also may comprise a base to elevate the pH of the mixture that is formed once the polymer blend has been added to and dispersed within the treatment fluid. Elevating the pH of the mixture may be desired to disperse the gelling agent. Generally, a base may be used to elevate the pH of the mixture to greater than or equal to about 7.0. In one embodiment, a base may be used to elevate the pH of the mixture to greater than or equal to about 11. Any known base that is compatible with the polymer blend of the present invention can be used in the treatment fluids of the present invention. Examples of suitable bases include sodium hydroxide, potassium carbonate, potassium hydroxide, sodium carbonate, calcium oxide, and/or magnesium oxide.

[0035] In some embodiments, the treatment fluids may contain bactericides and/or other biocides to protect both the subterranean formation as well as the treatment fluid from attack by bacteria and/or other living organisms. Such attacks may be problematic because they may lower the viscosity of the treatment fluid, resulting in poorer performance, such as poorer sand suspension properties. An artisan of ordinary skill with the benefit of this disclosure will be able to identify a suitable bactericide and the proper concentration of such bactericide for a given application.

[0036] The treatment fluids of the present disclosure show a unique synergy that provides better performance than individual additives, using low dosages, different water sources, temperature, and pH. As previously mentioned, the natural polymer blends can be provided as a dry powder or the natural polymer blends may come as a concentrated suspension in a low BTX- (benzene, toluene, xylene) free, mineral oil solution, wherein the former is commonly used for offshore well constructions operations, coiled tubing and fracking operations. As the name suggests, the natural polymer blend provides a small environmental footprint.

[0037] For water-based, drill-in type fluid formulation for pay zones completed as open hole, loads of natural polymers, e.g., xanthan, diutan, combination thereof or otherwise, and/or control filtrate additive, e.g., modified starch, polyanionic cellulose, CMC, etc. typically takes between 5-8 ppb, /._<?., pounds per barrel or more in front of a maximum of 2.50 ppb from the present disclosure.

[0038] In addition, the polymer blend of the treatment fluids works in most types of water sources including tap water, sea water, brackish water, produced water, monovalent and divalent brines. It can be used in most types of working fluids such as drilling, completion, fracking and workover fluids. It can withstand temperatures from 250 to 300°F. Finally, the present disclosure has an important economic impact on the process of fluid selection based on performance versus cost. Less chemical additives to be used on the overall process and larger volume of proppant placement inside the fractured area for a better fracture conductivity. [0039] Rheological properties of the example treatment fluids were measured using Ofite 900 viscometer and Grace 3600 automatic viscometer. Proppant suspension testing was performed using a Turbiscan Laser Scan Diffraction System and conventional settling following time for several hours. Friction reduction testing performed with a Flow Loop as well as Anton Paar Rheometer by means of a third-party certified laboratory.

[0040] During operations in which particles’ suspension and placement is important for well productivity, i.e., proppant placement in shale microfractures, the treatment fluids of the present disclosure show excellent performance when compared to additives such as high- viscosity friction reducers (“HVFR”) which are today the standard for fracking. At equivalent concentrations of 2 through 4 GPT, i.e. , gallons per 1000 gallons, the disclosed treatment fluids can suspend loads of up to 8.00 ppg, i.e., pounds per gallon, of proppant sand and maintain the suspension for several hours to days as seen from conventional settling test in Fig. 1 and Turbiscan testing in Fig. 2 and 3. Specifically, Fig. 1 depicts results from a settling test of a treatment fluid in 30 mL tubes (i.e., mL gradations shown in typed font in vertical box) using different sizes and loads as pound of proppant sand added (“ppa”) after six hours at 73°F with a concentration of 2.00 GPT for both the treatment fluid (Polymer Blend) and HVFR to compare suspension performance. After six hours all proppant settles down totally (5 ml) in the HVFR fluid, in all proppant sizes. The treatment fluid of present disclosure keeps suspending 100 % (25 ml reference) for the 40/70 and 30/50 proppant sizes. Large proppant size of 20/40 settles in part but not totally (13 ml).

