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RELATED APPLICATIONS 
     This application is a continuation-in-part of U.S. patent application Ser. No. 13/299,288, filed Nov. 17, 2011, which is a continuation-in-part of U.S. patent application Ser. No. 12/789,177, filed May 27, 2010, which is a continuation of U.S. patent application Ser. No. 12/324,608, now U.S. Pat. No. 7,726,070, issued Jun. 1, 2010 to Thrash, which claims the benefit of U.S. Provisional Patent Application Ser. No. 61/012,912, filed on Dec. 11, 2007. 
    
    
     BACKGROUND 
     1. The Field of the Invention 
     This invention relates to oil field and oil well development, and, more particularly, to novel systems and methods for fracturing and propping fissures in oil-bearing formations to increase productivity. 
     2. The Background Art 
     Oil well development has over one hundred years of extensive engineering and chemical improvements. Various methods for stimulating production of well bores associated with an oil reservoir have been developed. For example, United States Patent Application Publication US 2009/0065253 A1 by Suarez-Rivera et al. and entitled “Method and System for Increasing Production of a Reservoir” is incorporated herein by reference in its entirety and provides a description of fracturing technology in order to increase permeability of reservoirs. Moreover, various techniques exist to further improve the fracture channels, such as by acid etching as described in U.S. Pat. No. 3,943,060, issued Mar. 9, 1976 to Martin et al., which is likewise incorporated herein by reference in its entirety. 
     In general, different types of processes require various treatments. In general, well production can be improved by fracturing formations. Fracturing is typically done by pumping a formation full of a fluid, containing a large fraction of water, and pressurizing that fluid in order to apply large surface forces to parts of the formation. These large surface forces cause stresses, and by virtue of the massive areas involved, can produce extremely high forces and stresses in the rock formations. 
     Accordingly, the rock formations tend to shatter, increasing porosity an providing space for the production oil to pass through the formation toward the bore hole for extraction. However, as the foregoing references describe, the chemistry is not simple, the energy and time required for incorporation of various materials into mixtures is time, money, energy, and other resource intensive. 
     It would be an advance in the art if such properties as viscosity, absorption, mixing, propping, and so forth could be improved by an improved composition and method for introduction. 
     Moreover, hydraulic fracturing has a rather sophisticated process for adding various constituents to the fracking fluids. Not only must proppants be added, but various other chemicals. In certain fracturing processes, it has been found important or even necessary to blend materials into the working fluid for fracturing. Such blending requires substantial equipment, occupying a very significant footprint on the overall well site. 
     Moreover, this equipment requires manpower, and maintenance of numerous receiving and storage areas. These are needed for various constituent products that will ultimately be added to the working fluid. All of these processes for mixing auxiliary materials into the fluid cause delays in time, since many of the materials require substantial mixing. 
     Particularly with small particles, surface tension tends to float such materials on the of liquids and require substantial mixing and substantial associated time. Many solids must be pre-mixed in oils, emulsions, and the like, increasing the effect of any spill. Meanwhile, addition of chemicals to a fracturing flow necessarily creates uneven distributions of additives. For example, upon addition, into the flow, a constituent is at a very high concentration near the well head. Meanwhile, none of that newly added constituent exists elsewhere. Thus, the ability to thoroughly distribute material, or to even get it distributed well throughout the fluid being introduced, has proven difficult. 
     Similarly, transportation of individual constituent chemicals and materials to the well site requires multiple vehicles specialized to different types of materials and phases. For example, some materials are fluids, some are solids, some use a water solvent, some use a petroleum-based solvent, and such materials must be hauled, delivered, and handled in distinct ways with their own suitable storage, handling, and transport equipment. 
     Various complaints have been encountered with the amount of hydrocarbons, such as various emulsions, chemical additives, including such materials as diesel fuel and the like that are often used. With such liquid chemicals on site, the risk of surface contamination due to chemical spills of such materials is increased. Even when contained in smaller containers, such materials run the risk of spills, carrying about by water, wind, and other weather, as well as the prospect of possible spilling during delivery, handling, or the feeding and mixing processes. 
     Meanwhile, the operational footprint required for storage, mixing systems, receiving, shipping, and the like increase the overall operational footprint of a well site. Moreover, money, labor, and time are substantial for the process of receiving, preparation, storage, handling, and ultimately mixing materials that will be added to a fracturing fluid. 
     Thus, it would be a substantial advance in the art to provide a system and method, and particularly a material, that would eliminate many of the handling, equipment, footprint, transportation, and other problems that exist in prior art materials and mixing systems to service fracture fluids. 
     BRIEF SUMMARY OF THE INVENTION 
     In view of the foregoing, in accordance with the invention as embodied and broadly described herein, a method, apparatus, and composition are disclosed in certain embodiments in accordance with the present invention, as including a substrate that may be formed of sand, rock product, ceramic sand, gravel, or other hard and structurally strong materials, provided with a binder to temporarily or permanently secure a hydrating polymer in proximity to the substrated. When used herein any reference to sand or proppant refers to any or all of these used in accordance with the invention. In certain embodiments of a method in accordance with the invention, a composition as described may be mixed directly into drilling fluids, such as a fracturing fluid made up of water and other additives. 
     By virtue of the increased surface area and weight provided to the polymeric powders affixed to the substrate, the surface area, and consequently the frictional drag, is greatly increased, sweeping the material of the invention into a flow of fluid. This greatly decreases the time required to absorb polymers into the fluid. 
     In fact, rather than having to wait to have the polymers thoroughly mixed, or absorb a full capacity of water, and thereby flow properly with the drilling fluid or fracturing fluid, a composition in accordance with the invention will sweep along with the fluid immediately, with the weight of the substrate submerging the polymer. Meanwhile, the cross sectional area presented results in hydrodynamic drag sweeps the composition along with the flow. 
     Meanwhile, over time, the polymeric powder adhered to the substrate will absorb water, without the necessity for the time, energy, temperature, mixing, and so forth that might otherwise be required by surface mixing. Thus, the composition in accordance with the invention is immediately transportable and flows, relying on the drilling or fracturing fluid as its carrier. 
     Moreover, as the polymer tends to pick up more water, the density of the granule of substrate and polymer powder becomes closer to the density of water. Accordingly, the size increase and the density change tend to drive the particles of the composition even more homogeneously with the flowing fluid. Thus, the sand does not settle out in various eddies, obstructions, and other locations of low velocity. Rather, the sand continues to be carried with the fluid, providing a double benefit. That is, the sand weight and area helps to initially mix and drive the particles (granules) with the fluid. Thereafter, the hydration of the polymer tends to increase the surface area and reduce the density of the granule or particle, tending to make the particles flow even better and more homogeneously with the surrounding fluid. 
