Title of Invention	METHOD OF TREATING SUBTERRANEAN FORMATIONS WITH POROUS CERAMIC PARTICULATE MATERIALS
Abstract	Methods and compositions useful for subterranean formation treatments, such as hydraulic fracturing treatments and sand control that include porous materials. Such porous materials may be selectively configured porous material particles manufactured and/or treated with selected glazing materials, coating materials and/or penetrating materials to have desired strength and/or apparent density to fit particular downhole conditions for well treating such as hydraulic fracturing treatments and sand control treatments. Porous materials may also be employed in selected combinations to optimize fracture or sand control performance, and/or may be employed as relatively lightweight materials in liquid carbon dioxide-based well treatment systems.

Title of Invention

METHOD OF TREATING SUBTERRANEAN FORMATIONS WITH POROUS CERAMIC PARTICULATE MATERIALS

Abstract

Methods and compositions useful for subterranean formation treatments, such as hydraulic fracturing treatments and sand control that include porous materials. Such porous materials may be selectively configured porous material particles manufactured and/or treated with selected glazing materials, coating materials and/or penetrating materials to have desired strength and/or apparent density to fit particular downhole conditions for well treating such as hydraulic fracturing treatments and sand control treatments. Porous materials may also be employed in selected combinations to optimize fracture or sand control performance, and/or may be employed as relatively lightweight materials in liquid carbon dioxide-based well treatment systems.