[0041] Fig. 2 depicts Turbiscan results of equivalent 3.00 GPT concentration of the polymer blend and HVFR using a load of 2.00 pound of proppant of 40/70 mesh sand. This instrument provides a dynamic view of the settling process at specific times. The X axis records any changes every 30 seconds, where a laser beam scans through a glass cell with a fluid height of 40 mm (Y axis). If proppant particles within the fluid move down or remain in place, then they can be tracked. After 1 hour and 11 minutes, HVFR fluid has settled to 10 mm and the polymer blend is still carrying a 100 % proppant at 25 mm. Temperature of l20°F was used during testing for the results depicted in Figures 2 and 3. Fig. 3 depicts Turbiscan results of polymer blend using a load of 6.00 pound of proppant of 40/70 mesh sand. This high load is held for 2 hours and 30 minutes with no settling.

[0042] The Turbiscan works by pulsing an infrared light source into glass cell sample and by measuring the amount of light that is reflected (backscattering) and the amount transmitted straight through, which can be related to the concentration of the suspension. In each scan, the sensor takes readings of backscattering and transmission every 40 mm over the entire 55 mm height of the sample vessel and by taking a series of scans over a period of time showing if suspension profile is changing because of settling. The quickest that scans can be taken is about every 30 seconds, but the interval can be set to any time greater than that.

[0043] Ofite Model 900 Viscometer is a true Couette coaxial cylinder rotational oilfield viscometer, which employs a transducer to measure the induced angle of rotation of the bob by a fluid sample. After mixed with tap water, the treatment fluid is a 23.8 ppt gel, i.e. , 1.00 ppb, it was tested using an Ofite 900 viscometer to set an initial condition of rheology, then it was aged in a roller oven for 16 hours at l50°F using a pressurized (100 psi) metal cell to simulate bottom-hole conditions. This is common practice to see the effect of aging. After cooling down, Plastic Viscosity (“PV”) of 5.4 cP and a yield point (“YP”) of 10.8 pounds/lOOft² were obtained as shown in Table 1. The rheological properties, such as plastic viscosities, gel strengths (Gel 0/10), and yield points, were measured for treatment fluid. PV is calculated by the following formula: PV = 600 rpm reading - 300 rpm reading with units in cP (centipoises). The Yield Point (Yp) is calculated by YP = 300 rpm reading - PV with units in in lb/l00ft². The gel strength Gel 0/10 (initial 0 s/lO min) is the shear stress of fluid that is measured at low shear rate after being static for a certain period (10 sec and 10 min). The gel strength is one of the important fluid properties because it demonstrates the ability to suspend solids with fluid circulation and when circulation is ceased. Its units are lb/ 100ft². According to API RP 13B, the temperature of the fluid for this test should be l20°F. Additional testing included Brookfield viscosity measurement, performed at 73 °F, using a rotation speed of 0.3 rpm with a spindle #2. Values over 15000 cP qualify a fluid as having good suspension or carrying properties. The data is attached at the end of Table 1.

Ofite 900 Viscometer @ 120°F After Mix After OR (150°F/16 h)

600 rpm (lb/lOO ft² ) 27.5 22.0

300 rpm (lb/lOO ft² ) 19.6 16.3

6 rpm (lb/lOO ft² ) 4.6 5.1

3 rpm (lb/lOO ft² ) 4.3 4.4

PV (cP) 7.2 5.4

YP (lb/lOO ft² ) 12.3 10.8

Gel 10 sec (lb/lOO ft² ) 5.1 4.8

Gel 10 min (lb/lOO ft² ) 6.3 7.8 Brookfield/spindle #2/0.3 rpm/73°F (cP) 10,300 16,270

Table 1. Rheology testing of invention polymer blend sample 23.8 ppt (1.00 ppb) by means of Ofite 900 Viscometer and Brookfield^® RV2T Viscometer

[0044] HVFR fluids may be used for fracking and delivered as a direct emulsion, whereby the water phase is a continuous phase made with mineral oil, and a specific surfactant that may generate a density about 1.000 g/mL at 20°C using 30% of active additive, /._<?., polyacrylamide.

A common unit of concentration used is gallons of additive per thousand gallons (GPT) pumped with water to make the fracking job. Comparatively, the disclosed treatment fluid is suspended as powder (/._<?., not an emulsion) in viscosified mineral oil, and just as the HVFR fluids, makes an equivalent GPT (/._<?., 1.00 ppb of the treatment fluid is equal to 2.85 GPT).

But, remarkably, and also at 1.000 g/mL at 20°C, the disclosed treatment fluid had 40% active additive, /._<?., natural polymer blends - much better suspension than the 30% by HVFR fluids.

Then 1.00 ppb of the treatment fluid is equal to 2.85 GPT.