     Ultimately, as the particles (granules) of the composition flow into fracture locations, they provide very small proppants as the substrate, such as sand, becomes trapped and lodged at various choke points. Nevertheless, because of the small size, the sand or other substrate acting as a proppant, simply needs to provide an offset, keeping fractured surfaces from collapsing back against one another. By providing the small, strong points of separation, the substrate provides a well distributed proppant, carried to maximum extent that the fluids will travel, and deposited in various traps, choke points, and the like. 
     The net saving in time, money, energy for heating and pumping, and the like is significant. Meanwhile, various technologies for reducing friction in the flow of fluid pumped into bore holes and other formation spaces is described in several patents, including U.S. Pat. No. 3,868,328, issued Feb. 25, 1975 to Boothe et al. and directed to friction reducing compounds, as well as U.S. Pat. No. 3,768,565, issued Oct. 30, 1973 to Persinski et al. and directed to friction reducing, U.S. Patent Application Publication US 2001/0245114 A1 by Gupta et al. directed to well servicing fluid, and U.S. Patent Application Publication US 2008/0064614 A1 by Ahrenst et al. and directed to friction reduction fluids, all described various techniques, materials, methods, and apparatus for developing, implementing, and benefiting from various well fluids. All the foregoing patent application publications and patents are hereby incorporated by reference. 
     Similarly, the development of various chemicals has been ubiquitous in oil field development. For example, U.S. Pat. No. 3,442,803, issued May 6, 1969 to Hoover et al. is directed to thickened friction reducers, discusses various chemical compositions, and is also incorporated herein by reference in its entirety. 
     In one embodiment of an apparatus, composition and method in accordance with the invention, a method may be used for formation fracturing. The formation may be in rock and within or near an oil reservoir underground. One may select an oil field region having a formation to be fractured. Fracturing may be sought to increase production. By providing a bore into the formation and a pump, a carrier material, typically comprising a liquid, and sometimes other materials dissolved or carried therein may be pumped into the formation through the bore. 
     The carrier as a liquid, or slurry comprising a liquid, or otherwise containing a liquid may be driven by the pump to be pressurized into the formation. However, the carrier may be provided an additive formed as granules. Each granule may include a substrate, such as a grain of sand, ceramic sand, crushed rock, other rock products, or the like having bonded thereto many particles (e.g., powder) formed from a polymer. 
     The polymer may be selected to have various properties, including lubricity, water absorption, water solubility, or the like. This hydrophilic polymer may be bonded permanently, temporarily, or the like to secure to the substrate. Various binders may be used alone or in combination. These may range from a solvent (e.g., organic or water) simply softening the polymer itself to bond it, to glues, sugars, molasses, and various other saccharides, as well as other products, including starches, other polymers, and so forth. 
     Thus, with some bonds, the polymer powder may be less permanent or attached to have a bond that is less robust. Over time, the polymer powder so attached may wear off, pull away, or otherwise remove from the substrate into the carrier fluid, and may even act as a viscous agent, lubricant, or the like in the carrier. 
     The method may include introducing the additive directly into the carrier. The more dense substrate will immediately submerge the granules in the carrier at ambient conditions. Thus heating, extensive mixing, waiting, and the like may be dispensed with, as the granules typically will not float or resist mixing once initial surface tension is broken. 
     Pumping the carrier toward the formation is possible immediately. The carrier fluid carries the granules by the liquid dragging against the substrate (with the particles of polymer attached. The substrate&#39;s cross sectional area engages immediately the surrounding liquid, dragging it into the carrier to flow substantially immediately therewith. 
     Meanwhile, weighting, by the substrate of the polymer, permits the granules to flow into and with the carrier independently from absorption of any of the liquid into the polymer. Nevertheless, over time, absorbing by the polymer a portion of the liquid results in the polymer expanding and providing by the polymer, lubricity to the carrier with respect to the formation; 
     Creating fractures may be accomplished by pressurizing the carrier in the formation. This creates fissures or fractures. Thus, flowing of the carrier and particles throughout the fractures or fissures in the formation results in lodging, by the particles, within those fractures or fissures. Unable to re-align, adjacent surfaces of rock, now fracture cannot close back together due to propping open the fractures by the substrate granules lodging in the fractures. 
     The substrate is best if selected from an inorganic material, such as sand, ceramic sand, or other hard, strong, rock product. The polymer may be selected from natural or synthetically formulated polymers. For example polymers of at acrylic acid, acrylate, and various amides are available. Polyacrylamide has been demonstrated suitable for all properties discussed above. 
     In fracturing a rock formation, the method may include providing an additive comprising a substrate formed as granules, each having an exterior surface, particles formed of a hydrophilic material, the particles being comminuted to a size smaller than the size of the granules and having first and second sides comprising surfaces. The granules may each be coated with the particles, the particles being dry and bonded to the exterior surface by any suitable binder, including the polymer softened with a solvent. The particles are each secured by the first side to the granules, the second side extending radially outward therefrom. 
     Upon identifying a reservoir, typically far underground from thousands of feet to miles, perhaps, and extending in a formation of rock, one needs to provide a bore into the formation. Providing a carrier, comprising a liquid, and possibly other materials known in the art, is for the purpose of fracturing the formation. Introducing the additive directly into the liquid at ambient conditions is possible, because the substrate weighs the granules down, and there is no need for long mixing, heating or the like as in addition of polymers directly to the carrier. 
     Thus, pumping may continue or begin immediately to move the carrier and additive down the bore and toward the formation. This results in exposing the second sides of the polymer powder particles directly to the liquid during transit of the carrier and additive toward and into the formation. The polymer particles thus begin absorbing, a portion of the liquid, typically principally water. Swelling of the polymer increases the size, effective diameter, and cross-sectional area, thus increasing the fluid drag on the granules. 
     Fracturing, typically by hydraulic pressure in the carrier creates fissures in the formation by fracturing the rock pieces in bending, or by layer separation, with tensile stresses breaking the rock. The resulting fissures allow carrying, by the carrier, of the granules into the fissures. However, fissures vary in size and path, resulting in lodging of granules, within the fissures. The granules do not settle out from the carrier, and thus may travel far into the formation and every fissure. However, each time a grain or granule is lodged like a chock stone, it obstructs the ability of the adjacent rock surfaces to close back with one another. 
     Thus, rather than the proppant (substrate) settling out ineffectually, failing to prop open the fissures, the granules are swept forcefully with the flow of the carrier wherever the carrier can flow, until lodged. Meanwhile, the lubricity of the polymer aids the granules, and thus the substrate from being slowed, trapped, or settled out by the slow flowing boundary layer at the solid wall bounding the flow. 