Full Text	METHOD OF TREATING SUBTERRANEAN FORMATIONS WITH POROUS CERAMIC PARTICULATE MATERIALS SPECIFICATION Field of the Invention This invention relates generally to methods and compositions useful for subterranean formation treatments, such as hydraulic fracturing treatments and sand control. Background of tile Invention Hydraulic fracturing is a common stimulation technique used to enhance production of fluids from subterranean formations. In a typical hydraulic fracturing treatment, fracturing treatment fluid containing a solid proppant material is injected into the formation at a pressure sufficiently high enough to cause the formation or enlargement of fractures in the reservoir. During a typical fracturing treatment, proppant material is deposited in a fracture, where it remains after the treatment is completed. Afire deposition, the proppant material serves to hold the fracture open, thereby enhancing the ability of fluids to migrate the formation to Hoe well bore through the fracture. Because fractured well productivity depends on the ability of a fracture to conduct fluids from a formation to a wellbore, fracture conductivity is an important parameter in determining the degree of success of a hydraulic fracturing treatment. Hydraulic fracturing treatments commonly employ proppant materials that are placed downhole with a gelled carrier fluid such as aqueous\is-based fluid such as gelled brine. Gelling agents for proppant carrier fluids may provide a source of proppant pack and/or formation damage, and settling of proppant may interfere with proper placement downhole. Formation damage may also be caused by gelled carrier fluids used to place particulates downhole for purposes such as for sand control, such as gravel packs, franc packs, and similar materials. Formulation of gelled carrier fluids usually requires equipment and mixing steps designed for this purpose. Hydraulic fracturing treatments may also employ proppant materials that are placed downhole with non-aqueous-based fluids, such as liquid CO2 and liquid CO2/N2 systems. Proppants commonly employed with such non-aqueous-based fluids tend to settle in the system. Many different materials have been used as proppants including sand, glass beads, walnut hulls, and metal shot. Commonly used proppants today include various sands, resin-coated sands, intermediate strength ceramics, and sintered bauxite; each employed for their ability to cost effectively withstand the respective reservoir closure stress environment. As the relative strength of the various materials increases, so too have the respective particle densities, ranging from 2.65 g/cc for sands to 3.4 g/cc for the sintered bauxite. Unfortunately, increasing particle density leads directly to increasing degree of difficulty with proppant transport and a reduced propped fracture volume for equal amounts of the respective proppant, reducing fracture conductivity. Previous efforts undertaken to employ lower density materials as proppant have generally resulted in failure due to insufficient strength to maintain fracture conductivity at even the lowest of closure stresses (1,000 psi). Recently, deformable particles have been developed. Such deformable particles for sand flowback control are significantly lighter than conventional proppants, and exhibit high compressive strength Such deformable materials include polystyrene divinylbenzene (PSDVB) deformable beads. Such beads, however, have not been entirely successful primarily due to limitations of the base material. While PSDVB beads offered excellent deformability and elasticity, they lacked the structural integrity to withstand high closure stresses and temperatures. The first successful path to generate functional deformable particles was the usage of modified ground walnut hulls. Walnut hulls in their natural state have been used as proppants, fluid loss agents and lost circulation materials for many years with greater or lesser degrees of success in each respective task. As a proppant, natural walnut hulls have very limited applicability, because they deform fairly readily upon application of closure stress. This deformation drastically reduces conductivity and limits utility of the natural material to relatively low-closure environments. Walnut hull based ultra-lightweight (UCW) proppants may be manufactured in a two-step process by using closely sized washout particles (i.e. 20/30 US mesh), and impregnating them with strong epos.\y or other resins. These impregnated walnut hull particles are then coated with phenolic or other resins in a fashion similar to most resin coated proppants (RCP). Such walnut hull based ULW proppants have a bulk density of 0.85 grams/cc and withstand up to 6,000 psi (41.4 MPa) closure stress at 175°F (79°C). Generally speaking, the stronger a proppant, the greater the density. As density increases, so too does difficulty of placing that particle evenly throughout the created fracture geometry. Excessive settling can often lead to bridging of the proppant in the formation before the desired stimulatwn is achieved. The lower particle density reduces the fluid velocity required to maintain proppant transport within the fracture, which, in tam, provides for a greater amount of the created fracture area to be propped. ULW proppants which allow for optimization of fracturing treatment with improved fracture length and well productivity are therefore desired. Summary of the Invention The invention relates to methods for treating subterranean formations by creating a well with a composition containing porous ceramic or organic polymeric particulates. In particular, the compositions introduced into the well are particularly suitable in hydraulic fracturing of a well as well as sand consolidation methods such as gravel packing and franc packing. The porous particulate material may be a selectively configured porous particulate material, as defined herein. Alternatively, the porous particulate material may be a non-selectively configured porous particulate material, as defined herein. The porous particulate material may be selectively configured with a non-porous penetrating material, coating layer or glazing layer. In a preferred embodiment, the porous particulate material is a selectively configured porous particulate material wherein either (a.) the apparent density or apparent specific gravity of the selectively configured porous particulate material is less than the apparent density or apparent specific gravity of the porous particulate material; (b.) the permeability of the selectively configured porous particulate material is less than the permeability of the porous particulate material; or (c.) the porosity of the selectively configured porous particulate material is less than the porosity of the porous particulate material. In a preferred embodiment, the penetrating material and/or coating layer and/or glazing layer of the selectively configured porous particulate material is capable of trapping or encapsulating a fluid having an apparent specific gravity less than the apparent specific gravity of the carrier fluid. Further, the coating layer and/or penetrating material and/or glazing material may be a liquid having an apparent specific gravity less than the apparent specific gravity of the matrix of the porous particulate material. The strength of the selectively configured porous particulate material is typically greater than the strength of the porous particulate material per se. Further, the selectively configured porous material exhibits crush resistance under conditions as high as 10,000 psi closure stress, API RP 56 or API RP 60. In a preferred mode, the porous particulate composition is a suspension of porous particulates in a earner fluid. The suspension preferably forms a pack of particulate material that is permeable to fluids produced food the wellbore and substantially prevents or reduces production of formation materials food the formation into the wellbore. Further, the porous particulate material may exhibit a porosity and permeability suds that a fluid may be drawn at least partially into the porous matrix by capillary action. Preferably, the porous particulate material has a porosity and permeability such that a penetrating material may be drawn at least partially into the porous matrix of the porous particulate material using a vacuum and/or may be forced at least partially into the porous matrix under pressure. The selectively configured porous particulate material may consist of a multitude of coated particulates bonded together. In such manner, the porous material is a cluster of particulates coated with a coating or penetrating layer or glazing layer. Suitable coating layers or penetrating materials include liquid and/or curable resins, plastics, cements, sealants, or binders such as a phenol, phenol formaldehyde, melamine formaldehyde, urethane. epoxy resin, nylon, polyethylene or a combination thereof In a preferred mode, the coating layer or penetrating material is an ethyl carbonate-based resin. In a preferred embodiment, the selectively configured porous particulate materials are derived from lightweight and/or substantially neutrally buoyant particles. The application of selected porous material particulates and relatively lightweight and/or substantially neutrally buoyant particulate material as a fracture proppant particulate advantageously provides for substantially improved overall system performance in hydraulic fracturing applications, or in other well treating applications such as sand control. The porous particulate material-containing compositions used in the invention may fritter contain a carrier fluid. The carrier fluid may be a completion or workover brine, salt water, fresh water, a liquid hydrocarbon, or a gas such as nitrogen or carbon dioxide. The porous particulate material-containing compositions may further contain a gelling agent, crosslinking agent, gel breaker, surfactant, taming agent, demulsifier, buffer, clay stabilizer, acid or a mixture thereof. Brief Description of the Drawings In order to more fully understand the drawings referred to in the detailed description of the present invention, a brief description of each drawing is presented, in which: FIG. 1 is a graph depicting bulk apparent density comparison of the data of Example 1. FIG. 2 is a graph depicting amiability versus closure stress data of Example 2. FIG. 3 is a graph depicting conductivity versus closure stress data of Example 2. FIG. 4 is a graph depicting conductivity versus closure stress data of Example 2. FIG. 5 is a graph depicting permeability versus closure stress data of Example 2. FIG. 6 is a graph depicting conductivity comparison data of Example 2. FIG. 7 is a graph depicting permeability comparison data of Example 2. FIG. 8 is a SEM photograph of a porous material particle of Example 3. FIG. 9 is a SEM photograph of a porous material particle of Example 3. FIG. 10 is a SEM photograph of a porous material particle of Example 3. FIG. 11 is a SEM photograph of a porous material particle of Example 3. FIG. 12 is a SEM photograph of a porous material particle of Example 3. FIG. 13 is a SEM photograph of a porous material particle of Example 3. FIG. 14 is a SEM photograph of a porous material particle of Example 3. FIG. 15 is a SEM photograph of a porous material particle of Example 3. FIG. 16 illustrates proppant distribution for a selected combination or" well treatment particulates according to one embodiment of the disclosed compositions and methods described in Example 4. FIG. 17 illustrates comparative proppant distribution data of Example 4 for Ottawa sand alone. Detoured Description of the Preferred Embodiments As used herein, the following terms shall have the designated meanings: "porous particulate material" shall refer to porous ceramic or porous organic polymeric materials. Examples of types of materials suitable for use as porous material particulates include particulates having a porous matrix; "selectively configured porous particulate material" shall refer to any porous particulate material, natural or non-natural, which has been chemically treated, such as treatment with a coating material; treatment with a penetrating material; or modified by glazing. The term shall include, but not be limited to, those porous particulate materials which have been altered to achieve desired physical properties, such as particle characteristics, desired strength and/or apparent density in order to fit particular downhole conditions for well treating such as hydraulic featuring treatments and sand control treatments. "non-selectively configured porous particulate material" shall refer to any porous natural ceramic material, such as lightweight volcanic rocks, like pumice, as well as prelate and other porous "lavas" like porous (vesicular) Hawaiian Basalt, porous Verna Diabase, and Utah Hyalite. Further, inorganic ceramic materials, such as alumina, magnetic glass, titanium oxide, zirconium oxide, and silicon carbide may also be used. In addition, the term shall refer to a synthetic porous particulate material which has not been chemically treated and which imparts desired physical properties, such as particle characteristics, desired strength and/or apparent density in order to fit particular downhole conditions for well treating; "relatively lightweight" shall refer to a porous particulate material that has a apparent density (API RP 60) that is substantially less than a conventional particulate material employed in hydraulic fracturing or sand control operations, such as sand having an apparent specific gravity (API RP 60) of 2.65 and bauxite having an apparent specific gravity of 3.55. The apparent specific gra\ity of a relatively lightweight material is less than about 2.4. "substantially neutrally buoyant" shall refer to a porous particulate material that has an apparent density sufficiently close to the apparent density of a selected ungelled or weakly gelled carrier fluid, such as an ungelled. or weakly gelled completion brine, other aqueous-based fluid, slick water, or other suitable fluid, which allows pumping and satisfactory placement of the proppant/particulate using the selected ungelled or weakly gelled carrier fluid. a "weakly gelled carrier fluid" is a carrier fluid having a viscosifier or friction reducer to achieve friction reduction when pumped down hole, for example when pumped down tubing, work string, casing, coiled tubing, drill pipe, or siniilar location, wherein the polymer or viscosifier concentration from about 0 pounds of polymer per thousand gallons of base fluid to about 10 pounds of polymer per thousand gallons of base fluid, and/or the viscosity from about 1 to about 10 centipoises. An "ungelled carrier fluid" is a carrier fluid having no polymer or viscosifier. The ungelled carrier fluid may contain a friction reducer known in the art. The selectively configured porous particulate materials as well as non-selectively configured porous particulate materials are particularly effective in hydraulic fracturing as well as sand control fluids such as water, salt brine, slickwater such as slick water fracture treatments at relatively low concentrations to achieve partial monolayer fractures, low concentration polymer gel fluids (linear or crosslinked), foams (with gas) fluid, liquid gas such as liquid carbon dioxide fracture treatments for deeper proppant penetration, treatments for water sensitive zones, and treatments for gas storage wells. For instance, the selectively configured porous material particles or non-selectively configured porous material particles may be mixed and pumped during any desired portion/s of a well treatment such as hydraulic fracturing treatment or sand control treatment and may be mixed in any desired concentration with a carrier fluid. In this regard, any carrier fluid suitable for transporting the selectively configured porous particulate material or non-selectively configured porous particulate material particles into a well and/or subterranean formation fracture in communication therewith may be employed including, but not limited to, carrier fluids comprising salt water, fresh water, potassium chloride solution, a saturated sodium chloride solution, liquid hydrocarbons, and/or nifrogen or other gases may be employed. Suitable carrier fluids include or may be used in combination with fluids have gelling agents, cross-linking agents, gel breakers, surfactants, foaming agents, demulsifiers, buffers, clay stabilizers, acids, or mixtures thereof. When used in hydraulic fracturing, the selectively configured porous particulate material or non-selectively configured porous particulate material particles may be injected into a subterranean formation in conjunction with a hydraulic fracturing treatment or other treatment at pressures sufficiently high enough to cause the fonmation or enlargement of fractures. Such other treatments may be near wellbore in nature (affecting near wellbore regions) and may be directed toward improving wellbore productivity and"or controlling the production of fracture proppant or formation sand. Particular examples include gravel packing and "frac-packs." Moreover, such particles may be employed alone as a fracture proppant/sand confrol particulate, or in mixtures in amounts and with types of fracture proppant/sand control materials, such as conventional fracture or sand control particulate. Further information on hydraulic fracturing methods and materials for use therein may be found in United States Patent No. 6,059,034 and in United States Patent No. 6,330,916, which are incorporated herein by reference. When employed in well treatments, selected porous material particles that have been selectively configured, such as glazed and/or treated with one or more selected coating and/or penetrating materials, may be infroduced into a wellbore at any concentration/s deemed suitable or effective for the downhole conditions to be encountered. For example, a well freatment fluid may include a suspension of proppant or sand control particulate that is made up completely of relatively lightweight selected porous material particles that have been selectively configured, such as glazed and/or treated with one or more selected coating and/or penetrating materials. Alternatively, it is possible that a well treatment fluid may include a suspension that contains a mixhire of conventional fracture proppant or sand control particulates such as sand with relatively lightweight selected porous material particles that have been selectively configured such as glazed and/or freated with one or more selected coating and/or penetrating materials. In one exemplary embodiment, a gravel pack operation may be carried out on a wellbore that penetrates a subterranean formation to prevent or substantially reduce the production of formation particles into the wellbore from the formation during production of formation fluids. The subterranean formation may be completed so as to be in communication with the interior of the wellbore by any suitable method known in flie art, for example by perforations in a cased ■wellbore, and/or by an open hole section. A screen assembly such as is known in the art may be placed or otherwise disposed within the wellbore so that at least a portion of the screen assembly is disposed adjacent the subterranean formation. A slurry including the selectively configured porous