[0045] For the 600/300/200/ 100/60/30/6/3 -rpm readings in Table 1, the sample was also placed on a Grace M3600 Automatic Viscometer platform with bob Bl, rotor Rl and the speed was adjusted to each rpm. The above-mentioned, Grace instrument enables users to create test sequences and record test data without the use of external equipment. It can also be connected to a Microsoft Windows PC with a dedicated software for advanced test operations, test results analysis, and to export test data in spreadsheet format. After readings are allowed to stabilize, viscosity (cP) and the shear stress (lb/lOO ft²) values were read from the dial and recorded as rpm dial reading (DR). This procedure is performed automatically using the instrument software routine API RP 13B (American Petroleum Institute Recommended Practice 13 B).

[0046] HVFR fluids using the above-mentioned, Grace instrument have viscosity readings of 23.69 to 43.47 cP at l20°F and 300 rpm, as shown in Table 2, and thereby pass the criteria required for good proppant suspension in fracking field operations, whereby a more viscous fluid will carry more proppant according to Stokes Law. The equivalent 300 rpm values from 7.44 to 20.45 cP obtained for the disclosed treatment fluid would suggest that it does not have good suspension properties. However, that is untrue. Polymer blends in the disclosed treatment fluid forms a thinner fluid with a higher suspension capacity as compared to HVFR fluids. For instance, at 3.00 GPT, the Turbiscan testing results illustrated in Fig. 2 show that the HVFR fluid does not hold the 40/70 proppant although the disclosed treatment fluid does.

Table 2. Rheology testing of HVFR and natural polymer blend sample with concentrations from 2- 4 GPT by means of Grace 3600 automatic viscometer

[0047] Figure 4 shows test results from the Grace 3600 rheology test on a treatment fluid with four different concentrations in GPT of polymer blend as compared to HVFR fluids (/._<?.,

HVFR’s are high- viscosity polyacrylamides), which are used as friction reducers that help to fracture rocks using only water (slick water frack). This chemistry uses direct emulsions as part of their components. This means they need an emulsion breaker (surfactant) besides the viscosity breaker (oxidizers). There is a clear trend in fracking operations to increase viscosity on them, but suspension testing results found on the tested sample are not convincing. Tap water was the base fluid at a temperature of l20°F and pressure of 1 atmosphere. The graphs in Fig. 4 clearly show that the disclosed polymer blend treatment fluid shows a power law fluid behavior and has a lower viscosity profile than the HVFR. Figure 5 shows the same polymer blend and HVFR treatment fluids that were used in Figure 4, but this time shear rate is on the ordinate to reveal that the polymer blend treatment fluids have lower viscosity at higher shear rates when compared to HVFR fluids that indicate shear thinning properties.

[0048] An Anton Paar MCR501 rheometer was used for specific rheological measurements of elastic and storage moduli, such as those shown in Fig. 6, at temperatures of l50/200/250°F.

The viscosity was measured using Couette geometry. The bob has a diameter of 26.663 mm, and the inner diameter of the measuring cup is 28.92 mm. The rheometer is equipped with the Peltier system, which can adjust temperatures from 40 to 400°F. Fig. 6 shows the variation of G’ (storage modulus) and G” (loss modulus) as a function of frequency at the temperatures mentioned for a polymer blend sample of 17.85 ppt linear gel (0.75 ppb) prepared with water using the Anton Paar MCR501 rheometer. This graphic demonstrates that this polymer blend sample - just as all the disclosed polymer blends as treatment blends do at l50/200/250°F over the depicted frequency range - formed strong gels as G’ (elastic modulus) was greater than G” (viscous modulus) throughout the frequency range. The crossover phenomenon usually found in other polymer systems was not observed within the frequency testing range of the instrument. Presumably the amylose chains present in the continuous phase have formed a 3D network; therefore, gel behavior is expected. This result suggests a very thin fluid, i.e., very low viscosity, with high suspension properties due to the structure of a permanent gel.