     In summary, weighting, by the substrate, sinks the polymer into the carrier readily and independently from absorption of the liquid into the polymer. Mixing, dissolving, and so forth are unnecessary, as the substrate drags the polymer into the carrier, and the carrier drags the granule along with it in its flow path. Lubrication is provided by the polymer between the substrate of each granule and adjacent solid walls of the bore, passages previously existing in the formation, and the fissures formed by fracturing. Any separating, by some of the powdered polymer particles from the substrate, still reduces friction drag on passage of the carrier and particles within the formation. 
     A composition for fracturing and propping a formation of rock may include a fluid operating as a carrier to be pumped into a rock formation, a substrate comprising granules of an inorganic material, each granule having an outer surface and a size characterized by a maximum dimension thereacross, and all the granules together having an average maximum dimension corresponding thereto. A polymer comprising a hydrophilic material selected to absorb water in an amount greater than the weight thereof may be bound to the substrate. The polymer is comminuted to particles, each particle having a size characterized by a maximum dimension thereacross. 
     All the polymer particles may be characterized by an average maximum dimension, and an effective (e.g., hydraulic diameter). The average maximum dimension of the particles is best if smaller, preferably much smaller, than the average maximum dimension of the granules. 
     The particles of the polymer, bound to the substrate, will travel with it in the fluid. Particles of the polymer are thus further directly exposed to water in the fluid during travel with the fluid. The granules, flowing in the fluid, are carried by the hydrodynamic drag of the fluid against the cross-sectional area of the granules coated with the particles of the polymer. The polymer, selected to expand by absorbing water directly from the fluid, increases the area and drag, assisting distribution in the formation by the carrier fluid. The polymer meanwhile operates as a lubricant lubricating the motion of the substrate against the formation during flow of the granules against solid surfaces in the formation, bore, and fracture fissures. 
     The inorganic material, such as sand, ceramic sand, or the like is typically sized to lodge in fissures formed in the formation and has mechanical properties rendering it a proppant capable of holding open fissures formed in the formation. In certain embodiments, a water soluble binder is used, then a substrate may release additives into the fracturing fluid quickly or slowly after insertion in the working fluid. 
     A substrate may perform as a proppant, and may be constituted of sand, ceramic, another rock or mineral product, a resin coated, or other material used to prop open fractures. Such a substrate may be provided with a binder securing powdered components of suitable additives to be introduced into a fracturing fluid. 
     For example, a friction reducer, biocide, oxygen scavenger, clay stabilizer, scale inhibitor, gelling agent, or the like may be included in a mix, or as an element to be adhered to a substrate proppant. The substrate thereby forms particles that will easily be drawn into a flow of fracturing fluid, thus introducing all the necessary constituents into the flow. This occurs rapidly, without having to wait for mixing to occur topside on the site before introduction into the bore. Rather, mixing can take place and hydration or distribution in the flow may take place on the fly as the flow of fluid courses through the bore toward the formation. Thus, the preparation and introduction time on the surface at the well site is minimized. 
     In certain embodiments, the composition may be mixed directly into the fluid to form a complete and suitable fracturing fluid with all the necessary additives desired. By adhering chemicals to the proppant as the operable substrate, in the correct ratios, elaborate mixing ratios and elaborate mixing processes, and control thereof, as well as their related equipment, personnel, time, storage, and handling are greatly reduced, and optimally eliminated. Thus, the operational footprint of a service company on the well site is reduced, as well as the time, cost, labor, and so forth required to measure, add, mix, and otherwise introduce desired chemical constituents into the fracturing fluid. 
     By coating a proppant or substrate with the suitable materials (e.g., chemicals, etc.) an even mix of chemicals is maintained within the fracturing fluid much more easily. Moreover, distribution thereof within the flow is straightforward. In fact, all those additives may thereby all be present in exactly the proper ratios at all times at the time they are introduced. Thus, adding them one at a time, working with them to try to get them all introduced at about the same time, and so forth, as encountered in the prior art is no longer a problem. 
     Because many or all desired constituents may be coated onto a single substrate  12 , or each granule of a single substrate, then numerous constituents, including previously dissolved liquids or solids that have been rendered liquid by introduction into solvents, in order to ensure more rapid mixing, may be reduced or eliminated. Thus the full array of constituent chemicals to be used as additives in the fluid may be provided with proppants in the delivery of a single material, granular in nature, solid in phase, and simple to be stored, transported, handled, and the like. Thus, emissions, spills, other environmental risks, may be reduced or eliminated. 
     By using powdered base chemicals, the carriers or solvents that were previously needed, often hydrocarbon based emulsions and the like, may be eliminated. Thus, the risk of surface spills and consequent contamination may be reduced or eliminated. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The foregoing features of the present invention will become more fully apparent from the following description and appended claims, taken in conjunction with the accompanying drawings. Understanding that these drawings depict only typical embodiments of the invention and are, therefore, not to be considered limiting of its scope, the invention will be described with additional specificity and detail through use of the accompanying drawings in which: 
         FIG. 1  is a schematic cross-sectional view of a material including a substrate provided with a binder securing a hydrating polymer thereto in accordance with the invention; 
         FIG. 2  is a schematic block diagram of one embodiment of a process for formulating and producing fluid additive particles in accordance with the invention; 
         FIG. 3  is a schematic diagram of the fluid-particle interaction in an apparatus, composition, and method in accordance with the invention; 
         FIG. 4  is a chart illustrating qualitatively the relationship between volumetric increase over time at various temperatures, illustrating the improved activation with minimum mixing and temperature increase of particles in accordance with the invention; 
         FIG. 5  is a schematic diagram illustrating one embodiment of friction reducing by polymers used in compositions in accordance with the invention; 
         FIG. 6A  is a schematic diagram of the fracturing and proppant action of particles in accordance with a method and composition according to the invention; 
         FIG. 6B  is a schematic diagram illustrating a collection of proppant particles positioning rock fragments in a formation away from one another in order to maintain open passages in the formation; 
         FIG. 7  is a schematic block diagram of a fracturing and propping process using compositions and methods in accordance with the invention 
         FIG. 8  is a schematic diagram of processes illustrating alternative options for coating, in which particles being adhered to the binder layer may be added sequentially or simultaneously by species or constituent particles; 
         FIG. 9  is a schematic diagram of an alternative coating process in which multiple binding layers are added over previous binding layers and layers of particles; and 
         FIG. 10  is a schematic block diagram of some alternative coating processes, including direct coating, sequentially adding particular constituents, and sequentially adding binder and particulate constituents to the particles. 
     
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS 
     It will be readily understood that the components of the present invention, as generally described and illustrated in the drawings herein, could be arranged and designed in a wide variety of different configurations. Thus, the following more detailed description of the embodiments of the system and method of the present invention, as represented in the drawings, is not intended to limit the scope of the invention, as claimed, but is merely representative of various embodiments of the invention. The illustrated embodiments of the invention will be best understood by reference to the drawings, wherein like parts are designated by like numerals throughout. 