particulate material or non-selectively configured porous particulate material and a carrier fluid may then be infroduced into the wellbore and placed adjacent the subterranean formation by circulation or other suitable method so as to form a-fluid-permeable pack in an annular area between the exterior of the screen and the interior of the wellbore that is capable of reducing or substantially preventing the passage of formation particles from the subterrane;in formation into the wellbore during production of fluids from the formation, while at the same time allowing passage of formation fluids from the subterranean formation through the screen into the wellbore. It is possible that the slurry may contain all or only a portion of selectively configured porous particulate material or the non-selectively configured porous particulate material. In the latter case, the balance of the particulate material of the slurry may be another material, such as a conventional gravel pack particulate. As an alternative to use of a screen, the sand control method may use the selectively configured porous particulate material or non-selectively configured porous particulate material in accordance with any method in which a pack of particulate material is formed within a wellbore that it is permeable to fluids produced from a wellbore, such as oil, gas, or water, but that substantially prevents or reduces production of formation materials, such as formation sand, from the formation into the wellbore. Such methods may or may not employ a gravel pack screen, may be introduced into a wellbore at pressures below, at or above the fracturing pressure of the formation, such as frac pack, and/or may be employed in conjunction with resins such as sand consolidation resins if so desired. The porous particulate material shall include any naturally occurring or manufactured or engineered porous ceramic particulate material that has an inherent and/or induced porosity. A commercially available instrument, ACCUPYC 1330 Automatic Gas Pycnometer (Micromeritics, Norcross, GA), that uses Helium as an inert gas and the manufacturer"s recommended procedure can be used to determine the internal porosity of the particulates. The internal porosity is generally from about 10 to 75 volume percent. Such particulate material may also have an inherent or induced permeability, i.e., individual pore spaces within the particle are interconnected so that fluids are capable of at least partially moving through the porous matrix, such as penefrating the porous matrix of the particle, or may have inherent or induced non-permeability, individual pore spaces within the particle are disconnected so that fluids are substantially not capable of moving through the porous matrix, such as not being capable of penetrating the porous matrix of the particle. The degree of desired porosity intercormection may be selected and engineered into the non-selectively configured porous particulate material. Furthermore such porous particles may be selected to have a size and shape in accordance with typical fracturing proppant particle specifications {i.e., having a uniform shape and size distribution), although such uniformity of shape and size is not necessary. The apparent specific gravity of fte porous particulatB loaterial is generally less fbsn or equal to Z"A, prefiBrably less than or equal to 2.0, even more preferably less than ox equal to 1.75. most preferably lesa &an or oqual to 1.25. la a seloctively configured porous particulate material, the particles may be selected based on. porosity and/or penoeability daracteristics so diat they have desired ligbtwei’t charactBiistics, such as when suspended in a selected canier fluid for a wsll treatment As before, the isherest and/or induced porosity of a porous material particle may be selected so as to help provide the desired balance between parent density and strength. Optional matstials may be enqiloyed along -wiSi a glazing, penetratiag axLd/or coating mataiial to control penetration, such as enhancing or impairing penetration. For example, in one embodiment an catLonic clay stabilizer, such as CLAY MASTER. 5C from BI Services, may be first applied to the extedor sor&ce of a porons ccianuc matexial to inhibit peaettation by coating/jpenetrsmig sxatenal, snch as epoxy ox resin described elsewhere herein. In a preferred embodiment, tiie porous particulate matedal is a relatively li’tweight or subslantially neutral buoyant particulate material. Such materials may be employed in a manner that elhninates the need for gellation of earner fluid, thus eliminating a source of potentied proppant pacl: and/or fistmation damage. Fmthemiore, a relatively li’tweight particulate material may be easier to place within a targeted zone due to lessened settling constraints, and a reduced mass of such relatively ti’tweight particulate material is generally required to fill an equivalent volonoe dian is required with conventional sand control particulates, used, for example, for gravel packing purposes. Bjelatxvely lightweight and/or substantially neutrally buoyant firactuze prappant/particnlate material used in hydraulic fracturmg/"saQd control treattoeat, such as porous cersmic particles having untreated bulk apparent density of 1.16 and untreated porosity of about 59.3%, may be employed. In one embodiment, the disclosed porous material particulates may be employed as lelalively ligbtweig’ particulate/jiroppant material that may be introduced or pmnped into a well as neutrally buoyant particles in, for example, a satnrated sodium chloride solution carrier fhiid or a carrier fhrid that is any other completictn or workover brine known in die art, thus eliminating the need for "Vrp"gmg polymer or fluid loss material In one embodiment’ such a material may be employed ss proppant/saad control particulate material at temperatures up to about STl"C, and closure stresses up to about 55.2 MPa. However, these ranges of temperature and closure stress are exemplary only, it being understood that the disclosed materials znay be employed as proppam/sand control materials at temperatures greater than about 371°C aixd/or at closure stresses greater than about 552 MPa. In any event, it will be imderstood wilfa benefit of this disclosnra that pototu pailicblste sateiial and/or coatiag’eiietntiiig toatenab tnay be selected by those of still in the art to meet and withstimd anfic’peUed downhole conditions of a given application. In ‘se embodiments where the djjsclosed ponnis matoial paiticnktes are employed as telatiyely lightweight aad/or sabstaatially neutcally buoyant particulate/’ppant niatenals, they may be employed wilb earner fluids ttiat are gelled, noo-geOed, or that have a reduced or ligtaCer gelling reqvdremetlt as cosq>ared to cazrier fluids employed -with conveatjonal fiactme Ireaisient’sand control me&ods. In one embodimenl employing one or more of the disclosed substantially neutialty buoyant paiticolate nutsiials and a btine caixicr fluid, miicrng eqoiqnnest need only include such equqnnsnt Hat is capable of (a) mixing the biine (dissolving soluble salts), and (b) homogeneously dispecsing in the substantially neutrally buoyant paiticiilatB matsiiaL In one embodiment a substantially nsuQaUy buoyant paxticulata’noppant matetial may be advastageously pie-suspe&ded and stored in a storage fluid, such, as biine of near or substantially equal density, aad thisn pumped or placed dowohole as is, or diluted on the fly. Examples of non-natoial porous paniculate matedals for use in the invention include, but are not limited to, porous ceramic particles such as &ose paiticlea available &om Caibo Ceiamics Inc. as "Econopxop", and those fired kaolinitic described in United States Patent No. 5,188,175 which is incorporated herein by referwcB. As described in this refeieace such particles may include solid spherical pellets or particles fiom raw materials (such as kaolin clay) having an alumioa content of between about 25% and 40% and a silica content of between about 50% and 65"A. A starch binder may be employed. Such particles may be cbaractoized as haviilg a ratio of silicon dioxide to alumina content of ficm about 1.39 to about 2.41,. and a apparent specific gravity of between about 2.20 and about 2.60 or between about 2.20-8nd about 2,70. It win also be uadeistood that porous ceramic particles may be selectively moau&ctured torn. law materials sooh as those desoibed in United States Patent No. 5,188,175; United States Patent No. 4,427,068; and United States Patent No. 4,322,731, which are each incorporated hereiQ by refeieace, such as by inclusion, of selected process steps in the initial material manuftctucing process to result in a material diat possesses desired characteristics of porosity, penneabHity, apparent density or apparent specific gravity, combinations tiiereof For example, such taw materials may be-fired at relatively low temperature of about 668" C or about 7W C to achieve a desired crystaJIine structure and a more highly porous and lifter straoture. In one eseinplaiy embodiment of such particles, as described ebewhere herein, about 20/40 mesh size porous material fired kaolinitic particles from Carbo Ceramics Inc. may be selected for use in the disclosed method. These particles have the following internal characteristics: bulk apparent density about 1.16, internal porosity about 59.3%. These particles may be treated with a variety of penetrating/coating materials in an amount of from about 0.5 to about 10% by total weight of particle. Such coated particles may be manufactured and/or supplied, for example, by Fritz Industries of Mesquite, Te.xas. In one exemplary case, size of such a material may be selected to range from about 200 mesh to about 8 mesh. In such a case, the particles may be selected based on porosity and/or permeability characteristics so that they have desired lightweight characteristics, such as when suspended in a selected carrier fluid for a well treatment. As before, the inherent and/or induced porosity of a porous material particle may be selected so as to help provide the desired balance between apparent density and strength. Optional materials may be employed along with a glazing, penetrating and/or coating material to control penetration such as enhance or impair penetration. For example, in one embodiment an cationic clay stabilizer, such as CLAY MASTER 5C from BJ Services, may be first applied to the exterior surface of a porous ceramic material to inhibit penetration by coating/penetrating material, such as epoxy or resin described elsewhere herein. . In a selectively configured porous particulate material, the porous particulate material is chemically treated in order to impart desired physical properties, such as porosity, permeability, appai-ent density or apparent specific gravity, or combinations thereof to the particulate materials. Such desired physical properties are distinct from the physical properties of the porous particulate material"s prior to treatment. The desired physical properties may further be present in non-selectively configured porous particulate materials. Non-selectively configured porous particulate materials shall include naturany occurring porous ceramic materials as well as non-natural (synthetic) materials manufactured in a manner that raiders such desired characteristics. The non-selectively configured particulate material is selected based on desired physical properties, such as porosity, permeability, apparent density, particle size, chemical resistance or combinations thereof. The selectively configured porous particulate material as well as non-selectively configured porous particulate material exhibit crush resistance under conditions as high as 10,000 psi closure stress, API RP 56 or API RP 60, generally between from about 250 to about 8,000 psi closure stress, in combination with a apparent specific gravity less than or equal to 2.4, to meet the pumping and/or downhole formation conditions of a panicular application, such as hydraulic fracturing treatment, sand control treatment Such desired physical properties may be impaned to a portion or portions of the porous particulate material of the selectively configured porous particulate material or non-selectively configured porous particulate material, such as on the particle surface of the material particulate, at or in the particle surface of the particulate material, in an area near the particle surface of a particulate material, in the interior particle matrix of a particulate material or a portion thereof, combinations thereof, etc. Advantageously, in one embodiment the low apparent specific gravity- of the porous particulate material of the selectively configured porous particulate material or non-selectively configured porous paniculate material maybe taken advantage of to result in a larger fi-acture or fi-ac pack width for the same loading, such as pound per square foot of proppant. to give much larger total volume and increased width for the same mass. Alternatively, tliis characteristic allows for smaller loading of proppant material to be pumped while still achieving an equivalent width. hi a preferred embodiment, selective configuration, such as by using glaze-forming, coating and/or penetrating materials, such as those materials described elsewhere herein, may be selectively employed to modify or customize the apparent specific gravity of a selected porous particulate material. Modification of particulate apparent specific gravity, to have a greater or lesser apparent specific gravity, may be advantageously employed, for exainple, to provide proppant or sand control particulates of customized apparent specific gravity for use as a substantially neutrally buoyant particulate with a variety of different weight or apparent specific gravity carrier fluids. The selectively configured porous particulate material has an apparent density fi-om about 1.1 g/cm’to about 2.6 g/cm", a bulk apparent density firom about 1.03 g/cm’ to about 1.5 g/cm\ and an internal porosity firora about 10 to about 75 volume percent. In one example, bulk densities may be controlled to be in the range of from about 1.1 g/cm" to about 1.5 g/cm"*, although greater and lesser values are also possible. The selectively configured porous particulate material, as well as the non-selectively configured particulate material, is generally between from about 200 mesh to about 8 mesh. The selectively configured porous particulate material may comprise porous particulate material selectively altered by treating with a coating or penetrating material using any suitable wet or dry process. Methods for coating particulates, such as fracpjre proppant particles, with materials such as resin are known in the art, and such materiaLs are available, for example, from manufacturers listed herein. With regard to coating of the disclosed porous particulate materials, coating operations may be performed using any suitable methods known in the art. As used herein, the term "penetration" shall further refer to partially or completely impregnated with a penetrating material, by for example, vacuum and/or pressure impregnation. For example, porous particulate material may be immersed in a second material and then exposed to pressure and/or vacuum to at least partially penetrate or impregnate the material. Those of skill in the art will understand that one or more coating and/or penetrating materials may be selected to treat a porous material particulate to meet particular criteria or requirements of given downhole application based on the information and examples disclosed herein, as well as knowledge in the art. In this regard, porous material panicle characteristics, such as composition, porosity and permeability characteristics of the particulate material, size, and/or coating or penetradng material characteristics, such as composition, amount, thickness or degree of penetration, may be so selected. The coating or penetrating material is typically non-porous. The porosity and permeability characteristics of the porous particulate material allows the penetrating material to be drawn at least partially into the porous matrix of the porous particulate material by capillary action, for example, in a manner similar to a sponge soaking up water. Alternatively, one or more penetrating materials may be drawn at least partially into tlie porous matrix of the porous particulate material using a vacuum, and/or may be forced at least partially into the porous matrix under pressure. Examples of penetrating materials that may be selected for use include, but are not limited to, liquid resins, plastics, cements, sealants, binders or any other material suitable for at least partially penetrating the porous matrix of the selected particle to provide desired characteristics of strength/crush resistance, apparent specific gravity, etc. It will be understood that selected combinations of any two or more such penetrating materials may also be employed, either in mixture or in sequential penetrating applications. Examples of resins that may be employed as penetrating and/or coating materials include, but are not limited to, resins and/or plastics or any other suitable cement, sealant or binder that once placed at least partially within a selected particle may be crosshnked and/or cured to form a rigid or substantially rigid material within the porous structure of the particle. Specific examples of plastics include, but are not limited to, nylon, polyethylene, styrene, etc. and combinations thereof. Suitable resins include phenol formaldehyde resins, melamine formaldehyde resins, and urethane resins, low volatile urethane resins, such as these and other types of resins available from Borden Chemical Inc., Santrol, Hepworth of England, epoxy resins and mixtures thereof. Specific examples of suitable resins include, but are not limited to, resins ft-om Borden Chemical and identified as 500-series and 700-series resins (e.g., 569C, 794C, ere). Further specific examples of resins include, but are not limited to, SIGMASET series low temperature curing urethane resins fi-om Borden Chemical, such as SIGMASET, SIGMASET LV, SIGMASET XL, ALPHASET phenolic resin fi"om Borden Chemical, OPTI-PROP phenolic resin fi-om Santrol, and POLAR PROP low temperature curing resin fi"om Santrol. W"Tiere desired, curing characteristics, such as curing time, may be adjusted to fit particular treatment methods and/or final product specifications by, for example, adjusting relative amounts of resin components. Still fijrther examples of suitable resins and coating methods include, but are not limited to, those found in European Patent Application EP 0 771 935 Al; and in U.S. Patents No. 4,869,960; 4,664,819; 4,518.039: 3,929,191; 3,659,651; and 5,422,183, each of the foregoing references being incorporated herein by reference in its entirety. In one exemplary embodiment, a curable phenolic resin or other suitable curable material may be selected and applied as a coating material so that individual coated particles may be bonded together under downhole temperature, after the resin flows and crosslinks/cures downhole, such as to facilitate proppant pack/sand control particulate consolidation after placement. Alternatively, a cured phenolic type resin coat or other suitable cured material may be selected to contribute additional strength to the particles and/or reduce in situ fines migration