Fracturing method using low-viscosity fluid with low proppant settling rate

Abstract

A fluid design with enhanced proppant-carrying capacity utilizes a low-viscosity fluid with high proppant carrying capacity and low required power for injection into a hydrocarbon-bearing, subterranean formation. A preferred viscosifying agent that comprises a copolymer polymerized from an acrylic acid monomer and a monomer selected from: a) at least one carboxylic acid monomer; b) at least one C.sub.1 to C.sub.5 alkyl ester and/or at least one C.sub.1 to C.sub.5 hydroxyalkyl ester of acrylic acid or methacrylic acid; c) one crosslinking monomer; and optionally d) at least one α,β-ethylenically unsaturated monomer, may be used to produce a fracturing fluid that has the pumpability of a slick water fluid and the proppant-carrying ability of a cross-linked gel. An optimization process to optimize hydraulic fracture design evaluates and quantifies the proppant-carrying capacity of the invented fluid and its impact in the proppant transport during fracturing.

Claims

1. A hydraulic fracturing system, comprising: a base carrier fluid; a viscosifying agent added to the base carrier fluid, the viscosifying agent comprising a copolymer polymerized using two different monomers, wherein a molecular weight of the copolymer is about 1×10.sup.9 Daltons, wherein a first of the two different monomers is an acrylic acid monomer, and wherein a second of the two different monomers is selected from the group consisting of: a) a carboxylic acid monomer, b) a C.sub.1 to C.sub.5 alkyl ester and/or a C.sub.1 to C.sub.5 hydroxyalkyl ester of acrylic acid or methacrylic acid, and c) a crosslinking monomer; and a proppant suspended in the base carrier fluid having the viscosifying agent, wherein the base fluid having the viscosifying agent comprises: a viscosity of 20 cP to 150 cP at ambient temperature at 511 1/s with R1:B1 bob configuration and equivalent viscosity with R1:B5 and R1:B2 configurations; a pumpability of as much as 60 bbl/minute; and a proppant-carrying capacity to carry the proppant at a concentration ranging from 0.1 lb/gl to 20 lbs/gl and suspending behavior greater than that of a 1000-cP system.

2. A method to hydraulically fracture a formation, the method comprising: suspending a proppant in a fracturing fluid comprising a base carrier fluid and a viscosifying agent, the viscosifying agent comprising a copolymer polymerized using two different monomers, wherein a molecular weight of the copolymer is about 1×10.sup.9 Daltons, wherein a first of the two different monomers is an acrylic acid monomer, and wherein a second of the two different monomers is selected from the group consisting of: a) a carboxylic acid monomer, b) a C.sub.1 to C.sub.5 alkyl ester and/or a C.sub.1 to C.sub.5 hydroxyalkyl ester of acrylic acid or methacrylic acid, and c) a crosslinking monomer, wherein the fracturing fluid with the viscosifying agent comprises: a viscosity of 20 cP to 150 cP at ambient temperature at 511 1/s with R1:B1 bob configuration and equivalent viscosity with R1:B5 and R1:B2 configurations; a pumpability at least as great as 60 bbl/minute; and a proppant-carrying capacity to carry the proppant at a concentration ranging from 0.1 lb/gl to 20 lbs/gl and suspending behavior greater than that of a 1000-cP system; and injecting the fracturing fluid, comprising the viscosifying agent and the suspended proppant, into the formation in a fracturing operation.

3. The method of claim 2 wherein the carboxylic acid monomer is selected from the group consisting of acrylic acid, methacrylic acid, itaconic acid, fumaric acid, crotonic acid, aconitic acid, maleic acid, and combinations thereof.

4. The method of claim 2 wherein the carboxylic acid monomer comprises about 20% to about 80% by weight of the copolymer.

5. The method of claim 2 wherein the C.sub.1 to C.sub.5 alkyl ester and/or a C.sub.1 to C.sub.5 hydroxyalkyl ester of acrylic acid or methacrylic acid comprises about 80% to about 15% by weight of the copolymer.

6. The method of claim 2 wherein the C.sub.1 to C.sub.5 alkyl ester is a C.sub.1 to C.sub.5 hydroxyalkyl ester of acrylic acid.

7. The method of claim 2 wherein the C.sub.1 to C.sub.5 alkyl ester is a C.sub.1 to C.sub.5 hydroxyalkyl ester of methacrylic acid.

8. The method of claim 2 wherein the crosslinking monomer comprises about 0.01% to about 5% by weight of the copolymer.

9. The method of claim 2 wherein the copolymer is a random copolymer.

10. The method of claim 2 wherein acrylic acid monomer is a predominant monomer in the copolymer.

11. The method of claim 2, further comprising: injecting a breaker into the formation; and recovering at least a portion of the fracturing fluid by flow back.

12. The method of claim 11, wherein the breaker is selected from the group consisting of an oxidative breaker, an ammonium persulfate breaker, and a peroxide breaker.