     Referring to  FIG. 1 , a material  10  in accordance with the invention may include a substrate  12  formed of a suitable material for placement in the vicinity of a fracture region. For example, a substrate may be a particle of sand, ceramic sand, volcanic grit, or other hard material. In some embodiments, a substrate may be formed of organic or inorganic material. Nevertheless, it has been found effective to use sand as a substrate  12  inasmuch as it is submersible in water and will not float as many organic materials will when dry. Likewise, the sand as substrate  12  is comminuted to such a small size that interstices between individual grains of the sand substrate  12  provide ample space and minimum distance for water to surround each of the substrate  12  particles. 
     In the illustrated embodiment, a binder  14  may be distributed as a comparatively thin layer on the surface of the substrate  12 . Typical materials for binders may include both temporary and permanent binders  14 . Permanent binders include many polymers, natural and synthetic. Temporary binders may be sugar-based or other water soluble materials. For example, corn syrup, molasses, and the like may form temporary binders. In the presence of water, such material may ultimately dissolve. Nevertheless, so long as the substrate  12  is not turned, mixed, or otherwise disturbed significantly, any other materials supported by the binder  14  would not be expected to dislocate. 
     Otherwise, certain naturally or synthetically occurring polymers may also be used as a binder  14 . Lignicite may be used as a binder  14 . Lignicite is a byproduct of wood, and provides material having good adhesive properties, and substantial permanence as a binder  14  on a substrate  12 . Any suitable insoluble polymer may be used for more permanent binding. 
     Other polymers may be used to form a binder  14 . For example, various materials used as glues, including mucilage, gelatin, other water soluble polymers including, for example, ELMER&#39;S™ glue, and the like may also operate as binders  14  to bind materials to a substrate  12 . 
     In certain embodiments, the substrate  12  may be used in oil fields as a substrate  12  for polymer additives to fracture fluids. In other situations, the substrate  12  may be implemented as a proppant. 
     Pigment  16  may be implemented in any of several manners. For example, the substrate  12  may have pigment  16  applied prior to the application of the binder  14 . In alternative embodiments, the pigment  16  may actually be included in the binder  14 , which becomes a pigmented coating on the substrate  12 . In yet other embodiments, the pigments  16  may be added to a hydration particle  18  either as a pigment  16  mixed therein, or as a pigment  16  applied as a coating thereto. Thus the location of the pigment  16  in the Figures is schematic and may take alternative location or application method. 
     Particles  18  of a hydrophilic polymer material may be bonded to the substrate  12  by the binder  14 . Particles may be sized to substantially coat or periodically coat the substrate  12 . 
     In certain embodiments, the hydrophilic material  18  may be a powdered polymeric material  18  such as polyacrylamide or any of the materials in the patent documents incorporated by reference. In other embodiments, the particles  18  may actually be organic material having capillary action to readily absorb and hold water. In one presently contemplated embodiment of an apparatus in accordance with the invention, the particles  18  may be powdered polymeric material in a dehydrated state, and having a capacity to absorb water, typically many times the weight (e.g., five to forty times) of a particular particle  18 . 
     The substrate  12 , in certain embodiments, may be some form of sand or granular material. The sand will typically be cleaned and washed to remove dust and organic material that may inhibit the binder  14  from being effective. Likewise, the substrate  12  may be sized of any suitable size. For example, sand particles may range from much less than a millimeter in effective diameter or distance thereacross to approximately two millimeters across. Very coarse sands or ceramic sands may have even larger effective diameters. Hydraulic diameter is effective diameter (four times the area divided by the wetted perimeter). However, in one presently contemplated embodiment, washed and dried sand such as is used in construction, such as in concrete, has been found to be suitable. Fine sands such as masonry sands tend to be smaller, and also can function suitably in accordance with the invention. 
     Accordingly, the distance across each powder particle  18  may be selected to provide an effective coating of powdered particles  18  on the substrate  12 . In one presently contemplated embodiment, the effective diameter of the particles  18  may be from about a 30 mesh size to about a 100 mesh size. For example, a sieve system for classifying particles has various mesh sizes. A size of about 30 mesh, able to pass through a 30 mesh sieve, (i.e., about 0.6 mm) has been found suitable. Likewise, powdering the particles  18  to a size sufficiently small to pass through a 100 mesh (i.e., about 0.015 mm) sieve is also satisfactory. A mesh size of from about 50 mesh to about 75 mesh is an appropriate material to obtain excellent adhesion of particles  18  in the binder  14 , with a suitable size of the particles  18  to absorb significant liquid at the surface of the substrate  12 . 
     As a practical matter, about half the volume of a container containing a substrate  12  as particulate matter will be space, interstices between the granules of the substrate  12 . One advantage of using materials such as sand as the substrate  12  is that a coating of the particles  18  may provide a substantial volume of water once the particles  18  are fully saturated. By contrast, where the size of the particles  18  is too many orders of magnitude smaller than the effective diameter or size of the substrate particles  12 , less of the space between the substrate particles  12  is effectively used for storing water. Thus, sand as a substrate  12  coated by particles  18  of a hydrophilic material such as a polymer will provide substantial space between the substrate particles  12  to hold water-laden particles  18 . 
     The diameter of the particles  18 , or the effective diameter thereof, is typically within about an order of magnitude (e.g., 10×) smaller than the effective diameter of the particles of the substrate  12 . This order of magnitude may be changed. For example, the order of magnitude difference less than about 1 order of magnitude (i.e., 10×) may still be effective. Similarly, an order of magnitude difference of 2 (i.e., 100×) may also function. 
     However, with particles  18  too much smaller than an order of magnitude smaller than the effective diameter of the substrate  12 , the interstitial space may not be as effectively used. Likewise, with an effective diameter of particles  18  near or larger than about 1 order of magnitude smaller than the size of the particles of the substrate  12 , binding may be less effective and the particles  18  may interfere more with the substrate itself as well as the flow of water through the interstitial spaces needed in order to properly hydrate a material  10 . 
     Referring to  FIG. 2 , an embodiment of a process for formulating the material  10  may involve cleaning  22  the material of the substrate  12 . Likewise, the material of the substrate  12  may be dried  24  to make it more effective in receiving a binder  14 . The material of the substrate  12  may then be blended  26 . 
     One embodiment, a ribbon blender provides an effective mechanism to perform continuous blending as the binder  14  is added  28 . Other types of mixers, such as rotary mixers, and the like may be used. However, a ribbon blender provides a blending  26  that is effective to distribute binder  14  as it is added  28 . 
     For example, if an individual particle of the substrate  12  receives too much binder  14 , and thus begins to agglomerate with other particles of the substrate  12 , a ribbon binder will tend to separate the particles as a natural consequences of its shearing and drawing action during blending  26 . 