once placed in a subterranean formation. The degree of penetration of the coating or penetrating fluid into the porous particulate material may be limited by disconnected porosity, such as substantially impermeable or isolated porosity, within the interior matrix of the particulate. This may either limit the extent of uniform penetration of penetrating material in a uniform manner toward the core, such as leaving a stratified particle cross section having outside penetrating layer with unpenetrated substantially spherical core, and/or may cause uneven penetration all the way to the core, such as bypassing "islands" of disconnected ])orosity but penetrating all the way to the core. In any event, a penetrating and/or coatijig material may trap or encapsulate air (or other fluid having apparent specific gravity less than particle matrix and less than coating/penetrating material) within the disconnected porosity in order to reduce apparent specific gravity by the desired amoimt. Such materials coat and/or penetrate the porous particulate without invading the porosity to effectively encapsulate the air within the porosity of the particle. Encapsulation of tiie air provides preservation of the ultra-lightvveight character of the particles once placed in the b-ansport fluid. If the resin coating or transport fluids were to significantly peneh-ate the porosity of the particle, the density increases accordingly, and the particle no longer has the same lightweight properties. The resin coat also adds strength and substantially enhances the proppant pack permeability at elevated stress. Coating la\ers may be applied as desired to contribute to particle strength and/or reduce in situ fmes migration once placed in a subterranean formation. The coating significantly increases the strength and crush resistance of the ultra-lightweiglit ceramic particle, hi the case of natural sands the resin coat protects the particle from crushing, helps resist embedment, and prevents the liberarion of fines. The coating or penetrating fluid is typically selected to have an apparent specific gravity less than the apparent specific gravity of the porous particulate material so that once penetrated at least partially into the pores of the matrix it results in a particle having a apparent specific gravity less than that of the porous particulate material prior to coating or penetration, i.e., filling the pore spaces of a porous particulate material results in a solid or substantially solid particle having a much reduced apparent density. For example, the selected porous particulate material may be treated with a selected penetrating material in such a way that the resultant selectively configured porous particulate material has a much reduced apparent density, such as having a apparent density closer to or approaching the apparent specific gravity of a carrier fluid so that it is neutrally buoyant or semi-buoyant in a fi’cturing fluid or sand control fluid. Alternatively, a penetrating material may be selected so that it helps structurally support the matrix of the porous particulate material (i.e., increases the strength of the porous matrix) and increases the ability of the particulate to withstand the closure stresses of a hydrauhc firactured formation, or other downhole stresses. For example, a penetrating material may be selected by balancing the need for low apparent density versus the desire for strength, i.e., a more dense material may provide much greater strength, hi this regard, the inherent and/or induced porosity of the porous particulate material may be selected so as to help provide the desired balance between apparent density and strength. It wiU be understood that other variable, such as downhole temperature and/or fluid conditions, may also impact the choice of penetrating materials. The coating layer or penetrating material is generally present in the selectively configured porous particulate material in an amount of firora about 0.5% to about 10% by weight of total weight. The thickness of the coating layer of the selectively configured porous particulate material is generally between fi-om about 1 to about 5 microns. The extent of penetration of the penetrating material of the selectively configured porous particulate material is firom less than about 1% penetration by volume to less than about 25% penetrationby volume. Especially preferred results are obtained when the porous particulate material is a porous ceramic particle having an apparent density of 1.25 or less and untreated porosity is approximately 60%. Such materials may be treated with a coating material that does not penetrate the porous matrix of the porous pailiculate material, or that only partially penetrates the porous matrix of the ceramic particulate material. Such treated ceramic materials may have an apparent density from about 1.1 g/cm"" to about 1.8 g"cm’ (alternatively from about 1.75 g/cm"" to about 2 g/cm’ and further altematively about 1.9 g/cm’;). a bulk apparent densit> from about 1.03 g/cm’ to about 1.5 g/cm\ and a treated internal porosity from about 45"? o to about 55%. However, values outside these exemplary ranges are also possible. .\s an example, a porous ceramic treated with about 6% epoxy has been ."‘een to exhibit a bulk apparent density of about 1.29 and a porosity of about 50.6%, a porous ceramic treated with about 8% epoxy exhibits a bulk apparent density of about 1.34 and a porosity of about 46.9%, a porous ceramic treated with about 6% phenol formaldehyde resin exhibits a bulk apparent density of about 1.32 and a porosity of about 51.8%, and a porous ceramic treated with about 8% phenol formaldehyde resin exhibits a bulk apparent density of about 1.20 and a porosity of about 54.1%. In this embodiment, a coating material or penetrating material may be selected to be present in an amount of from about 0.5% to about 10% by weight of total weight of individual particles. When present, thickness of a coating material may be selected to be from about 1 to about 5 microns on the exterior of a particle. Wlien present, extent of penefration penefrating material into a porous material particle may be selected to be from less than about 1% penetration by volume to less than about 25% penetration by volume of the particle. It will be understood that coating amounts, coating thickness, and penetration amounts may be outside these exemplary ranges as well. Further, the porous particulate material may be at least partially selectively configured by glazing, such as, for example, surface glazing with one or more selected non-porous glaze materials. In such a case, the glaze, like the coating or penetrating material, may extend or penetrate at least partially into the porous matrix of the porous particulate material, depending on the glazing method employed and/or the permeability (i.e., connectivity of internal porosity) characteristics of the selected porous particulate material, such as non-connected porosity allowing substantially no penetration to occur. For example, a selected porous particulate material may be selectively configured, such as glazed and/or coated with a non-porous material, in a manner so that the porous matrix of the resulting particle is at least partially or completely filled with air or some other gas, i:e.." the interior of the resulting particle includes only air/gas and the structural material forming and surrounding the pores. Once again, the inherent and/or induced porosity of a porous material particle may be selected so as to help provide the desired balance between apparent density and strength, and glazing and/or coating with no penetration (or extension of configured area into the particle matrix) may be selected to result in a particle having all or substantially all porosity of the particle being unpenetrated and encapsulated to trap air or other relatively lightweight fluid so as to achieve minimum apparent specific gravity. In addition to sealing a particle, such as to seal air/gas within the porous matrix of the particle, such selective configuration, such as using glazing and"or coating materials, may be selected to provide other advantages. In a preferred embodiment, the porous particulate material, such as the above-described fired kaolinitic particles, is irianufactured by using a glaze-forming material to form a glaze to seal or otiierwise alter the permeability of the particle surface, so that a gi\en particle is less susceptible to invasion or saturation by a well treatment fluid and thus capable of retaining relatively lightweight or substantially neutrally buoyant characteristics relative to the well treatment fluid upon exposure to such fluid. Such glazing may be accomplished using any suitable method for forming a glaze on the surface or in the near surface of a particle, including by incorporating a glaze-forming material into the raw material "green paste" that is then formed such as molded into shape of the particle prior to firing. Those skilled in the art recognize that glazes may be made firora a variety of methods, including the application of a smooth, glassy coating such that a hard, nonporous surface is formed. Glazes may be formed firom powdered glass with oxides. The mixture of powders is suspended in water and applied to the substrate. The glaze can be dried and then fixed onto the substrate by firing or similar process known to those skilled in the art. Additionally, the use of borates or similar additives may improve the glaze. Examples of such glaze-forming materials include, but are not limited to, materials such as magnesium oxide-based material, boric acid/boric oxide-based material, etc. During firing, the glaze-forming material/s "bloom" to the surface of the particles and form a glaze. Alternatively, glazing may be accomplished, for example, by applying a suitable glaze-forming material onto the surface of the formed raw material or "green" particles prior to firing such as by spraying, dipping, and similar methods so that glazing occurs during partitle firing. Further alternatively, a glaze-forming material may be applied to a fired ceramic particle, and then fired again in a separate glaze-forming step. In one embodiment, the glaze forms a relatively hard and relatively non-porous surface during firing of the particles. Advantages cf such a glazing treatment include maintaming the relati\ ely low apparent density of a relatively lightweight porous particle without the necessity of further alteration, such as necessity of coating with a separate polymer coating although optional coatings may be applied if so desired. Furthermore, the resulting relatively smooth glazed surface of such a particle also may ser\e to enhance the ease of multi phase fluid flow, such as flow of water and gas and oil, through a particulate pack, such as thrcugli a proppant pack in a fracmre, resulting in increased fracture conductivity. In an alternative embodiment, one or more types of the disclosed selectively configured porous particulate material or non-selectively configured porous particulate material may be employed as particulates for well treating purposes in combination with a variety of different types of well treating fluids (including liquid CO’-based systems and other liquefied-gas or foamed-gas carrier fluids) and/or other types of particulates such as to achieve synergistic benefits, it being understood that benefits of the disclosed methods and compositions may also be achieved when employing only one type of the disclosed porous materials as a sole well treating particulate. Furthermore, although exemplary embodiments are described herein with reference to porous materials and to relatively lightweight porous materials, it will be understood that benefits of the disclosed methods and compositions may also be realized when applied to materials that may be characterized as non-relatively lightweight and/or non-porous in nature. Elimination of the need to formulate a complex suspension gel may mean a reduction in tubing fiiction pressures, particularly in coiled tubing and in the amount of on-location mixing equipment and/or mixing time requirements, as well as reduced costs. Furthermore, when selectively configured, such as by glazing and/or by treating with coating/penetrating material, to have sufficient strength and relative lightweight properties, the disclosed relatively particles may be employed to simplify hydraulic fi-acturing treatments or sand control treatments performed through coil tubing, by greatly reducing fluid suspension property requirements. Downhole, a much reduced propensity to settle (as compared to conventional proppant or sand control particulates) may be achieved, particularly in highly deviated or horizontal wellbore sections. In this regard, the disclosed particulate material may be advantageously employed in any deviated well having an angle of deviation of between about 0 degree and about 90 degrees with respect to the vertical. However, in one embodiment, the disclosed particulate material may be advantageously employed in horizontal wells, or in deviated wells having an angle with respect to the vertical of between about 30 degrees and about 90 degrees, alternatively between about 75 degrees and about 90 degrees. Thus, use of the disclosed particulate materials disclosed herein may be employed to achieve surprising and unexpected improvements in fracturing and sand control methodology, including reduction in proppant pack and/or formation damage, and enhancement of well productivity. It will be understood that the characteristics of glazing materials, penetrating materials and/or coating materials given herein, such as composition, amounts, types, are exemplary only. In this regard, such characteristics may be selected with benefit of this disclosure by those of skill in the art to meet and withstand anticipated downhole conditions of a given application using methods known in the art, such as those described herein. In another disclosed embodiment, blends of two or more different types of particles having different particulate characteristics, such as different porosity, permeability, apparent density or apparent specific gravity, settling velocity in carrier fluid, may be employed as well treatment particulates. Such blends may contain at least one porous particulate material and at least one other particulate material that may or may not be a porous particulate material. In addition, the selectively configured porous particulate material and non-selectively configured porous particulate material may be used as two or more multiple layers. In this regard, successive layers of such materials may be employed. For instance, multiple layers may consist of at least one selectively configured porous particulate material and at least one non-selectively configured porous particulate material. In one exemplary embodiment, a selected coating or penetrating material may be a urethane, such as ethyl carbamate-based resin, applied in an amount of about 4% by weight of the total weight of the selected porous material particle. A selected coating material may be applied to achieve a coating layer of at least about 2 microns thick on the exterior of the selected porous material particle. Such blends may be fiirther employed in any type of well treatment application, including in any of the well treatment methods described elsewhere herein. In one exemplary embodiment, such blends may be employed to optimize hydraulic fracture geometries to achieve aihanced well productivity, such as to achieve increased propped fi-acture length in relatively "tight" gas formations. Choice of different particulate materials and amounts thereof to employ in such blends may be made based on one or more well treatment considerations including, but not limited to, objective/s of well treatmait, such as for sand control and/or for creation of propped firactures, well treatment fluid characteristics, such as apparent specific gravity and/or rheology of carrier fluid, well and formation conditions such as depth of formation, formation porosity/permeability, formation closure stress, type of optimization desired for geometry of downhole-placed particulates such as optimized fracture pack propped length, optimized sand control pack heighi, optimized fracture pack and/or sand control pacK conduinivity and combinations thereof. Such different types of particles may be selected, for example, to achieve a blend of different specific gra\ities or densities relative to tlie selected carrier fluid. For example, a blend of three different parricles may be selected for use in a water fracture treatment to form a blend of well treatment particulates having three different specific gravities, such as .