13. The method of claim 2, wherein the method comprises selecting fracturing parameters for the fracturing operation; and wherein injecting the fracturing fluid in the fracturing operation comprises delivering the fracturing fluid to the formation at the selected fracturing parameters.

14. The method of claim 13, wherein selecting the fracturing parameters comprises: selecting at least one characteristic of the fracturing fluid, a type of the proppant, a concentration of the proppant, and a pumping rate for the fracturing fluid; and performing numerical analysis to assess the proppant-carrying capacity of the fracturing fluid based on the selections.

15. The method of claim 14, wherein the at least one selected characteristic of the fracturing fluid comprises the viscosity and a density of the fracturing fluid.

16. The method of claim 13, wherein selecting the fracturing parameters comprises performing one or more simulations to one or more of: predict a hydraulic fracture propagation, a fracture height growth, and a natural fracture reactivation; model proppant transport within both main hydraulic fractures and a reactivated natural fracture network; assess proppant embedment, crush, and fracture surface closure behavior during production; and forecast production efficiency.

17. The method of claim 2 wherein the viscosifying agent further comprises at least one a,β-ethylenically unsaturated monomer.

18. The method of claim 17 wherein the at least one a, β-ethylenically unsaturated monomer is selected from the group consisting of: (i) CH.sub.2═C(R)C(O)OR.sup.1 where R is selected from hydrogen or methyl, and where R.sup.1 is selected from C.sub.6-C.sub.10 alkyl, C.sub.6 to C.sub.10 hydroxyalkyl, —(CH.sub.2).sub.2OCH.sub.2CH.sub.3, —(CH.sub.2).sub.2C(O)OH, and salts thereof; (ii) CH.sub.2═C(R)X where R is hydrogen or methyl, and where X is selected from —C.sub.6H.sub.5, —CN, —C(O)NH.sub.2, —NC.sub.4H.sub.6O, —C(O)NHC (CH.sub.3).sub.3, —C(O)N(CH.sub.3).sub.2, —C(O)NHC(CH.sub.3MCH.sub.2).sub.4CH.sub.3, —C(O)NHC(CH.sub.3).sub.2CH.sub.2S(O)(O)OH, and salts thereof; (iii) CH.sub.2═CHOC(O)R.sup.1 where R.sup.1 is a linear or branched C.sub.1-C.sub.18 alkyl; and (iv) CH.sub.2═C(R)C(O)OAOR.sup.2 where A is a divalent radical selected from —CH.sub.2CH(OH)CH.sub.2— and —CH.sub.2CH(CH.sub.2OH)—, where R is selected from hydrogen or methyl, and where R.sup.2 is an acyl residue of a linear or branched, saturated or unsaturated C.sub.10 to C.sub.22 fatty acid.

19. The method of claim 17 wherein the at least one a,β-ethylenically unsaturated monomer comprises about 1% to about 35% by weight of the copolymer.

Description

BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWING(S)

(1) FIG. 1 is a schematic, cross-sectional view of a well undergoing a typical fracturing operation.

(2) FIG. 2 is a flowchart depicting an integrated fluid-geomechanics workflow according to an embodiment of the invention.

(3) FIG. 3A is a graph showing the viscosity of certain fluids versus post-hydration time.

(4) FIGS. 3B and 3B′ are graphs showing proppant settling versus time for various fracturing fluids.

(5) FIG. 4 is a graph showing breaker profiles for various fracturing fluids as viscosity versus time.

(6) FIG. 5 is a graph showing hydration baselines for various additive concentrations as viscosity versus time.

(7) FIG. 5 is a graph showing hydration baselines for various additive concentrations as viscosity versus time.

(8) FIGS. 6A, 6A′, and 6A″ are the graphical output of a computer simulation of a fracturing operation using a conventional high-viscosity fracturing fluid.

(9) FIGS. 6B, 6B′, and 6B″ are the graphical output of a computer simulation of a fracturing operation using a conventional low-viscosity fracturing fluid.

(10) FIGS. 6C, 6C′, and 6C″ are the graphical output of a computer simulation of a fracturing operation using a fracturing fluid according to an embodiment of the invention.

(11) FIGS. 7A and 7A′ are the graphical output of a computer simulation of surface treating pressure calculations and related fracture dimensions for a fracturing fluid according to the invention used at a level of 15 lbs. of the polymer per 1000 gallons of water (PPT).

(12) FIGS. 7B and 7B′ are the graphical output of a computer simulation of surface treating pressure calculations and related fracture dimensions for a linear gel fracturing fluid system that comprises natural guar or a low-residue hydroxypropyl guar (HPG) at a level of 40 lbs. per 1000 gallons of water.

(13) FIGS. 7C and 7C′ are the graphical output of a computer simulation of surface treating pressure calculations and related fracture dimensions for a CHMPG/zirconium (carboxymethylhydroxypropyl guar gel) fracturing fluid system at a level of 40 lbs. per 1000 gallons of water.