     As the binder  14  is added  28  to the mixture being blended  26 , the individual particles of the substrate  12  will be substantially evenly coated. At this stage, the binder  14  may also be heated in order to reduce its viscosity and improve blending. Likewise, the material of the substrate  12  or the environment of the blending  26  may be heated in order to improve the evenness of the distribution of the binder  14  on the surfaces of the substrate  12  materials or particles  12 . 
     Blending  26  of the binder  14  into the material of the substrate  12  is complete when coating is substantially even, and the texture of the material  10  has an ability to clump, yet is easily crumbled and broken into individual particles. At that point, addition  30  of the hydrophilic particles  18  may be accomplished. 
     For example, adding  30  the particles  18  as a powder into the blending  26  is a naturally stable process. Typically the particles  18  attach to the binder  14  of the substrate  12  particles, thus removing from activity that location. Accordingly, other particles  18  rather than agglomerating with their own type of material will continue to tumble in the blending  26  until exposed to a suitable location of binder  14  of the substrate  12 . Thus, the adding  30  of the particles  18  or powder  18  of hydrophilic material will tend to be a naturally stable process providing a substantially even coating on all the particles of the substrate  12 . 
     Just as marshmallows are dusted with corn starch, rendering them no longer tacky with respect to one another, the material  10  formulated by the process  20  are dusted with particles  18  and will pour freely. Accordingly, distribution  32  may be conducted in a variety of ways and may include one or several processes. For example, distribution may include marketing distribution from packaging after completion of blending  26 , shipping to distributors and retailers, and purchase and application by users. 
     An important part of distribution  32  is the deployment of the material  10 . In one embodiment of an apparatus and method in accordance with the invention, the material  10  may be poured, as if it were simply sand  12  or other substrate  12  alone. Since the powder  18  or particles  18  have substantially occupied the binder  14 , the material  10  will not bind to itself, but will readily pour as the initial substrate material  12  will. 
     The material  10  may typically include from about 1 percent to about 20 percent of a hydrophilic material  18  or particles  18 . The particles  18  may be formed of a naturally occurring material, such as a cellulose, gelatin, organic material, or the like. 
     In one embodiment, a synthetic gel, such as polyacrylamide may be used for the particles  18 , in a ratio of from about 1 to about 20 percent particles  18  compared to the weight of the substrate  12 . In experiments, a range of from about 5 to about 10 percent has been found to be the most effective for the amount particles  18 . 
     Sizes of particles  18  may range from about 20 mesh to smaller than 100 mesh. Particles  18  of from about 50 to about 75 mesh have been found most effective. 
     The binder  14  may typically be in the range of from about in ¼ percent to about 3 percent of the weight of the substrate  12 . A range of from about ¾ percent to about 1½ percent has been found to work best. That is, with a binder such as lignicite, ¼ of 1 percent has been found not to provide as reliable binding of particles  18  to the substrate  12 . Meanwhile, a ratio of higher than about 3 percent by weight of binder  14  to the amount of a substrate  12 , such as sand, when using lignicite as the binder  14 , tends to provide too much agglomeration. The pouring ability of the material  10  is inhibited as well as the blending  26 , due to agglomeration. Other binders also operate, including several smaller molecules that are water soluble. For example, glues, gelatins, sugars, molasses, and the like may be used as a binder  14 . Insoluble binders are also useful and more permanent. 
     One substantial advantage for the material  10  in accordance with the present invention is that the material remains flowable as a sand-like material  10  into the fluids to be used in oil field fracturing. Thus, handling and application is simple, and the ability of granular material  10  to flow under and around small interstices of fractures provides for a very effective application. 
     Referring to  FIG. 3 , a formation  80  such as a reservoir area of an oil may increase large and small flows  82  in passages  84  formed in the rock  86  of the formation  80 . Typically, the flow  82  represented by arrows  82  indicating the development of flow at a faster speed in center of a passage  84 , and the lower velocity near the wall  88  of the passage  84 , illustrates the flow  82  of fluid in the passage  84 . 
     In the illustrated embodiment, the granules  10  or large composite particles  10  or the materials  10  formed as a granulated material  10 , having the substrate  12  in the center column with the polymer  18  adhered by a binder  12  on the outside thereof. This material  10  may be added to a flow  82  being pumped into a formation  80 . Initially, a particle  10  will have an effective diameter  90   a . In this condition, the particle  10  of material  10  is largely dependant on the density of the substrate  12 , which constitutes the majority of its volume. Eventually, over time, with exposure to the liquid  82  or flow  82  and the water of that flow  82 , the polymer  18  will absorb water, increasing in its effective diameter  90   b . Ultimately, the polymer  18  or the polymer powder  18  will eventually become fully hydrated, increasing many times its size, and beginning to dominate the effective diameter  90   c  or hydraulic diameter  90   c  of the particle  10 . 
     Initially, the diameter  90   a  reflects the comparatively smaller size and larger density of the particle  10  dominated by the weigh of the substrate  12 , such as sand, ceramic sand, or some other hard and strong material. Ultimately, the diameter  90   a  or effective diameter  90   a  is sufficient to provide fluid drag according to fluid dynamic equations, drawing the particle  10  into the flow  82 . 
     Meanwhile, the increase in diameter  90   b  and the ultimate effective diameter  90   c  result in reduction of the density of the particle  10  as the polymer  18  absorbs more water, bringing the net density of the particle  10  closer to the density of water. Accordingly, the particles  10  flow with the water exactly in sync, so to speak, rather than settling out as a bare substrate  12  would do. 
     For example, in areas where eddies in the flow occur, such as corners, crevices, walls, and the like, heavy materials having higher density, such as sand and the like, normally will tend to drift out of the flow, toward a wall  88 , and ultimately will settle out. Instead, by virtue of the large “sail” presented by the larger diameter  90   c  of a fully hydrated polymer  18 , each particle  10  stays with the flow  82  in passage  84 , providing much more effective transport. 
     Referring to  FIG. 4 , a chart  92  illustrates a volume axis  94  representing the volume of a particle  10  or material  10  in accordance with the invention. The volume axis  94  is displayed orthogonally with respect to a time axis  96 , representing the passage of time of the particle  10  submerged in a carrier  82  or flow  82  of fluid  82 . Typically, at different temperatures, illustrated by curves  98   a - 98   e , with the temperature associated with curve  98   a  being the coldest and the temperature associated with the curve  98   e  being the hottest, one can visualize how heat added to a fluid flow  82  tends to increase the chemical activity and thus the rate of absorption of water into a polymer  18 . 
     In an apparatus and method in accordance with the invention, the particles  10  may be added directly to a flow  82 , without waiting for any significant time to absorb water into the polymer  18 . Instead, the normal flow  82  will draw the particles  10  along in a passage  84  while exposing each individual particle  10  to surrounding fluid  82 , thus promoting maximum rates of exposure and increased rates of absorption. Accordingly, the volume  94  increases, representing an increase in the absorption of water into the polymer  18 . 