-pparent specific gravity of first type of particle from about 1 to less about 1.5; apparent specific gravity of second type of particle from greater than about 1.5 to about 2,0; and apparent specific gravity of third tjpe of particle from about greater than about 2.0 to about 3.0; or in one specific embodiment the three types of particles having respective specific gravities of about 2.65, about 1.7 and about 1.2, it being understood that the preceding apparent specific gravity values are exemplary only and that other specific gravities and ranges of specific gravities may be employed. In one example, at least one of the types of selected well treatment particulates may be selected to be substantially neutrally buoyant in the selected carrier fluid. Such different types of particles may be selected for use in any amount suitable for achieving desired well treatment results and/or costs. However, in one embodiment multiple types of particles may be selected for use in a blend of well treatment particulates in amounts that are about equal in proportion on the basis of total weight of the blend. Thus, three different types of particles may each be employed in respective amounts of about 1/3 of the total blend such as by total weight of the blend, four different types of particles may each be employed in respective amounts of about "A of the total blend such as by total weight or the blend However, these relative amounts are exemplary only, it being understood that any desired relative amount of each selected type of well particulate may be employed, such as for one exemplary embodiment of blend having three different types of particles, such as selected from the different types of particles described elsewhere herein, the amounts of each selected type of particle may be present in the blend in an amount ranging from about 10% to about 40% such as by total weight of the blend to achieve 100% weight of the total blend. It will be understood with benefit of this disclosure that choice of different particulate materials and amounts thereof to employ in such blends may be made using any methodology suitable for evaluating such blends in view of one or more desired well treatment considerations. In one embodiment, any method known in the art suitable for modeling or predicting sand control pack or fracture pack geometry/conductivity may be employed, such as illustrated and described in relation to Example 4 herein. Examples of different particle types which may be selected for xise in such blends include, but are not limited to, conventional sand particulates, such as Ottawa sand, relatively lightweight well treatment particulates, such as ground or crushed nut shells at least partially surrounded by at least one layer component of protective or hardening coating, selectively configured porous materials, such as any one or more of the selectively configured porous materials described herein, such as deformable particles. Further examples of pjurticle types which may be selected for use in such blends include any of those particles described in U.S. Patent Application Serial No. 10/113,844, filed April 1, 2002; U.S. Patent Application Serial No. 09/579,146, filed May 25, 2000; U.S. Patent No. 6,364,018; U.S. Patent No. 6.330,916; and U.S. Patent No. 6,059,034, each of which is incorporated herein by reference. In one exemplary embodiment, selected blends of conventional sand proppant, relatively lightweight particulates of ground or crushed nut shells at least partially surrounded by at least one layer component of protective or hardening coating, and selectively configured porous materials such as relatively lightweight porous material fired kaolinitic particles treated with a penetrating/coating materials described herein may be employed in a hydraulic firacture treatment utilizing ungelled or weakly gelled carrier fluid. One specific example of such a blend is described in Example 4 herein. In such an embodiment, these different types of particles may be employed in any relative volume or weight amount or ratio suitable for achieving desired well treatment results. In one specific example, these different types of particles may be employed in a well treatment particulate composition including about 1/3 by weight of conventional sand proppant by total weight of well treatment particulate, about 1/3 by weight of relatively lightweight particulate, such as core of ground or crushed nut shells at least partially surrounded by at least one layer component of protective or hardening coating) by total weight of well treatment particulate, and about 1/3 by weight of selectively configured relatively lightweight porous material, such as fired kaolinitic particles treated with a penetrating/coating materials described herein, by total weight of well tireatment particulate. It will be understood that the foregoing relative amo\ints are exemplary only and may be varied, for example, to achieve desired results and/or to meet cost objectives of a given treatinent. It will also be understood that the disclosed methods and compositions may also be practiced with such blends using other types of relatively lightweight particulate materials as described elsewhere herein, such as porous polymeric materials, such as polyolefins, styrene-divinylbenzene based materials, pqlyalkylacrylate esters and modified starches. Further, any of the disclosed porous materials may be employed in "neat" or non-altered form in the disclosed blends where apparent density jind other characteristics of the particle are suitable to mcsi requirements of the gi\en well treating application. In one respect, disclosed are well treating methods, such as hydraulic fiacturing and sand control, which may be employed to treat a well penetrating a subterranean formation, and include introducing into a well a selected porous particulate material that is treated with a selected coating material, selected penetrating material, or combination thereof Indi\idual particles of the particulate material optionally may have a shape with a maximum length-based aspect ratio of equal to or less than about 5. In one embodiment porous particulate materials may be any particulate material with suitable internal porosity and/or permeability characteristics to achieve the desired finished particle properties when combined with selected penetrating/coating materials as described elsewhere herein. Examples of suitable porous material particulates that may be selected for use in aqueous based carrier fluids include, but are not limited to porous ceramics, porous pohmeric materials or any other porous material or combinations thereof suitable for selection for combination of internal porosity and permeability to achieve desired properties, such as strength and/or apparent specific gravity, for particular downhole conditions and/or well treatment applications as described elsewhere herein. For example, porous ceramic particles may be manufactured by firing at relatively low temperatures to avoid loss of porosity due to crystallization and driving off of water. Particular examples include, but are not limited to, porous ceramic particles available from Carbo Ceramics Inc. of Lrving, Texas composed of fired kaolinitic clay that is fired at relatively low temperature of about 1235"? or about ISOO’F (or about 700°C and that has trace amounts of components such as cristobalite, mullite and opalite), polyolefin particles, and similar components. In another disclosed embodiment, relatively lightweight particulates or blends including such particulates as described elsewhere herein, such as including selectively (Xinfigured particulates and/or non-selectively configured particulates described elsewhere herein, may be advantageously employed as well treatment particulates, such as fi-acture proppant particulate or sand control particulate, in liquefied gas and foamed gas carrier fluids. Examples of types of such carrier fluids include, but are not limited to, liquid C02-based systems, liquid CO2, CO2/N2, and foamed N2 in CO2 systems that may be employed in hydraulic fi-acturing applications. In one specific embodiment, porous ceramic well particulates having a bulk apparent density of close to or about 1.0 g/cm’ in either selectively configured or non-selectively configured form, may be employed with such liquefied gas and/or foamed gas carrier fluids, such as liquid COj-based systems, liquid C02,-C02/N2, and foamed Ni in CO2 systems. In another specific embodiment, selectively configured particulates and/or non-selectively configured particulates may be employed that may be characterized as substantially neutrally buoyant in such liquefied gas and/or foamed gas carrier fluids. Liquid CO2 has a density close to about 1.02 g/cra’ under typical fiacturing conditions, and conventional proppants, such as sand, or non-relatively lightweight ceramic proppants have a tendency to settle in liquid C02-based systems. Furthermore, liquid CO2 has \ery little if any viscosity, and therefore proppant transport in a liquid COj-based system is provided by turbulence and fiictional forces, and fractures created by liquid CC)2 are typically relatively narrow. Advantageously, using the disclosed methods and compositions, proppant transport of relatively lightweight particulates is easier than is proppant transport of conventional sand proppants or non-relatively lightweight ceramic proppants. In one exemplary embodiment, relatively lightweight porous ceramic particles may be employed in liquid CC’-based systems. Examples of types of such relatively lightweight porous ceramic particles include, but are not limited to, those porous ceramic particles available from Carbo Ceramics for controlled release applications altered in the manufacturing process to have a bulk apparent density close to about 1.0 g/cm". Other suitable examples of relatively lightweight porous particles include, but are not limited to, those particles having a bulk apparent density of less than about 2.5 g/cm"", alternatively having a bulk apparent density of from about 1.0 to about 2.0 g/cm\ fijrther alternatively having a bulk apparent density of from about 1.2 g/cin" to about 2.0 g/cml One specific example of suitable relatively lightweight porous ceramic particle for use in C02-based systems of this embodiment is porous ceramic material described elsewhere herein, either in selectively configured form, as described herein in Example 1, or in non-selectively configured or non-altered or "neat" form. In one exemplary embodiment, the practice of the disclosed methods and compositions, relatively lightweight porous ceramic materials or blends thereof may be employed as fracture proppant materials in liquid COa-based fracturing systems using methodologies similar or the same to those employed with conventional proppants in liquid COa-based firacturing systems. In this regard, liquid COa-based firacturing job characteristics, such as proppant amounts, proppant sizes, mixing and pumping methodologies, using relatively lightweight porous ceramic materials may be the same as described for conventional proppants in "The History and Success of Liquid CO2 and CO2/N2 Fracturing System" by Gupta and Bobier, SPE 40016, March 1998. Further information on liquid COa-based firacturing job characteristics that may be employed with " relatively lightweight porous ceramic materials may be found in United States Patent No. 4,374,545, United States Patent No. 5,558,160, United States Patent No. 5,SS}.053, Canadian Patent No. 2,257,028 and Canadian Patent No. 2,255,413, each of the foregoing references being incorporated herein b>- reference. In one disclosed exemplary embodiment, relatively lightweight porous ceramic particles employed as fracture proppant particulate in a liquid CO:-based system may be lused in "neat" or non-altered form and may have a apparent specific gravity of from about 1.17 to about 2.0 In another disclosed exemplary embodiment, using relatively lightweight porous ceramic particles as fracture proppant particulate in a liquid CIO-based system allows the concentration of proppant in such a system to be advantageously extended to about 1200 Kg cubic meter. Other advantages of using the disclosed relatively lightweight porous ceramic panicle.’ in liquid CO2-based fracturing systems include, but are not limited to, reduced proppant settling in surface mixing equipment prior to pumping downhole and improved proppant transport downhole and into the formation. It will be understood that although described abo\e for embodiments employing relatively lightweight porous ceramic particles, the disclosed methods and compositions may also be practiced with liquid CO’-based .systems using other relatively lightweight porous material particulate materials and blends thereof described elsewhere herein, such as porous polymeric materials such as polyolefin’s. Any of such materials may be employed in "neat" or non-altered fond with liquid COo-based systems where apparent density and other characteristics of the particle are suitable to meet requirements of the gi\en well treating application, or may alternatively be employed in selectively configured form as described elsewhere herein. The following examples will illustrate the practice of the present invention in a preferred embodiment. Other embodiments within the scope of the claims herein will he apparent to one skilled in the art from consideration of the specification and practice of the invention as disclosed herein. It is intended that the specification, together with the example, be considered exemplary only, with the scope and spirit of the invention being indicated by the claims which follow. EXAMPLES The following examples are illustrative and should not be construed as limiting the scope of the invention or claims thereof. Example 1: To obtain the data for this example, the following procedure was followed: Measured mass of 25 ml of sample on a graduate cylinder. Cylinder was tapped several times on the WE CLAIM : 1. A particulate material which is (a) a ceramic, polyolefin, styrene-divinylbenzene copolymer or polyalkylacrylate ester (b) porous; and (c) treated with a coating material, penetrating material or glaze, wherein one of the following conditions prevail: (i) air or a relatively lightweight fluid is encapsulated or entrapped within the pores of the particulate material and wherein the ceramic, polyolefin, styrene-divinylbenzene copolymer or polyalkylacrylate ester exhibits inherent or induced permeability; (ii) the apparent specific gravity of the treated porous particulate material is less than the apparent specific gravity of the untreated porous particulate material and wherein the ceramic, polyolefin, styrene-divinylbenzene copolymer or polyalkylacrylate ester exhibits inherent or induced permeability; (iii) the strength of the treated porous particulate material is greater than the strength of the untreated porous particulate material when the porous ceramic, polyolefin, styrene-divinylbenzene copolymer or polyalkylacrylate ester and wherein the ceramic, polyolefin, styrene-divinylbenzene copolymer or polyalkylacrylate ester exhibits inherent or induced permeability; (iv.) the porous particulate material is treated or modified with a glazing material. 2. The material as claimed in claim 1, which is of size 200 mesh to 8 mesh. 3. The material as claimed in claim 1 or 2 wherein the apparent specific gravity of the porous particulate is not more than 2. 4. The material as claimed in claim 3, which the apparent specific gravity of the porous particulate is not more than 1.75. 5. The material as claimed in claim 4, wherein the apparent specific gravity of the porous particulate is not more than 1.25. 6. The material as claimed in any preceding claim, wherein the treated porous particulate material has an apparent density of 1.1-2.6 g/cm^. 7. The material of any preceding claim, wherein the treated porous particulate material has a bulk apparent density of 1.03-1.4 g/cm"". 8. The material of any of the preceding claims, wherein individual particles of the porous particulate material have a maximum length-based aspect ratio of equal to or less than about 5. 9. The material of any preceding claim, wherein the particles of the porous ceramic material have a cationic clay stabilizer applied to their exterior surfaces for inhibiting penetration by coating/penetrating material. 10. The material as claimed in any preceding claim, coated with material of thickness 1-5\|jjn. 11. The material as claimed in any preceding claim, wherein the penetrating or coating material is a liquid resin, plastic, cement, sealant or binder. 12. The material as claimed in claim 11, wherein the particulate material is coated or penetrated with a curable resin. 13. The material as claimed in any of claims 1 to 11, wherein the coating or penetrating material is a phenol, phenol formaldehyde, melamine formaldehyde, urethane, epoxy resin, nylon, polyethylene or polystyrene or a combination thereof 14. The material as claimed in claim 13, treated with an epoxy resin or phenol formaldehyde resin. 15. The material as claimed in any of claims 1 to 10, wherein the particles comprise an epoxy inner coating/penetrating material and a phenol formaldehyde outer coating material. 16. The material as claimed in any preceding claim, wherein particles of the treated particulate material comprise a multitude of the porous particles bonded together. 17. The material as claimed in claim 16, wherein the particulate material is coated or penetrated with a curable resin. 18. The material as claimed in any preceding claim, wherein the permeability of the treated porous particulate material is less than the permeability of the untreated porous particulate material. 19. A method of making the material of any preceding claim which comprises: providing porous permeable particulate material which is a ceramic, polyolefin, styrene-divinylbenzene copolymer or polyalkylacrylate ester; and treating said porous permeable particulate material with a penetrating material which is a liquid resin, plastics, cement, sealant or binder suitable for at least partially penetrating the porous material, the porosity of the porous material being such that the penetrating material can be drawn or forced at least partially into the porous matrix of the porous particulate material by capillary action, vacuum or pressure. 20. A composition for treating a well comprising: a carrier fluid and at least one material as claimed in any of claims 1 to 18 or porous particulate material of a natural ceramic. 21. The composition as claimed in claim 20, wherein the porous particulate material is a natural ceramic of a lightweight volcanic rock. 22. The composition as claimed in claim 21, wherein the natural ceramic is pumice, prelate, Hawaiian basalt, Virginia diabase or Utah hyalites. 23. The composition as claimed in any of claims 20 to 22, wherein the carrier fluid is salt water, fresh water, a liquid hydrocarbon, or a gas or a mixture thereof 24. The composition as claimed in any of claims 20 to 23, wherein the particulate material is relatively lightweight and/or substantially neutrally buoyant. 25. The composition as claimed in any of claims 20 to 24, wherein the carrier fluid is a completion or workover brine. 26. The composition as claimed in any of claims 20 to 25, wherein the carrier fluid is a liquefied gas or foamed gas carrier fluid or a mixture thereof, such as liquid carbon dioxide or liquid carbon dioxide/nitrogen. 27. The composition as claimed in any of claims 20 to 24, wherein the composition is a suspension which, when introduced into the well, forms a fluid-permeable gravel pack in an annular area defined between the exterior of a screen assembly and the interior of the wellbore. 28. The composition as claimed in any of claims 20 to 27, which further comprises one or more of a friction reducer, gelling agent, crosslinking agent, gel breaker, surfactant, foaming agent, demulsifier, buffer, clay stabilizer, acid or mixture thereof 29. The composition as claimed in any of claims 20 to 28, wherein the carrier fluid is non-gelled. 30. A method for treating a well penetrating a subterranean formation, comprising introducing into the well any of the following materials: (a) a material according to any of claims 1 -18 or a composition of any of claims 20 to 29; or (b) a porous organic polymeric material treated with a penetrating, coating or glazing material, wherein air or a fluid is encapsulated by or trapped within the porosity of the treated porous organic polymeric material; or (c) a proppant of a porous material which is an organic polymeric material treated with a coating or penetrating material, wherein the coating or penetrating material penetrates the organic polymeric material, without invading the porosity of the organic polymeric material, to effectively encapsulate air within the porosity of the organic polymeric material; or (d) a proppant of a porous organic polymeric material treated with a coating, penetrating or glazing material, wherein the proppant is introduced into the well at concentrations sufficient to achieve a partial monolayer fracture. 31. The method as claimed in claim 30, wherein the material exhibits crush resistance milder conditions from 2,500 psi to 10,000 psi closure stress. 32. The method as claimed in claim 30 to 31, wherein the organic polymeric material is a polyolefin. 33. The method as claimed in any of claims 30 to 32, wherein the material is introduced into the well as a slickwater fracturing fluid. 34. The method as claimed in any of claims 30 to 33, wherein the well is a vertical well. 35. The method as claimed in any of claims 30 to 33, wherein the well is a deviated well. 36. The method as claimed in any of claims 30 to 33, wherein the well is a horizontal well. 37. The method as claimed in any claims 30 to 33, wherein the treatment is for hydraulic fracturing. 38. The method as claimed in any of claims 30 to 33, wherein the method is for sand control. 39. Use as a proppant in a wellbore of the material as defined in any of claims 1 to 18.