(14) FIGS. 7D and 7D′ are the graphical output of a computer simulation of surface treating pressure calculations and related fracture dimensions for a delayed borate crosslinked fracturing fluid system at a level of 40 lbs. per 1000 gallons of water.

DETAILED DESCRIPTION OF THE INVENTION

(15) FIG. 1 illustrates a treatment system 20 according to one embodiment of the present invention for treating a formation intersected by a wellbore 10. A tubing string 12 deploys from a rig 30 into the wellbore 10. The string 12 has fracture sleeves 100A-C disposed along its length. Various packers 40 may isolate portions of the wellbore 10 into isolated zones. In general, the wellbore 10 can be an opened or cased hole, and the packers 40 may be any suitable type of packer intended to isolate portions of the wellbore into isolated zones.

(16) The fracture sleeves 100A-C on the tubing string 12 between the packers 40 are initially closed during run in, but may be opened to divert treatment fluid to the isolated zones of the surrounding formation, as discussed below. The tubing string 12 may be part of a fracture assembly, for example, having a top liner packer (not shown), a wellbore isolation valve (not shown), and other packers and sleeves (not shown) in addition to those shown. If the wellbore 10 has casing, then wellbore 10 may have casing perforations 14 at various points.

(17) As conventionally done, operators deploy a setting ball to close the wellbore isolation valve (not shown). Then, operators rig up the fracturing surface equipment at the rig 30 and pumping system 35 and pump fluid down the wellbore 10 to open a pressure-actuated sleeve (not shown) toward the end of the tubing string 12. This treats a first zone of the formation.

(18) Then, in later stages of the operation, operators selectively actuate the fracture sleeves 100A-C between the packers 40 to treat the isolated zones depicted in FIG. 1. A number of mechanisms and techniques may be used to open the fracture sleeves 100A-C. In a typical arrangement, successively dropped plugs or balls engage a respective seat in each of the fracture sleeves 100A-C and create a barrier to the zones below. Applied differential tubing pressure may then be used to shift the respective sleeve 100A-C open so that the treatment fluid may stimulate the adjacent zone. Some ball-actuated fracture sleeves may be mechanically shifted back into the closed position. This affords the operator the ability to isolate problematic sections where water influx or other unwanted egress from the formation or a previously fractured zone may take place.

(19) In treating the zones of the wellbore 10, fracture equipment of the rig 30 and pump system 35 at surface pump the treatment fluid (e.g., carrier fluid, fracture proppant, etc.) down the tubing string 12. In general, the rig 30 may have a fluid system, a launcher, and a pressure control assembly (i.e., blowout preventer, wellhead, shutoff valve, etc.). The launcher may be used to launch the plugs, such as darts, fracture balls, or other actuating devices, for opening downhole fracture sleeves 100A-C disposed on the tubing string 12. For its part, the pump system 35 includes one or more flow lines, pumps, control valves, a fluid reservoir (e.g., pit or tank), a solids separator, various sensors, stroke counters, and a proppant mixer.

(20) The industry is in need of a low-viscosity fracturing fluid option. Increasingly, operators request a high-viscosity friction reducer that offers better carrying capacity than traditional friction reducers. Although production may be gained by this approach, the models predict a major loss of proppant placement when using conventional fluids.

(21) As discussed in detail above, hydraulic fracturing is widely utilized to improve hydrocarbon productivity from permeability challenged reservoirs. During a typical hydraulic fracturing treatment, a fracturing fluid is injected into a wellbore and penetrated into a rock formation at a pressure above the formation pressure so as to create tensile open area. Following the first initiation phase, proppant is added to the fracturing fluid and injected into the newly created open area to prevent it from closing during production and also to provide conductive flow paths for hydrocarbon extraction from the target area. The overall success of the fracturing treatment and induced fracture characteristics (such as length, height, extent, and conductivity) are dependent on the rheological properties of the fracturing fluid which also influences proppant transport, distribution and mechanical behavior within the developed hydraulic fracture and/or reactivated natural fractures.

(22) Currently, high concentrations and/or high-strength proppants are typically used in the industry to minimize proppant embedment and crush and hence the fracture closure risk. However, in order to utilize high proppant concentrations and/or high-strength proppants, the rheological properties of the fracturing fluid must be carefully chosen in order to get the proppant to where it is most needed in the reservoir so as to maximize long-term production. When a low-viscosity fluid (such as slick water) is selected, the hydraulic fracture could be initiated, propagated and well-contained within the pay zone, however, high concentration and/or high-strength proppant tends to settle and accumulate on the bottom of the developed fractures which may greatly diminish the treatment efficiency. Thus, to carry a high concentration and/or high-strength proppant and provide relatively uniform distribution throughout the complex fracture network, one must use a high-viscosity fluid. Using a high-viscosity fluid may mitigate the proppant settling issue; however, it may also lead to: higher required pumping horsepower; lower propped fracture length with abnormally greater fracture height; lower conductive reservoir volume with less natural fracture reactivation; and, greater formation damage and residual guar polymer during flow back. Using a high-viscosity fluid, hydraulic fracture can readily extend out of the target zone and result in un-constrained fracture height growth. A massive portion of fracturing fluid and proppant could be sent into non-target zones and greatly decrease the treatment efficiency.