[0049] Without the addition of a friction reducer, the disclosed treatment fluids also provide up to 80 % friction reduction and lower limits of 50%, i.e., just like the friction reduction obtained with typical high viscosity friction reducers in treatment fluids known in the art. Sample fluid was pumped from the tank through the test pipe at designated flow rates, and a pressure drop was measured using pressure transducers and compared to the theoretical pressure drop of water. In Fig. 7, the flow loop test was performed on the same polymer blend sample used for Figure 6, i.e., a 17.85 ppt linear gel (0.75 ppb), run through a 3/8” tubing. It takes 2.5 minutes (150 seconds) to obtain full hydration, starting in point (a) and maximum friction reduction of 80% as shown in point (b). After injection, it took 24 seconds to start hydration. Polyacrylamides as direct emulsions reach their maximum hydration and friction reduction in 30 seconds. This delay observed in the polymer blend treatment fluids can be overcome using fast hydration mechanical units in the field or by chemical additives such as surfactants or even low doses of conventional polyamide suspensions (not emulsions) in mineral oil. A point here is that the disclosed treatment fluids provide the same friction reduction as those in art, but the disclosed treatment fluids require a couple of more minutes to do so. In order to reduce that time and still achieve the same results, addition of up to 4 wt.% of friction reducer is possible if desired.

[0050] Below are example embodiments of the disclosed composition in claim form:

1. A composition comprising:

a polymer blend consisting of 0 to 90 wt.% of flour polysaccharides, 0 to 80 wt. % of biopolymers, and 0 to 50 wt.% of modified natural starches,

wherein the polymer blend is capable of being suspended for carrying proppants. 2. The composition of claim 1, further comprising an aqueous fluid and optionally pH control additives, surfactants, breakers, bactericides, crosslinkers, fluid loss control additives, stabilizers, friction reducers or combinations thereof.

3. The composition of claim 2, wherein the aqueous fluid is salt water.

4. The composition of claim 2, wherein the aqueous fluid comprises multivalent cations.

5. The composition of claim 2, wherein the composition comprises the friction reducers at a concentration of 4 wt% or less.

6. The composition of claim 2, wherein a concentration of the polymer blend in the aqueous fluid is within a range from 0.1 wt% through 1.0 wt.%.

7. The composition of claim 2, wherein density of the composition is within a range from 8.4 ppg through 20.5 ppg.

8. The composition of claim 1 , wherein the polymer blend is suspended as a powder in mineral oil to form a suspension.

9. The composition of claim 1, wherein concentration of the polymer blend in the mineral oil is < 50 wt%.

10. The composition of claim 2, wherein the composition is a treatment fluid that withstands temperatures < 300°F.

11. The composition of claim 2, wherein < 8 ppa of 40/70 proppant sand remains suspended in a 2 gpt concentration of the composition at 73°F for at least six hours.

12. The composition of claim 2, wherein < 8 ppa of 30/50 proppant sand remains suspended in a 2 gpt concentration of the composition at 73°F for at least six hours.

13. The composition of claim 2, wherein a 2 ppa of 40/70 proppant sand remains suspended in a 3 gpt concentration of the composition at l20°F for at least an hour.

14. The composition of claim 2, wherein a 6 ppa of 40/70 proppant sand remains suspended in a 2.62 gpt concentration of the composition at l20°F for at least two-and-a-half hours.

15. The composition of claim 13, wherein the composition has a viscosity of < 20 cP at l20°F at 300 rpm.

16. The composition of claim 13, wherein the composition has a shear rate of less than 200 per second.

17. The composition of claim 2, wherein the composition has an elastic modulus greater than its storage modulus at l50°F, 200°F and 250°F over a frequency range from 0.1 through 100 rad/s.

18. The composition of claim 2, wherein the composition provides > 50% friction reduction without using friction reducers. 19. The composition of claim 18, wherein the composition provides up to 80% friction reduction without using friction reducers.

20. The composition of claim 2, wherein the polymer blend is a hydrophilic colloid.

[0051] While the foregoing is directed to example embodiments of the disclosed invention, other and further embodiments may be devised without departing from the basic scope thereof, wherein the scope of the disclosed compositions, methods and systems are determined by one or more claims.

Claims

CLAIMS What is claimed is:

1. A composition comprising:

a polymer blend consisting of 0 to 90 wt.% of flour polysaccharides, 0 to 80 wt.% of biopolymers, and 0 to 50 wt.% of modified natural starches,

wherein the polymer blend is capable of being suspended for carrying proppants.

2. The composition of claim 1, further comprising an aqueous fluid and optionally pH control additives, surfactants, breakers, bactericides, crosslinkers, fluid loss control additives, stabilizers, friction reducers or combinations thereof.

3. The composition of claim 2, wherein the aqueous fluid is salt water.

18. The composition of claim 2, wherein the composition provides > 50% friction reduction without using friction reducers.

19. The composition of claim 18, wherein the composition provides up to 80% friction reduction without using friction reducers.