Full Text

METHOD OF TREATING SUBTERRANEAN FORMATIONS WITH POROUS CERAMIC PARTICULATE MATERIALS
SPECIFICATION Field of the Invention
This invention relates generally to methods and compositions useful for subterranean formation treatments, such as hydraulic fracturing treatments and sand control. Background of tile Invention
Hydraulic fracturing is a common stimulation technique used to enhance production of fluids from subterranean formations. In a typical hydraulic fracturing treatment, fracturing treatment fluid containing a solid proppant material is injected into the formation at a pressure sufficiently high enough to cause the formation or enlargement of fractures in the reservoir. During a typical fracturing treatment, proppant material is deposited in a fracture, where it remains after the treatment is completed. Afire deposition, the proppant material serves to hold the fracture open, thereby enhancing the ability of fluids to migrate the formation to Hoe well bore through the fracture. Because fractured well productivity depends on the ability of a fracture to conduct fluids from a formation to a wellbore, fracture conductivity is an important parameter in determining the degree of success of a hydraulic fracturing treatment.
Hydraulic fracturing treatments commonly employ proppant materials that are placed downhole with a gelled carrier fluid such as aqueous\is-based fluid such as gelled brine. Gelling agents for proppant carrier fluids may provide a source of proppant pack and/or formation damage, and settling of proppant may interfere with proper placement downhole. Formation damage may also be caused by gelled carrier fluids used to place particulates downhole for purposes such as for sand control, such as gravel packs, franc packs, and similar materials. Formulation of gelled carrier fluids usually requires equipment and mixing steps designed for this purpose.
Hydraulic fracturing treatments may also employ proppant materials that are placed downhole with non-aqueous-based fluids, such as liquid CO2 and liquid CO2/N2 systems. Proppants commonly employed with such non-aqueous-based fluids tend to settle in the system.
Many different materials have been used as proppants including sand, glass beads, walnut hulls, and metal shot. Commonly used proppants today include various sands, resin-coated sands, intermediate strength ceramics, and sintered bauxite; each employed for their ability to cost effectively withstand the respective reservoir closure stress environment. As the relative strength of the various materials increases, so too have the respective particle densities, ranging from 2.65 g/cc for sands to 3.4 g/cc for the sintered bauxite. Unfortunately, increasing particle density leads

directly to increasing degree of difficulty with proppant transport and a reduced propped fracture volume for equal amounts of the respective proppant, reducing fracture conductivity. Previous efforts undertaken to employ lower density materials as proppant have generally resulted in failure due to insufficient strength to maintain fracture conductivity at even the lowest of closure stresses (1,000 psi).
Recently, deformable particles have been developed. Such deformable particles for sand flowback control are significantly lighter than conventional proppants, and exhibit high compressive strength Such deformable materials include polystyrene divinylbenzene (PSDVB) deformable beads. Such beads, however, have not been entirely successful primarily due to limitations of the base material. While PSDVB beads offered excellent deformability and elasticity, they lacked the structural integrity to withstand high closure stresses and temperatures.
The first successful path to generate functional deformable particles was the usage of modified ground walnut hulls. Walnut hulls in their natural state have been used as proppants, fluid loss agents and lost circulation materials for many years with greater or lesser degrees of success in each respective task. As a proppant, natural walnut hulls have very limited applicability, because they deform fairly readily upon application of closure stress. This deformation drastically reduces conductivity and limits utility of the natural material to relatively low-closure environments.
Walnut hull based ultra-lightweight (UCW) proppants may be manufactured in a two-step process by using closely sized washout particles (i.e. 20/30 US mesh), and impregnating them with strong epos.\y or other resins. These impregnated walnut hull particles are then coated with phenolic or other resins in a fashion similar to most resin coated proppants (RCP). Such walnut hull based ULW proppants have a bulk density of 0.85 grams/cc and withstand up to 6,000 psi (41.4 MPa) closure stress at 175°F (79°C).
Generally speaking, the stronger a proppant, the greater the density. As density increases, so too does difficulty of placing that particle evenly throughout the created fracture geometry. Excessive settling can often lead to bridging of the proppant in the formation before the desired stimulatwn is achieved. The lower particle density reduces the fluid velocity required to maintain proppant transport within the fracture, which, in tam, provides for a greater amount of the created fracture area to be propped.
ULW proppants which allow for optimization of fracturing treatment with improved fracture length and well productivity are therefore desired.

Summary of the Invention
The invention relates to methods for treating subterranean formations by creating a well with a composition containing porous ceramic or organic polymeric particulates. In particular, the compositions introduced into the well are particularly suitable in hydraulic fracturing of a well as well as sand consolidation methods such as gravel packing and franc packing. The porous particulate material may be a selectively configured porous particulate material, as defined herein. Alternatively, the porous particulate material may be a non-selectively configured porous particulate material, as defined herein.
The porous particulate material may be selectively configured with a non-porous penetrating material, coating layer or glazing layer. In a preferred embodiment, the porous particulate material is a selectively configured porous particulate material wherein either (a.) the apparent density or apparent specific gravity of the selectively configured porous particulate material is less than the apparent density or apparent specific gravity of the porous particulate material; (b.) the permeability of the selectively configured porous particulate material is less than the permeability of the porous particulate material; or (c.) the porosity of the selectively configured porous particulate material is less than the porosity of the porous particulate material.
In a preferred embodiment, the penetrating material and/or coating layer and/or glazing layer of the selectively configured porous particulate material is capable of trapping or encapsulating a fluid having an apparent specific gravity less than the apparent specific gravity of the carrier fluid. Further, the coating layer and/or penetrating material and/or glazing material may be a liquid having an apparent specific gravity less than the apparent specific gravity of the matrix of the porous particulate material.
The strength of the selectively configured porous particulate material is typically greater than the strength of the porous particulate material per se. Further, the selectively configured porous material exhibits crush resistance under conditions as high as 10,000 psi closure stress, API RP 56 or API RP 60.
In a preferred mode, the porous particulate composition is a suspension of porous particulates in a earner fluid. The suspension preferably forms a pack of particulate material that is permeable to fluids produced food the wellbore and substantially prevents or reduces production of formation materials food the formation into the wellbore.
Further, the porous particulate material may exhibit a porosity and permeability suds that a fluid may be drawn at least partially into the porous matrix by capillary action. Preferably, the porous particulate material has a porosity and permeability such that a penetrating material may