(23) In order to overcome these obvious shortcomings, the present invention provides a fluid design with optimal rheological properties that replicates slick water flowback while providing the high proppant-carrying capacity that is commonly observed in high-concentration crosslinked systems; i.e., highly viscous fluids. By utilizing such a fluid, proppant delivery into the natural fracture networks may be achieved without unacceptably high pumping horsepower which is often encountered when running conventional highly viscous fluids. In summary, in order to maximize the stimulation efficiency of a reservoir, there is a need for a fluid and a methodology that provides the ability to transport high concentration and/or high-strength proppant without having to rely on the traditional approach which uses viscosity alone as a guide for selection.

(24) Furthermore, the fluid design and proppant selection strategy should be customized and evaluated based on the local geological and formation characteristics. If engineered accurately, a fit-for-purpose fluid may well distribute the selected proppant into the fracture surface, which may sustain closure stresses by reducing embedment and/or crush risk, and result in longer effective fracture length(s) and larger conductive reservoir volume with enhanced conductivity and hence production. Thus, there is a need for an integrated geo-mechanics-fluid workflow that is capable of providing an optimized design and/or evaluating and improving existing designs based on the reservoir properties and instrument limitations by iteratively optimizing relevant aspects/controls (such as fluid design, proppant type, pumping schedule) of a fracturing operation.

(25) In the past, high-viscosity fluid (greater than 800 centipoise) has been the preferred solution for increased proppant transport and reduced proppant settling. This methodology has been effective using systems such as a borate-crosslinked fluid with a polymer loading of 40 lbs. per 1000 gallons of water and offers what the industry considers a standard for low-rate pumping with high proppant transporting, 40 BPM and >5 ppg, respectively. The downside of high polymer loads of guar is that they commonly increase formation damage created in the fracturing process, typically resulting in an 86% percent regain permeability value. While this may be acceptable, additional loss of needed fracture length is commonly observed when high-viscosity fluids are utilized to carry proppant. However, greater fracture geometry width is often considered a common characteristic of high viscosity fluids. Often, with low-viscosity fluids such as linear gels and friction reducers, fracture length may be established allowing breaks into the secondary fracture and mechanical reactivation of the pre-existing natural fracture network may be enhanced due to the interaction between natural fractures and propagating hydraulic fractures. Each individual natural fracture within the fracture network can reactivate in opening, slip or a combined mode with greatly increased fracture conductivity, which allows the fracturing fluid together with proppant to be diverted from the propagating hydraulic fractures into the fracture network. However, these fluids do not offer suspending characteristics past 30 minutes under static conditions. When applied to fracture geometry, this loss of suspending ability causes proppant to fall from suspension resulting in loss of uniform proppant placement and induce early closure at the location with less proppant coverage. As for the complex fracture geometry, the loss of suspending ability may also cause blockage at the intersection between the reactivated natural fractures and hydraulic fractures, introduce additional pressure loss, and consequently reduce the proppant transport efficiency and form potential chock points with the fracture network. In instances where frac gradients are high, high-viscosity fluids are often used to allow for lower treating rates. This approach is often taken with high viscosity fluids, but added treatment pressure may be required on surface, resulting in additional pumping horsepower requirements.

(26) A secondary approach (and a more recent industry option) is the use of a high-viscosity friction reducer. As compared to guar-based systems, the viscosity of such fluids is far lower. However, proppant transport in such systems is not comparable to either alternative fluid systems or borate-crosslinked systems. When attempting to replicate the suspending properties of alternative fluid systems or borate cross-linked systems with a friction reducer, the friction reducer must be employed at a concentration that is not economically feasible and fluid compatibility (in terms of polymer actually working) suffers.

(27) There is no existing, integrated, geo-mechanics-fluid workflow that can guide and optimize the fluid design for proppant transport during fracturing operations as described below.