     In an apparatus and method in accordance with the invention, the curve  98   a  is suitable because the entire travel within the well bore, and within the formation  80  by the fluid  82  bearing the particles  10  is permissible and available as absorption time. By contrast, prior art systems rely on the increased temperature of curve  98   e  in order to provide the time, temperature, and mixing to work polymers into a flow  82  or liquid carrier  82 . 
     Referring to  FIG. 5 , in one embodiment of an apparatus, composition, and method in accordance with the invention, some of the polymer  18  may eventually be scraped, sheared, or otherwise removed from the particles  10 . If bonded only by itself with a water solvent, such a separation may be easier than if bonded by a more durable polymer. Such a release may even be engineered, timed, controlled by a solvent, or the like. 
     Thus, a certain amount of the polymer  18  may be released from the granule  10  into the carrier fluid  82  to flow with the fluid  82  and operate as a general friction reducer or provide its other inherent properties to the carrier fluid  82 . By an engineered process of bonding and un-bonding, the polymer powder may be less permanent or attached to have a bond that is less robust. Over time, the polymer powder so attached may release, tear, wear off, pull away, or otherwise remove from the substrate into the carrier fluid to act as a viscosity agent, surfactant, lubricant, or the like in the carrier, according to its known properties available for modifying the carrier  82 . 
     For example, a polymer  100  or polymer chain  100  may be captured on a corner  102  defining a passage  84  into which a flow  82  will proceed. Accordingly, the corner  102  renders less of an orifice on the passage  84  against entry of the flow  82  by virtue of the friction reduction of the polymer  100  in the fluid, deposited temporarily or permanently about a corner  102 . Thus, other particles  10  passing the corner  100  may shear off a portion of the polymer  18  carried thereby or may rely on the presence of the polymer  18  as a direct friction reducing agent on the particle  10  (granule) itself, permitting the particles  10  to pass more easily with the flow  82  into the passage  84 . 
     Referring to  FIGS. 6A and 6B , various fracture processes are described in various literature, including U.S. Patent Application publication US 2009/0065253 by Suarez-Rivera et al. incorporated herein by reference. In a fracturing process, the pressure  110  or force  110  applied to a formation  80  tends to force apart large expanses of rock. As a result of that expansion of passages  84  in a rock formation  80 , the rock is stressed. Pressure pumped into the fluid  82  flowing in the passages  84  within the formation  80  results in bending stresses, tensile stresses, and so forth in the formation  80 . 
     In  FIG. 6A , the forces  110  illustrated the effect of a large pressure applied over a large area. Since pressure multiplied by area equals force, applying an elevated hydraulic pressure to a large surface of a rock  86  or rock segment  86  within a formation  80  results in tensile forces. Compressive forces will not tend to break rock. However, a tensile force, which may be induced by bending, expansion, or the like, results in fracture of the rock. The fracture of the rock  86  thus results in condition shown in the lower view, in which the passages  84  are mere fissures within the rock  86 . 
     The inset of  FIG. 6A  magnifies the fissures  84  or passages  84  formed in the rock  86  and immediately entered by the working fluid  82  being used for the fracture. Having the particles  10  formed around substrates  12 , the fluid  82  extends into each of the fissures formed. Fissures  84  are simply passages  84 . Some may be large, others small. 
     Referring to  FIG. 6B , proppants  10  trapped in a small location still displace a large amount of fractured rock  86 . Thus, a small displacement at one location may still maintain opened another opening much larger elsewhere near the rock  86 . The particles  10 , even if as small as sand, may also collect and fill larger dead ends, slow flowing, and eddying spaces, eliminating the ability for rocks  86  to return to former positions. 
     After fracturing rock  86  to form all of the fissures  84 , the fluid  82  will pass through the fissures, carrying particles  10 , which eventually collect in cavities or reach choke points. In the absence of the particles  10 , fissures  84  could close back up after the fracturing water leaves. However, by containing additives  18 , and then losing them, the individual substrates  12  are themselves rock in the form of sand, ceramic sand, or the like. Thus, a particle  10  or many particles  10  need only obstruct the ability of the fissure  84  to close, and may “prop” open the fissures  84  precluding the rock  86  or the pieces of rock  86  from settling back into alignment with one another. 
     Thus, the particles  10  both alone and in collected piles act as proppants left behind by the fluid flow  82 , by virtue of the particles  10   b  captured. As a practical matter, it is the substrate  12  that acts as a proppant. The polymers  18  may eventually be worn off, or released by a water-soluble binder, but can easily be compressed, distorted, or cut. Regardless, as the fissures  84  open, they are back filled and close in at choke points and settling points collecting the substrate  12 . 
     Continuing to refer to  FIG. 6B , while referring generally to  FIGS. 1-10 , a formation  80  when fractured into individual pieces of stone  86 , may form various passages  84  or fissures  84  therein. To the extent that proppant materials  10  lose the adhered particles  18  or powders  18 , once hydrated or mixed into the fluid  82 , the substrate  12  is then in a position to be deposited by eddies, slower flows, turning corners, and the like. Thus, when the other materials  18  that have acted sails, drifting the substrate  12  with the fluid  82 , have been removed, then the substrate  12  can more easily settle out. Accordingly, near corners, in small crevices, in dead corners, and the like, the particles  10 , largely stripped of their added constituent powders  18  (in whatever phase at that point) may then drop out of the fluid  82  in a slow flow. 
     Once two portions of rock  86  separate from one another, forming a passage  84  of some size, a supply of proppant  10   b  may then prevent that rock portion  86  from moving back into its exact position, necessarily forming passages  84  on virtually every side. Where a single particle  10  of substrate  12  may drop out of the fluid  82  and collect, many more may likewise collect. Accordingly, the various particles  10   b  illustrated in  FIG. 6B  may collect, forming substantial support for various edges, corners, and the like of various rock  86 . The result is that a small material, in comparatively small quantities, supporting an edge, or a particular region of a rock  86  in the formation  80  may nevertheless maintain a large network of passages  84  as a direct result. 
     In stone formations having stronger tensile strength, fractures may produce less debris to act as natural proppants. Nevertheless, in addition to the particles  10  constituting primarily substrate material  12  at this point, the passages  84  may be maintained open as is the objective with fracturing. 
     Referring to  FIG. 7 , a process  111  may include preparing  112  a fluid  82 . Processing  114  other additives other than the particles  10  may be done according to any suitable methods, including prior art processes. Adding  116  directly to the fluid  82 , the particles  10  as described hereinabove, may be done in such a manner that the operators need not wait for absorption or any other processes to take place. Additional energy for elevating temperature is not required, neither mixing or the like, other than adding  116  directly particles  10  in to the flow  82 . The flow  82  will immediately grab the particles  10  according the principles of fluid dynamics in which fluid drag is dependent upon a shape factor of the particle  10 , the density of the fluid  82 , the square of velocity of the fluid, and so forth, as defined in engineering fluid mechanics. 