be drawn at least partially into the porous matrix of the porous particulate material using a vacuum and/or may be forced at least partially into the porous matrix under pressure.
The selectively configured porous particulate material may consist of a multitude of coated particulates bonded together. In such manner, the porous material is a cluster of particulates coated with a coating or penetrating layer or glazing layer. Suitable coating layers or penetrating materials include liquid and/or curable resins, plastics, cements, sealants, or binders such as a phenol, phenol formaldehyde, melamine formaldehyde, urethane. epoxy resin, nylon, polyethylene or a combination thereof In a preferred mode, the coating layer or penetrating material is an ethyl carbonate-based resin.
In a preferred embodiment, the selectively configured porous particulate materials are derived from lightweight and/or substantially neutrally buoyant particles. The application of selected porous material particulates and relatively lightweight and/or substantially neutrally buoyant particulate material as a fracture proppant particulate advantageously provides for substantially improved overall system performance in hydraulic fracturing applications, or in other well treating applications such as sand control.
The porous particulate material-containing compositions used in the invention may fritter contain a carrier fluid. The carrier fluid may be a completion or workover brine, salt water, fresh water, a liquid hydrocarbon, or a gas such as nitrogen or carbon dioxide.
The porous particulate material-containing compositions may further contain a gelling agent, crosslinking agent, gel breaker, surfactant, taming agent, demulsifier, buffer, clay stabilizer, acid or a mixture thereof. Brief Description of the Drawings
In order to more fully understand the drawings referred to in the detailed description of the present invention, a brief description of each drawing is presented, in which:
FIG. 1 is a graph depicting bulk apparent density comparison of the data of Example 1.
FIG. 2 is a graph depicting amiability versus closure stress data of Example 2.
FIG. 3 is a graph depicting conductivity versus closure stress data of Example 2.
FIG. 4 is a graph depicting conductivity versus closure stress data of Example 2.
FIG. 5 is a graph depicting permeability versus closure stress data of Example 2.
FIG. 6 is a graph depicting conductivity comparison data of Example 2.
FIG. 7 is a graph depicting permeability comparison data of Example 2.
FIG. 8 is a SEM photograph of a porous material particle of Example 3.
FIG. 9 is a SEM photograph of a porous material particle of Example 3.
FIG. 10 is a SEM photograph of a porous material particle of Example 3.

FIG. 11 is a SEM photograph of a porous material particle of Example 3.
FIG. 12 is a SEM photograph of a porous material particle of Example 3.
FIG. 13 is a SEM photograph of a porous material particle of Example 3.
FIG. 14 is a SEM photograph of a porous material particle of Example 3.
FIG. 15 is a SEM photograph of a porous material particle of Example 3.
FIG. 16 illustrates proppant distribution for a selected combination or" well treatment particulates according to one embodiment of the disclosed compositions and methods described in Example 4.
FIG. 17 illustrates comparative proppant distribution data of Example 4 for Ottawa sand alone. Detoured Description of the Preferred Embodiments
As used herein, the following terms shall have the designated meanings:
"porous particulate material" shall refer to porous ceramic or porous organic polymeric materials. Examples of types of materials suitable for use as porous material particulates include particulates having a porous matrix;
"selectively configured porous particulate material" shall refer to any porous particulate material, natural or non-natural, which has been chemically treated, such as treatment with a coating material; treatment with a penetrating material; or modified by glazing. The term shall include, but not be limited to, those porous particulate materials which have been altered to achieve desired physical properties, such as particle characteristics, desired strength and/or apparent density in order to fit particular downhole conditions for well treating such as hydraulic featuring treatments and sand control treatments.
"non-selectively configured porous particulate material" shall refer to any porous natural ceramic material, such as lightweight volcanic rocks, like pumice, as well as prelate and other porous "lavas" like porous (vesicular) Hawaiian Basalt, porous Verna Diabase, and Utah Hyalite. Further, inorganic ceramic materials, such as alumina, magnetic glass, titanium oxide, zirconium oxide, and silicon carbide may also be used. In addition, the term shall refer to a synthetic porous particulate material which has not been chemically treated and which imparts desired physical properties, such as particle characteristics, desired strength and/or apparent density in order to fit particular downhole conditions for well treating;
"relatively lightweight" shall refer to a porous particulate material that has a apparent density (API RP 60) that is substantially less than a conventional particulate material employed in hydraulic fracturing or sand control operations, such as sand having an apparent specific

gravity (API RP 60) of 2.65 and bauxite having an apparent specific gravity of 3.55. The apparent specific gra\ity of a relatively lightweight material is less than about 2.4.
"substantially neutrally buoyant" shall refer to a porous particulate material that has an apparent density sufficiently close to the apparent density of a selected ungelled or weakly gelled carrier fluid, such as an ungelled. or weakly gelled completion brine, other aqueous-based fluid, slick water, or other suitable fluid, which allows pumping and satisfactory placement of the proppant/particulate using the selected ungelled or weakly gelled carrier fluid.
a "weakly gelled carrier fluid" is a carrier fluid having a viscosifier or friction reducer to achieve friction reduction when pumped down hole, for example when pumped down tubing, work string, casing, coiled tubing, drill pipe, or siniilar location, wherein the polymer or viscosifier concentration from about 0 pounds of polymer per thousand gallons of base fluid to about 10 pounds of polymer per thousand gallons of base fluid, and/or the viscosity from about 1 to about 10 centipoises. An "ungelled carrier fluid" is a carrier fluid having no polymer or viscosifier. The ungelled carrier fluid may contain a friction reducer known in the art.
The selectively configured porous particulate materials as well as non-selectively configured porous particulate materials are particularly effective in hydraulic fracturing as well as sand control fluids such as water, salt brine, slickwater such as slick water fracture treatments at relatively low concentrations to achieve partial monolayer fractures, low concentration polymer gel fluids (linear or crosslinked), foams (with gas) fluid, liquid gas such as liquid carbon dioxide fracture treatments for deeper proppant penetration, treatments for water sensitive zones, and treatments for gas storage wells.
For instance, the selectively configured porous material particles or non-selectively configured porous material particles may be mixed and pumped during any desired portion/s of a well treatment such as hydraulic fracturing treatment or sand control treatment and may be mixed in any desired concentration with a carrier fluid. In this regard, any carrier fluid suitable for transporting the selectively configured porous particulate material or non-selectively configured porous particulate material particles into a well and/or subterranean formation fracture in communication therewith may be employed including, but not limited to, carrier fluids comprising salt water, fresh water, potassium chloride solution, a saturated sodium chloride solution, liquid hydrocarbons, and/or nifrogen or other gases may be employed. Suitable carrier fluids include or may be used in combination with fluids have gelling agents, cross-linking agents, gel breakers, surfactants, foaming agents, demulsifiers, buffers, clay stabilizers, acids, or mixtures thereof.

When used in hydraulic fracturing, the selectively configured porous particulate material or non-selectively configured porous particulate material particles may be injected into a subterranean formation in conjunction with a hydraulic fracturing treatment or other treatment at pressures sufficiently high enough to cause the fonmation or enlargement of fractures. Such other treatments may be near wellbore in nature (affecting near wellbore regions) and may be directed toward improving wellbore productivity and"or controlling the production of fracture proppant or formation sand. Particular examples include gravel packing and "frac-packs." Moreover, such particles may be employed alone as a fracture proppant/sand confrol particulate, or in mixtures in amounts and with types of fracture proppant/sand control materials, such as conventional fracture or sand control particulate. Further information on hydraulic fracturing methods and materials for use therein may be found in United States Patent No. 6,059,034 and in United States Patent No. 6,330,916, which are incorporated herein by reference.
When employed in well treatments, selected porous material particles that have been selectively configured, such as glazed and/or treated with one or more selected coating and/or penetrating materials, may be infroduced into a wellbore at any concentration/s deemed suitable or effective for the downhole conditions to be encountered. For example, a well freatment fluid may include a suspension of proppant or sand control particulate that is made up completely of relatively lightweight selected porous material particles that have been selectively configured, such as glazed and/or treated with one or more selected coating and/or penetrating materials. Alternatively, it is possible that a well treatment fluid may include a suspension that contains a mixhire of conventional fracture proppant or sand control particulates such as sand with relatively lightweight selected porous material particles that have been selectively configured such as glazed and/or freated with one or more selected coating and/or penetrating materials.
In one exemplary embodiment, a gravel pack operation may be carried out on a wellbore that penetrates a subterranean formation to prevent or substantially reduce the production of formation particles into the wellbore from the formation during production of formation fluids. The subterranean formation may be completed so as to be in communication with the interior of the wellbore by any suitable method known in flie art, for example by perforations in a cased ■wellbore, and/or by an open hole section. A screen assembly such as is known in the art may be placed or otherwise disposed within the wellbore so that at least a portion of the screen assembly is disposed adjacent the subterranean formation. A slurry including the selectively configured porous particulate material or non-selectively configured porous particulate material and a carrier fluid may then be infroduced into the wellbore and placed adjacent the subterranean formation by circulation or other suitable method so as to form a-fluid-permeable pack in an annular area

between the exterior of the screen and the interior of the wellbore that is capable of reducing or substantially preventing the passage of formation particles from the subterrane;in formation into the wellbore during production of fluids from the formation, while at the same time allowing passage of formation fluids from the subterranean formation through the screen into the wellbore. It is possible that the slurry may contain all or only a portion of selectively configured porous particulate material or the non-selectively configured porous particulate material. In the latter case, the balance of the particulate material of the slurry may be another material, such as a conventional gravel pack particulate.
As an alternative to use of a screen, the sand control method may use the selectively configured porous particulate material or non-selectively configured porous particulate material in accordance with any method in which a pack of particulate material is formed within a wellbore that it is permeable to fluids produced from a wellbore, such as oil, gas, or water, but that substantially prevents or reduces production of formation materials, such as formation sand, from the formation into the wellbore. Such methods may or may not employ a gravel pack screen, may be introduced into a wellbore at pressures below, at or above the fracturing pressure of the formation, such as frac pack, and/or may be employed in conjunction with resins such as sand consolidation resins if so desired.
The porous particulate material shall include any naturally occurring or manufactured or engineered porous ceramic particulate material that has an inherent and/or induced porosity. A commercially available instrument, ACCUPYC 1330 Automatic Gas Pycnometer (Micromeritics, Norcross, GA), that uses Helium as an inert gas and the manufacturer"s recommended procedure can be used to determine the internal porosity of the particulates. The internal porosity is generally from about 10 to 75 volume percent. Such particulate material may also have an inherent or induced permeability, i.e., individual pore spaces within the particle are interconnected so that fluids are capable of at least partially moving through the porous matrix, such as penefrating the porous matrix of the particle, or may have inherent or induced non-permeability, individual pore spaces within the particle are disconnected so that fluids are substantially not capable of moving through the porous matrix, such as not being capable of penetrating the porous matrix of the particle. The degree of desired porosity intercormection may be selected and engineered into the non-selectively configured porous particulate material. Furthermore such porous particles may be selected to have a size and shape in accordance with typical fracturing proppant particle specifications {i.e., having a uniform shape and size distribution), although such uniformity of shape and size is not necessary.