(28) The trend in the industry has been to obtain a high suspending characteristic fluid [as defined above] by increasing the fluid viscosity to more than 500 cP. Although this may be effective, fracture geometry may be adversely affected to a great extent. In contrast, the characteristics of a fluid according to the present invention are that of a low-viscosity system (similar to those of a linear fluid) but with suspending behavior better than even twice the weight of active polymer. Significantly, the fluid of the present invention exhibits suspending behavior greater than that of a 1000-cP system yet has an actual viscosity less than 100 cP. Reservoir concept models indicate that the fluid of the present invention may actually suspend and carry the proppant within the main hydraulic fractures as well as place proppant into reactivated natural fractures. An additional advantage of the new fluid system that is particularly needed is that the low-viscosity behavior may actually minimize the pumping horsepower requirement and improve the proppant coverage when carrying large/heavy proppant, keeping the proppant in the desired place, enhancing the conductivity of the stimulated fracture and reactivating natural fractures. With a low-viscosity fluid, the pumping horsepower required on location during a fracturing operation is lower. The high-viscosity fluids of the prior art require additional pumping horsepower on location to combat the added frictional pressure loss of high viscosity fluids such as crosslinked fluids where a viscosity no less than 200 cP may be reached on surface. This, along with other cross-linked fluids, may cause treatment rates to be reduced to compensate for the higher treatment pressure (especially when frac gradients are high). Low-viscosity fluids such as the new fluid of the present invention provide low viscosity yet more effective proppant transporting thereby keeping the proppant more effectively suspended and reducing perf bridging and proppant settling better than crosslinked fluids.

(29) Low-viscosity fluids such as high-concentration friction reducers and linear gelling agents like guar are common, but do not allow proppant to be placed as effectively in fractures as the fluid of the present invention does. In terms of injection pressure, the fluid of the present invention is consistent with a conventional low-viscosity fluid such as a friction reducer. However, it has more than double the proppant-suspending power, which mitigates proppant settling within the fracture geometry, especially within a complex fracture network.

(30) FIG. 3A illustrates the apparent viscosity of a fluid according to the invention in reference to the API 39 statement and provides a viscosity comparison of borate/guar fluid and a fluid according to the invention. It shows the viscosity versus time of DynaFrac which is a 40-lb. borate/guar system at 163° F. and that of a fluid according to the invention is shown at both room temp and at 163° F. FIG. 3A when referenced to FIGS. 3B and 3B′ illustrates that, merely because a fluid yields high viscosity, proppant settling is not necessarily improved over a low-viscosity fluid.

(31) In addition, it will be appreciated that, because of the low viscosity of a fluid according to the invention (as compared to a borate/guar system), less horsepower on surface is needed due to pumping fluid dynamics of viscosity principle.

(32) FIG. 4 shows that the new fluid of the present invention is not affected in terms of viscosity at surface temperature when breaker is introduced. Often, in guar systems and true slickwater, breaking behavior begins to occur even at surface temperature. A system according to the present invention is preferably broken with ammonium persulfate breaker.

(33) FIG. 5 illustrates making active co-polymer into a slurry form for easier field deployment and pumpability. Due to the surfactant and clay components used when making a slurry, the active co-polymer disperses more effectively into solution. This is illustrated where a 15-lb. slurry system yields a more effective viscosity than when a 20-lb dry form a/k/a co-polymer used alone. [don't see “15” in FIG. 5]

(34) Referring now to FIGS. 6A through 6C″, computer simulation results of fracturing operations using a conventional high viscosity fluid (a borate-crosslinked guar-based system), a conventional low-viscosity fluid (slickwater), and the new fluid of the present invention are shown, respectively. In FIGS. 6A through 6C″, “NF” denotes natural fractures and “HF” denotes hydraulic fractures. Proppant dispersion is shown as a “heat map” wherein red areas have a high proppant concentration and blue areas have a low proppant concentration. Green and yellow areas have intermediate proppant concentrations. The ideal solution is a low-viscosity fluid which has high proppant carrying capacity while requiring relatively low power for injection.

(35) The simulation results presented in FIGS. 6A through 6C″ are based on the use of a 3-D reservoir scale fracturing simulator to model hydraulic fracture propagation, natural fracture reactivation and proppant transport within both hydraulic fracture and reactivated natural fracture networks.

(36) State-of-the-art numerical simulations for fracturing are based on coupled Fracture Mechanics (FM) and Fluid Dynamics (FD). FM is a branch of solid mechanics that uses algorithms as well as numerical analysis to analyze (or solve) fracture propagation inquiries or problems. FM applies the theories of elasticity and plasticity to predict the rock failure behavior with respect to intrinsic mechanical properties and boundary conditions. FD is a sub discipline of fluid mechanics that may be used for simulating interactions involving fracturing fluid flow, fracture surfaces, proppant transport and boundary conditions. Fracturing fluid and proppant flow within a complex fracture network and the induced stress generated by fracture propagation and deformation are fully coupled in the 3-D reservoir scale fracturing simulator. Coupled FM and FD analysis may be used to understand and evaluate the influence of the proppant-carrying capacity of fluid and pumping strategy on the proppant transport efficiency in a complex fracture network. For example, coupled FM and FD may be used in some embodiments for optimizing the parameters affecting the proppant distribution within a developed fracture network such as, for example, injection rate, injection duration, proppant type and proppant concentration in the fluid.