     The fluid  82  now bearing the particles  10  would be immediately pumped  118  into the formation  80  that is the reservoir  80  of an oil field. Eventually, pressurizing  120  the reservoir by pressurizing the fluid  82  results in creating  122  fractures  84  or fissures  84  within the formation  80  by breaking up the rock  86  of the formation  80 . A fracture  84  with enough displacement may make a site for material  10  to stagnate and collect. 
     Creating  122  fracture lines throughout the formation  80  is followed by penetrating  124 , by the particles  10  borne in the fluid  82  into the passages  84  or fissures  84  in the rock  86  of the formation  80 . Whenever the flow  82  of fluid  82  carries a particle  10  to a choke point  108  in a passage  84 , as illustrated in  FIG. 6 , a particle  10  will be lodged as illustrated in the inset of  FIG. 6 , a particle  10  with its polymer  18  still secured and intact may be lodged. Similarly, the substrate  12  may be lodged  126  and the polymer  18  may stripped therefrom by the consequent or subsequent flowing of material in the flow  82 . Likewise, piles of stagnant particles  10  may backfill spaces, precluding rock  86  settling back in. 
     After the lodging  126  or propping  126  of the fissures  84  by the substrate  12 , in the particles  10 , the passages  84  will remain open. These fissures  84  may then be used tolater withdraw  128  the fluid  82  from the formation  80 . Thereafter, returning  130  the formation  80  to production may occur in any manner suitable. For example, heat may be added to the formation, liquid may be run through the formation as a driver to push petroleum out, or the like. 
     Referring to  FIGS. 8-10 , while continuing to refer generally to  FIGS. 1-10 , in various alternative embodiments, multiple constituents may be used as the particles  18  or powder  18  held by the binder  14  to the substrate  12 . For example, in various alternative embodiments, one or more other constituents may be added in addition to friction reducers. In the embodiments described hereinabove, the polymeric powders  18  added to the substrate  12  by the tacky or otherwise adhering binder material  14  operated partly as a friction reducer but also as a sill encouraging drifting of the particles  10  with the flow of the fluid  82  or flow  82  in the fracture fluid  82 . Thus, hydrophillic powder  18  served multiple purposes. 
     Meanwhile, as described hereinabove, such polymers may be bonded to the outer surface of the binder  14 , thus rendering themselves more susceptible to absorbing water and being stripped of by friction against the walls  88  of various passages  84  in the formation  80 . Accordingly, such materials may typically be used in combination with others in various fractures. It has been found effective to include a friction reducing material at a fraction of about 0 to about 10 percent of the total coating granules  18  or powder  18  adhered to the binder  14 . 
     Similarly, biological organisms can change the pH in the water  82  or fluid  82  used for the fracture process. Accordingly, biocides or bacteriacides may eliminate the bacteria or reduce its population in order to avoid changes in the mechanical properties of the fluid  82  as well as changing the pH and thereby the corrosiveness of the fluid  82 . 
     In the contemplated embodiment, such materials such as sodium hypochlorite as a powder or crystal form may be used as one of the constituents for the powder  18  to be bound by the binder  14 . Likewise, chlorine dioxide may also be applied by a powder formed of a crystal and form thereof. Other biocides that may be included may be gouteraldehyde as a liquid, or as the constituents thereof in solid form. Similarly, quaternary ammonium chloride may be provided as a solid and therefore as a powder, or as a liquid. 
     Liquids may be included in the binder  14 . Alternatively, the liquid constituents may instead be separated from (or not dissolved in) their solvents in order to provide powders  18  for adhering to the particles  10 . Thus, the foregoing liquids as well as tetrakis hydroxhydroxymethyl-phosphonium sulfate may be similarly treated. 
     As one or even as the only constituent, a particular material may be used as powder  18  adhered to the substrate  12  as part of a particle  10 . Any one or more may be combined appropriately. Biocides, typically appear to be suitable in the range of from about 0 to about 3 percent of the particles  18  or powder  18  secured to the substrate  12 . 
     Oxygen scavengers also assist in changing pH as well as preventing corrosion, by removing available oxygen from the fluid  82 . Removal of oxygen prevents oxidation, commonly known as rust or corrosion. Thus, the liners, drilling equipment, and other tubular materials may increase their life and reliability and overall integrity of the well by reducing oxygen in the fluid  82 . Accordingly, from about 0 to about 3 percent of an oxygen scavenger may be included as part of the coating  18  or the powder  18  adhered to each substrate  12 . 
     Similarly, a clay stabilizer may be included in a proportion of from about 0 to about 3 percent of the coating  18 . Thus, clay stabilizers that are used in the fluid  82  may be modified or restricted from swelling or shifting. For example, choline chloride as well as tetramethyl ammonium chloride as well as sodium chloride (salt) may all be provided as powders  18  to be bonded to the substrate  12  by a binder  14 . 
     Likewise, scaling inhibitors may be included at a rate of from about 0 to about 3 percent of the powder  18  adhered to the substrate  12  or of the total weight of the product. Scaling involves the deposition on various conduits and walls, typically in pipes of various minerals, such as carbonates. Changes in pH, changes in temperature, changes in various concentrations of other materials including that of the scaling material may cause scale to accumulate. Accordingly, scale inhibitors may be added as particles  18  in an overall mix, or as part of another coating process. 
     For example, various copolymers of acrylamides as well as sodium acrylate are scale inhibitors that may be secured to the substrate  12  by the binder  14 . Similarly, sodium polycarboxylate and phosphonic acid salt may all be provided in a solid form. All may be comminuted to a powder  18 , and sieved to a common size corresponding to that of other materials. Accordingly, mixed in a proper ratio, the powders  18  may actually be compositions of numerous constituents in suitable proportions. 
     Likewise, a gelling agent may be added in a proportion of from about 0 to about 10 percent as a powder  18  secured to the substrate  12  of particle  10 . A function of gelling agents is to alter viscosity. This improves suspension of proppants, such as the substrate  12 , sand, or the like, in water. Typically, the speed or velocity with which gravity or other effects may drift a heavy substrate  12  or particle  10  out of solution to leave it elsewhere, is controlled to a large extent by the relative viscosity of the liquid fluid  82  through which the particles  10  are passing. Accordingly, increasing the viscosity tends to keep the particles  10  entrained and more evenly distributed within the fluid  82 . 
     Accordingly, various gelling agents, or a single gelling agent selection may be used as a constituent forming the powder  18  adhered to a substrate  12 . Typical processes describe hearinabove and hereinafter illustrate that solid particles may be inducted into the flow  82  or the fluid  82  almost instantly when introduced as the particulates  10 . Thus, rather than floating on top during extensive mixing, such materials may be drawn quickly as part of the particles  10  discharged into the fluid  82  at the well head. 
     Various experiments have shown the utility and ability to add many of these materials. Generally, anything that can be maintained stable for a suitable period of time may be added as powder  18  to a suitable binder  14  holding it to a substrate  12 . Thus, various hydrophilic polymers, including polyacrylamides and polyacrylates may be added. Guar gum, various guar derivatives, polysaccharide blends all have the mechanical properties to be suitable as constituents of the powder  18  of particles  10 . 
     Referring to  FIG. 8 , in one embodiment of a process in accordance with the invention, a substrate  12  may have added to it a layer of binder  14 . To the binder  14  may be added a particular powder  18   a  or additive  18   a  in solid form to be bound to the substrate  12  by the binder  14 . In this particular embodiment, the powder  18   a  is added first, in a particular fraction. Thereafter, various other constituents may be added in series as the powders  18   b ,  18   c ,  18   d , illustrated by differing shapes of particles. For example, the particles or powder  18   a  is illustrated by an irregular shape, the powder  18   b  by a rectangular shape,  18   c  by a diamond shape, and  18   d  by a circular shape. These shapes are merely schematic in order to show the addition of various materials. 
     Continuing to refer to  FIG. 8 , the process may also operate by a method of first mixing each of the different powders  18 , including up to about 10 or more. Typically, additives in the range of from about 5 to about 9 different constituents may be comminuted and sieved (sorted) in order to maintain all at approximately the same range of sizes. 
     In this way, by grinding to powder (comminuting) and then sorting with a sieve, the various constituent materials may then be treated mechanically as generic materials, mechanically equivalent. Thus, all may be mixed together. 
     An important feature here is to avoid disparate sizes, and particularly the inclusions of too many fines. Ultra fine particles tend to provide less included volume in each powder particle, and thus occupy more surface area of the available binder  14  and the surface area of the substrate  12 , thus inhibiting even coating and the addition of other constituents. Thus, in such an embodiment, the powder particles  18   a ,  18   b ,  18   c ,  18   d , and so forth may all be mixed in the exact proportion desired, usually as a fraction or percentage of the total weight of particles  10 , and each may then be included in a mixed supply (e.g., bin, etc.) having the proportions desired, of each and every constituent. Thus, the process described with respect to  FIGS. 1 and 2  hereinabove may be used directly, with the powder  18  simply being a mix of other individual constituent chemicals as powders. Thus, all constituents may be added “in parallel,” simultaneously. 
     Referring to  FIG. 9 , in an alternative embodiment, the substrate  12  may have added to it a binder  14 , after which a layer of particles  18  may be added to the binder. Following this, an additional layer of binder  14  may be added to which additional particles  18  may be adhered. 
     In this embodiment, the additional layers of binder  14  and particles  18  may provide sequential de-layering of the various powders  18  during the process of flowing through the bore and into the formation  80 . Nevertheless, it has been found that adhering a supply of particles  18  or powder  18  to a single layer of binder  14 , provides adequate surface area, adequate binding, and sufficient area to hold a wide variety of constituent chemicals all adhered in a single coating process. 
     Referring to  FIG. 10 , while continuing to refer generally to  FIGS. 1-10 , one embodiment of a process  20  may be illustrated with the cleaning  22 , drying  24 , and blending  26  as described hereinabove. Meanwhile, a decision  132  determines the mode of coating. For example, if the decision is to coat directly, then preparing  134  sieved constituents may include comminuting and sorting constituents, each sieved or otherwise sorted in order to provide a consistent size range for each. 
     Following the preparation  134  of the constituents, mixing  136  is needed for the constituents in the suitable ratios or percentages. This provides a single mixture of powdered particulates  18  suitable for bonding to a substrate  12 . Applying  138  a binder is followed by applying  140  the powder  18  to the binder  14  in coating the substrate  12  as described hereinabove. 
     Following preparation of the of the granular particulates  10 , postprocessing may include bagging, may include additional drying, or may include protection against elements to which the material  10  will be exposed. 
     Post processing  142  may be followed by distribution  144  to various destinations. Distribution  144  may include, or may be followed up by stocking the distributed  144  product  10  at various sites for use. Ultimately, injecting  148  the granular material  10  into the fluid  82  for fracturing may complete the preparation and use of the product  10  in accordance with the invention. Thereafter, the processes described with respect to  FIGS. 3-6B  occur as a consequence of the configuration of the granular material  10 . 
     In certain alternative embodiments, as illustrated in  FIGS. 8 and 9 , the mode decision  132  may involve adding powder  18  in series. For example, adding  150  a binder may be followed by adding  152  a powder species. Thereafter, a decision  154  may determine whether to add another species. If the decision is affirmative, then additional species may be added  152  until the coating is completed. Thereafter, when no other additions are to be made, according to the decision step  154 , then postprocessing  142  continues, and the process  20  continues to ejection  148 . 
     Similarly, the process of  FIG. 9  illustrates the process in which adding  160  a binder  14  is followed by adding  162  a powder constituent, after which a decision  164  results in adding  160  more binder before adding  162  more of a powder constituent. Thus, adding  152  powder only, compared to adding  160  binder  14  and adding  162  additional powdered constituents  18 , reflect certain of the embodiments such as  FIG. 9 . Nevertheless, the embodiment of preparing  134  sieved constituents, through applying  140  the powder  18  as a mixture, is also illustrated in  FIG. 8 , or represented thereby, as described hereinabove. 
     The present invention may be embodied in other specific forms without departing from its spirit or essential characteristics. The described embodiments are to be considered in all respects only as illustrative, and not restrictive. The scope of the invention is, therefore, indicated by the appended claims, rather than by the foregoing description. All changes which come within the meaning and range of equivalency of the claims are to be embraced within their scope.

Summary:
A method for improving hydraulic fracturing creates coated proppants containing one or more chemical constituents bonded to a substrate and introduced into the fracturing fluid itself. The substrate that eventually acts as a proppant may be sand, ceramic, resin coated sand, and other materials. Typically, the materials that are coated as powders adhered to the substrate may include friction reducers, biosides, oxygen scavengers, clay stabilizers, scale inhibitors, gelling agents, or the like. By adhering solid materials to a substrate  12  by a binder  14 , a single, solid, granular material may be maintained onsite, requiring reduced footprint, reduced mixing and may introduce almost instantaneously into a fracturing flow stream all the necessary chemical constituents, which will eventually become mixed. The result is reduced time, energy, manpower, equipment, and space at the sight, while reducing the environmental impact of transportation, spills, hydrocarbon use, and the like.