(37) To evaluate and quantify the efficiency of a proppant transport process using the new fluid of the present invention, an integrated geo-mechanics workflow comprised of multiple modules may be used, as shown in FIG. 2. In general, this workflow combines quick-look analysis (i.e. candidate selection) with advanced computational models (i.e. CFD-DEM [computational fluid dynamics-discrete element method] and geo-mechanical models) to provide operational guidelines to improve proppant deliverability and maximize production. Multiple analytical and numerical models and/or modules may be combined within the framework of the workflow to assess the design efficiency and customized fluid properties of the present invention.

(38) Certain embodiments of the invention iteratively employ analytical and numerical functions and modeling, for example to run simulations and obtain the results thereof. In particular, as discussed in further detail below, specifically directed use of coupled Computational Fluid Dynamics (CFD), Discrete Element Methods (DEM), and analytical models may be used to create custom design and verify the experimental results on new fluid proppant carrying capacity characteristics.

(39) Using logs and real-time log files obtained from an actual well in Argentina, simulations of pumping rate, frac geometry, and hydraulic horsepower (HHP) requirements were performed. In each case, the new fluid according to the present invention was shown to require less HHP than other representative fracturing fluids.

(40) TABLE 1 presents simulation data using a pumping rate of 40 BPM as a baseline to provide an idea of HHP requirements at a low rate. It will be appreciated by those skilled in the art that a pumping rate of 40 BPM is not realistic for the proppant (at 5 PPG) used in actual slickwater (friction reducer) field applications. However, the new fluid is still shown to be more efficient in terms of lower hydraulic horsepower required and greater propped fracture coverage.

(41) TABLE-US-00001 TABLE 1 Frac Total Total Rate Avg. Length fract prop. Fluid PPG BPM PSI (ft.) prpL height Ht. Perf W HHP Guar 1-5 40 11,170 118.7 92.7 253.8 198.3 .304 10,950 Slickwater 1-5 40 9978 147.6 77.3 253.0 196.0 .262 9782 Borate/ 1-5 40 10,850 121.0 92.5 245.9 188.0 .336 10,637 Guar New fluid 1-5 40 9550 121.7 114.4 253.1 186.4 .312 9363

(42) The simulations presented in TABLE 2 applied what would be the minimal pumping rate required to successfully pump a well without screening out and/or bridging off perforations. This is more so focused when linear gelled fluids and or slickwater fluids are applied (both were considered in determining pumping rate, with an error factor of 10%).

(43) TABLE-US-00002 TABLE 2 Frac Total Total Rate Avg. Length Frac prop. Fluid PPG BPM PSI (ft.) prpL height Ht. Perf W HHP Guar 1-5 60 12,982 125.1 92.9 267.1 198.3 .418 19,091 Slickwater 1-5 90 12,444 127.2 93.2 275.0 201.5 .466 27,449 Borate/ 1-5 55 12,267 121.4 90.3 255.0 190.0 .650 16,536 Guar New fluid 1-5 45 10,529 123.0 118.5 258.4 198.0 .314 11,613

(44) The simulations presented in TABLE 3 utilized the actual pump schedule that would likely be used with the new fluid. Inasmuch as the job being modeled required a low rate and high proppant amounts to pump proppant away, slickwater was not considered. At 5 ppg, proppant is falling quicker than fluid at 60 BPM. Use of the new fluid according to the present invention is shown to reduce required HHP by the equivalent of two trucks having skid-mounted pumps and the equivalent of four trucks having body-loaded pumps.

(45) TABLE-US-00003 TABLE 3 Fracture Total Total Rate Length frac prop. Perf Fluid PPG BPM Avg. PSI (ft.) prpL height height width HHP Guar 1-5 60 12,907 180.4 161.8 295.6 265.3 0.728 18,980 MF 40 1-5 60 13,317 151.1 137.4 310.7 282.6 0.895 19,584 DF 40 1-5 60 12,790 162.3 146.5 310.7 280.6 0.798 18,808 New fluid 1-5 60 10,853 184.2 161.6 294.0 257.9 0.720 15,960

(46) In the above tables, the following abbreviations are used: prpL=propped Frac Length (in feet) ttl Frac Ht=Total Frac Height (in feet) ttl prpHt=Total Propped Frac Height (in feet) Perf W=Perforation width (in feet) HHP=Hydraulic Horsepower DF=DynaFrac® delayed borate crosslinked fluid and additives [WEATHERFORD TECHNOLOGY HOLDINGS, LLC 2000, ST. JAMES PL., HOUSTON, TEXAS 77056] (GuarHPG/borate crosslink) MF=a CMHPG/zirconium crosslinked fluid Guar=Standard linear fluid, e.g. AquaVis® water-soluble polymers [HERCULES LLC, 500 HERCULES ROAD, WILMINGTON, DELAWARE 19808]

(47) FIGS. 7A through 7D″ are graphical representations from simulations of surface pressure, net pressure, wellbore friction, fracture length, fracture upper height, fracture lower height, and the maximum width of fracture at wellbore versus time for various convention fracturing fluids and the new fluid of the present invention.

(48) Current numerical simulations for particle settling analysis are based on coupled Computational Fluid Dynamics (CFD) and Discrete Element Methods (DEMs). CFD is a branch of fluid mechanics using algorithms as well as numerical analysis to analyze (or solve) fluid flow inquiries or problems. CFD is a computer-based mechanism for making calculations to simulate interactions involving liquids, gases, surfaces, and boundary conditions. DEM belongs to a well-known family of numerical methods used to compute particle motion and interaction. These models may be used to better design and calibrate against particle settling experiments. In many embodiments, coupled CFD and DEM analysis may be used to understand and evaluate the proppant carrying capacity of a certain fluid. For example, coupled CFD and DEMs may be used in some embodiments for optimizing the parameters affecting proppant settling properties such as, for example, proppant size, proppant density, and proppant concentration (in the fluid). However, it should be appreciated that the method may be generalized to any proppant and any fluid to optimize the parameters that affect proppant settling.

(49) The workflow may start with a candidate ranking and selection module to ensure that correct wells and/or stages are ranked and chosen for hydraulic fracturing. This module may contain input data collection and quick-look analysis to compare and contrast fracture potential between multiple well(s) or well stage(s). The input data may be collected from multiple sources, including core samples, log data and field data. The collected data and/or attributes may include reservoir characteristics (e.g., depth, pore pressure gradient, porosity, permeability, TOC, water saturation) and the geo-mechanical properties of the play (e.g., Young's modulus, Poisson's ratio, rock strength, cohesion and shmin gradient (minimum horizontal in-situ stress)), which may be ranked and integrated to predict the fracture potential.

(50) Once the most viable candidate wells and/or stages are chosen, experiments and/or numerical analysis may be conducted to quantify and assess the proppant-carrying capacity of the fracturing fluid of the present invention using the fluid and proppant design module. The available experimental and/or field test results may also be utilized to calibrate the numerical small-scale engine (e.g., CFD & DEM) for any future analysis, which may result in cost savings. With the aid of the numerical model, or by actual experiments and/or field tests, the fluid properties (viscosity, density, and proppant carrying capacity), proppant type and concentration may be modified and/or re-designed in order to achieve higher proppant carrying capacity, lower proppant settling, and appropriate stability of the fluid based on the specific reservoir and injection conditions. This process may be repeated until an optimized fluid and proppant design is obtained, which may be further analyzed in the fracture design module using an advanced geo-mechanical and production model.

(51) The fracture design module may first simulate proppant transport using the fluid and proppant properties exported from the previous analysis and may quantify proppant coverage and distribution using an advanced geo-mechanical model. The geo-mechanical analysis may model hydraulic fracture propagation, fracture height growth, natural fracture reactivation, and proppant transport within both hydraulic fractures and reactivated natural fracture networks. The geo-mechanical model may also simulate proppant mechanical deformation (both embedment and crush) and the resulting fracture closure behavior during production to quantify conductivity reservoir volume for production analysis. The relevant mechanical properties and behavior of the chosen proppant type are preferably calibrated through related experimental work and implemented into the numerical models.

(52) The workflow may include production prediction to evaluate any proposed or existing design for a specific formation. If the predicted production falls below the target value or an economically viable level, the analysis module may adjust the engineering design parameters and/or controls such as fluid property, proppant type, injection rate, pumping schedule, etc. (which, in an embodiment, includes an emphasis on the proppant-carrying properties of the fluid of the present invention) and iteratively rerun the fluid and proppant design module and the fracture design module until obtaining an improved and/or optimized design. Once an acceptably optimized engineering design is obtained, the analysis module may output design parameters for use in customizing the fluid properties of the present invention and to guide the field operations so as to maximize production.

(53) A fluid according to the present invention allows proppant to be placed into fractures more efficiently than conventional fracturing with low-viscosity properties. This provides higher proppant carrying capacity within the fracture system (main hydraulic fracture and activated natural fractures). In addition, it minimizes the pumping horsepower requirement by minimizing the fluid viscosity. Moreover, lower fluid viscosity results in less wellbore damage and reduced residual polymer within the formation by increasing the regain permeability (e.g., increasing to 96.5 md from 85 md when compared equally at a 20-lb. concentration). The fluid system of the present invention does not depend upon inherent viscosity to suspend and transport proppant. A fluid that utilizes a three-dimensional proppant-suspending mechanism in a relatively low-viscosity environment may be made using polyacrylamide polymers that are functionalized via synthesis using a free-radical micellar polymerization method with low amounts of anionic long-chain alkyl, sodium 9- (and 10-) acrylamidostearate with AMPS, sodium dodecyl sulfate, vinyl pyrrolidone, hydroxyethyl acrylate and/or ionizable carboxylic groups depending upon the desired final fluid rheological properties and brine compatibilities. For some versions of the fluid, minor amounts of other mono-functional or poly-functional monomers including styrene, vinyl toluene, butyl acrylate, methyl methacrylate, vinylidene chloride, vinyl acetate and the like may also be added to the backbone of the main polymer once the water solubility of the polymer is assured.

(54) In addition, the fluid system of the present invention may be optimized using an integrated geo-mechanical-fluid flow workflow. Multiple scales of both analytical and numerical models may be set up and utilized in the workflow to assess the proppant carrying capacity of the fluid of the present invention and ensure the success of utilizing the fluid of the present invention. The fluid of the present invention design methodology may be customized and flexible based on available experimental data, reservoir condition, proppant type and user-specific requirements to enhance the proppant carrying capacity while lowering the required pumping horsepower for injection. The fluid design may be coupled with reservoir-scale fracture simulations. By comparing and contrasting different design plans, the proppant settling, embedment and crush may be minimized so as to enhance the proppant coverage and conductive reservoir volume within the framework of the workflow. In such a way, the engineering parameters, including fluid properties, proppant type and pumping schedule, may be iteratively optimized to enhance the proppant-carrying efficiency of the fluid of the present invention and hence the overall production. The ultimate decision on the fluid design strategy for a successful hydraulic fracture treatment should be assessed within the local geological condition by using the integrated workflow for thorough evaluation. Thus, the engineering fluid design and pumping schedule may be customized based on data unique to different formations.

(55) An exemplary viscosifying agent according to one embodiment of the invention is product that comprises a copolymer that has been polymerized using two separate monomers—the first being an acrylic acid monomer and the second comprising a monomer selected from; a) about 20% to about 80% by weight of at least one carboxylic acid monomer comprising acrylic acid, methacrylic acid, itaconic acid, fumaric acid, crotonic acid, aconitic acid, or maleic acid, or combinations thereof; b) about 80% to about 15% by weight of at least one C.sub.1 to C.sub.5 alkyl ester and/or at least one C.sub.1 to C.sub.5 hydroxyalkyl ester of acrylic acid or methacrylic acid; c) about 0.01% to about 5% by weight of at least one crosslinking monomer; and optionally d) about 1% to about 35% by weight of at least one α,β-ethylenically unsaturated monomer selected from; CH.sub.2═C(R)C(O)OR.sup.1 wherein R is selected from hydrogen or methyl; and R.sup.1 is selected from C.sub.6-C.sub.10 alkyl, C.sub.6 to C.sub.10 hydroxyalkyl, —(CH.sub.2).sub.2OCH.sub.2CH.sub.3, and —(CH.sub.2).sub.2C(O)OH and salts thereof. CH.sub.2═C(R)X wherein R is hydrogen or methyl; and X is selected from —C.sub.6H.sub.5, —CN, —C(O)NH.sub.2, —NC.sub.4H.sub.6O, —C(O)NHC (CH.sub.3).sub.3, —C(O)N(CH.sub.3).sub.2, —C(O)NHC(CH.sub.3MCH.sub.2).sub.4CH.sub.3, and —C(O)NHC(CH.sub.3).sub.2CH.sub.2S(O)(O)OH and salts thereof. CH.sub.2═CHOC(O)R.sup.1 wherein R.sup.1 is linear or branched C.sub.1-C.sub.18 alkyl; and CH.sub.2═C(R)C(O)OAOR.sup.2 wherein A is a divalent radical selected from —CH.sub.2CH(OH)CH.sub.2—, and CH.sub.2CH(CH.sub.2OH)—, R is selected from hydrogen or methyl, and R.sup.2 is an acyl residue of a linear or branched, saturated or unsaturated C.sub.10 to C.sub.22 fatty acid.

(56) The polymerization may be a random polymerization—i.e., although on a weight basis there is a certain, selected amount of each monomer, the order in which the monomers are arranged in the polymer backbone is not definite.

(57) In the copolymer, the predominant monomer in the polymer is preferably acrylic acid, with relatively little of the secondary monomer in the polymer. The overall MW of the copolymer may be very high, approximately 1,000,000,000 Daltons, at least 1×10.sup.9 Daltons, or greater than 1×10.sup.9 Daltons.

(58) Of course many variations may be substituted to obtain a similar effect by those skilled in the art.

(59) The foregoing presents particular embodiments of a system embodying the principles of the invention. Those skilled in the art will be able to devise alternatives and variations which, even if not explicitly disclosed herein, embody those principles and are thus within the scope of the invention. Although particular embodiments of the present invention have been shown and described, they are not intended to limit what this patent covers. One skilled in the art will understand that various changes and modifications may be made without departing from the scope of the present invention as literally and equivalently covered by the following claims.