The apparent specific gravity of fte porous particulatB loaterial is generally less fbsn or equal to Z"A, prefiBrably less than or equal to 2.0, even more preferably less than ox equal to 1.75. most preferably lesa &an or oqual to 1.25.
la a seloctively configured porous particulate material, the particles may be selected based on. porosity and/or penoeability daracteristics so diat they have desired ligbtwei’t charactBiistics, such as when suspended in a selected canier fluid for a wsll treatment As before, the isherest and/or induced porosity of a porous material particle may be selected so as to help provide the desired balance between parent density and strength. Optional matstials may be enqiloyed along -wiSi a glazing, penetratiag axLd/or coating mataiial to control penetration, such as enhancing or impairing penetration. For example, in one embodiment an catLonic clay stabilizer, such as CLAY MASTER. 5C from BI Services, may be first applied to the extedor sor&ce of a porons ccianuc matexial to inhibit peaettation by coating/jpenetrsmig sxatenal, snch as epoxy ox resin described elsewhere herein.
In a preferred embodiment, tiie porous particulate matedal is a relatively li’tweight or subslantially neutral buoyant particulate material. Such materials may be employed in a manner that elhninates the need for gellation of earner fluid, thus eliminating a source of potentied proppant pacl: and/or fistmation damage. Fmthemiore, a relatively li’tweight particulate material may be easier to place within a targeted zone due to lessened settling constraints, and a reduced mass of such relatively ti’tweight particulate material is generally required to fill an equivalent volonoe dian is required with conventional sand control particulates, used, for example, for gravel packing purposes.
Bjelatxvely lightweight and/or substantially neutrally buoyant firactuze prappant/particnlate material used in hydraulic fracturmg/"saQd control treattoeat, such as porous cersmic particles having untreated bulk apparent density of 1.16 and untreated porosity of about 59.3%, may be employed.
In one embodiment, the disclosed porous material particulates may be employed as lelalively ligbtweig’ particulate/jiroppant material that may be introduced or pmnped into a well as neutrally buoyant particles in, for example, a satnrated sodium chloride solution carrier fhiid or a carrier fhrid that is any other completictn or workover brine known in die art, thus eliminating the need for "Vrp"gmg polymer or fluid loss material In one embodiment’ such a material may be employed ss proppant/saad control particulate material at temperatures up to about STl"C, and closure stresses up to about 55.2 MPa. However, these ranges of temperature and closure stress are exemplary only, it being understood that the disclosed materials znay be employed as proppam/sand control materials at temperatures greater than about 371°C aixd/or at

closure stresses greater than about 552 MPa. In any event, it will be imderstood wilfa benefit of this disclosnra that pototu pailicblste sateiial and/or coatiag’eiietntiiig toatenab tnay be selected by those of still in the art to meet and withstimd anfic’peUed downhole conditions of a given application.
In ‘se embodiments where the djjsclosed ponnis matoial paiticnktes are employed as telatiyely lightweight aad/or sabstaatially neutcally buoyant particulate/’ppant niatenals, they may be employed wilb earner fluids ttiat are gelled, noo-geOed, or that have a reduced or ligtaCer gelling reqvdremetlt as cosq>ared to cazrier fluids employed -with conveatjonal fiactme Ireaisient’sand control me&ods. In one embodimenl employing one or more of the disclosed substantially neutialty buoyant paiticolate nutsiials and a btine caixicr fluid, miicrng eqoiqnnest need only include such equqnnsnt Hat is capable of (a) mixing the biine (dissolving soluble salts), and (b) homogeneously dispecsing in the substantially neutrally buoyant paiticiilatB matsiiaL In one embodiment a substantially nsuQaUy buoyant paxticulata’noppant matetial may be advastageously pie-suspe&ded and stored in a storage fluid, such, as biine of near or substantially equal density, aad thisn pumped or placed dowohole as is, or diluted on the fly.
Examples of non-natoial porous paniculate matedals for use in the invention include, but are not limited to, porous ceramic particles such as &ose paiticlea available &om Caibo Ceiamics Inc. as "Econopxop", and those fired kaolinitic described in United States Patent No. 5,188,175 which is incorporated herein by referwcB. As described in this refeieace such particles may include solid spherical pellets or particles fiom raw materials (such as kaolin clay) having an alumioa content of between about 25% and 40% and a silica content of between about 50% and 65"A. A starch binder may be employed. Such particles may be cbaractoized as haviilg a ratio of silicon dioxide to alumina content of ficm about 1.39 to about 2.41,. and a apparent specific gravity of between about 2.20 and about 2.60 or between about 2.20-8nd about 2,70.
It win also be uadeistood that porous ceramic particles may be selectively moau&ctured torn. law materials sooh as those desoibed in United States Patent No. 5,188,175; United States Patent No. 4,427,068; and United States Patent No. 4,322,731, which are each incorporated hereiQ by refeieace, such as by inclusion, of selected process steps in the initial material manuftctucing process to result in a material diat possesses desired characteristics of porosity, penneabHity, apparent density or apparent specific gravity, combinations tiiereof For example, such taw materials may be-fired at relatively low temperature of about 668" C or about 7W C to achieve a desired crystaJIine structure and a more highly porous and lifter straoture. In one eseinplaiy embodiment of such particles, as described ebewhere herein, about

20/40 mesh size porous material fired kaolinitic particles from Carbo Ceramics Inc. may be selected for use in the disclosed method. These particles have the following internal characteristics: bulk apparent density about 1.16, internal porosity about 59.3%. These particles may be treated with a variety of penetrating/coating materials in an amount of from about 0.5 to about 10% by total weight of particle. Such coated particles may be manufactured and/or supplied, for example, by Fritz Industries of Mesquite, Te.xas.
In one exemplary case, size of such a material may be selected to range from about 200 mesh to about 8 mesh.
In such a case, the particles may be selected based on porosity and/or permeability characteristics so that they have desired lightweight characteristics, such as when suspended in a selected carrier fluid for a well treatment. As before, the inherent and/or induced porosity of a porous material particle may be selected so as to help provide the desired balance between apparent density and strength. Optional materials may be employed along with a glazing, penetrating and/or coating material to control penetration such as enhance or impair penetration. For example, in one embodiment an cationic clay stabilizer, such as CLAY MASTER 5C from BJ Services, may be first applied to the exterior surface of a porous ceramic material to inhibit penetration by coating/penetrating material, such as epoxy or resin described elsewhere herein. .
In a selectively configured porous particulate material, the porous particulate material is chemically treated in order to impart desired physical properties, such as porosity, permeability, appai-ent density or apparent specific gravity, or combinations thereof to the particulate materials. Such desired physical properties are distinct from the physical properties of the porous particulate material"s prior to treatment.
The desired physical properties may further be present in non-selectively configured porous particulate materials. Non-selectively configured porous particulate materials shall include naturany occurring porous ceramic materials as well as non-natural (synthetic) materials manufactured in a manner that raiders such desired characteristics.
The non-selectively configured particulate material is selected based on desired physical properties, such as porosity, permeability, apparent density, particle size, chemical resistance or combinations thereof.
The selectively configured porous particulate material as well as non-selectively configured porous particulate material exhibit crush resistance under conditions as high as 10,000 psi closure stress, API RP 56 or API RP 60, generally between from about 250 to about 8,000 psi closure stress, in combination with a apparent specific gravity less than or equal to 2.4,

to meet the pumping and/or downhole formation conditions of a panicular application, such as hydraulic fracturing treatment, sand control treatment
Such desired physical properties may be impaned to a portion or portions of the porous particulate material of the selectively configured porous particulate material or non-selectively configured porous particulate material, such as on the particle surface of the material particulate, at or in the particle surface of the particulate material, in an area near the particle surface of a particulate material, in the interior particle matrix of a particulate material or a portion thereof, combinations thereof, etc.
Advantageously, in one embodiment the low apparent specific gravity- of the porous particulate material of the selectively configured porous particulate material or non-selectively configured porous paniculate material maybe taken advantage of to result in a larger fi-acture or fi-ac pack width for the same loading, such as pound per square foot of proppant. to give much larger total volume and increased width for the same mass. Alternatively, tliis characteristic allows for smaller loading of proppant material to be pumped while still achieving an equivalent width.
hi a preferred embodiment, selective configuration, such as by using glaze-forming, coating and/or penetrating materials, such as those materials described elsewhere herein, may be selectively employed to modify or customize the apparent specific gravity of a selected porous particulate material. Modification of particulate apparent specific gravity, to have a greater or lesser apparent specific gravity, may be advantageously employed, for exainple, to provide proppant or sand control particulates of customized apparent specific gravity for use as a substantially neutrally buoyant particulate with a variety of different weight or apparent specific gravity carrier fluids.
The selectively configured porous particulate material has an apparent density fi-om about 1.1 g/cm’to about 2.6 g/cm", a bulk apparent density firom about 1.03 g/cm’ to about 1.5 g/cm\ and an internal porosity firora about 10 to about 75 volume percent. In one example, bulk densities may be controlled to be in the range of from about 1.1 g/cm" to about 1.5 g/cm"*, although greater and lesser values are also possible.
The selectively configured porous particulate material, as well as the non-selectively configured particulate material, is generally between from about 200 mesh to about 8 mesh.
The selectively configured porous particulate material may comprise porous particulate material selectively altered by treating with a coating or penetrating material using any suitable wet or dry process. Methods for coating particulates, such as fracpjre proppant particles, with materials such as resin are known in the art, and such materiaLs are available, for example, from

manufacturers listed herein. With regard to coating of the disclosed porous particulate materials, coating operations may be performed using any suitable methods known in the art.
As used herein, the term "penetration" shall further refer to partially or completely impregnated with a penetrating material, by for example, vacuum and/or pressure impregnation. For example, porous particulate material may be immersed in a second material and then exposed to pressure and/or vacuum to at least partially penetrate or impregnate the material.
Those of skill in the art will understand that one or more coating and/or penetrating materials may be selected to treat a porous material particulate to meet particular criteria or requirements of given downhole application based on the information and examples disclosed herein, as well as knowledge in the art. In this regard, porous material panicle characteristics, such as composition, porosity and permeability characteristics of the particulate material, size, and/or coating or penetradng material characteristics, such as composition, amount, thickness or degree of penetration, may be so selected. The coating or penetrating material is typically non-porous.
The porosity and permeability characteristics of the porous particulate material allows the penetrating material to be drawn at least partially into the porous matrix of the porous particulate material by capillary action, for example, in a manner similar to a sponge soaking up water. Alternatively, one or more penetrating materials may be drawn at least partially into tlie porous matrix of the porous particulate material using a vacuum, and/or may be forced at least partially into the porous matrix under pressure.
Examples of penetrating materials that may be selected for use include, but are not limited to, liquid resins, plastics, cements, sealants, binders or any other material suitable for at least partially penetrating the porous matrix of the selected particle to provide desired characteristics of strength/crush resistance, apparent specific gravity, etc. It will be understood that selected combinations of any two or more such penetrating materials may also be employed, either in mixture or in sequential penetrating applications.
Examples of resins that may be employed as penetrating and/or coating materials include, but are not limited to, resins and/or plastics or any other suitable cement, sealant or binder that once placed at least partially within a selected particle may be crosshnked and/or cured to form a rigid or substantially rigid material within the porous structure of the particle. Specific examples of plastics include, but are not limited to, nylon, polyethylene, styrene, etc. and combinations thereof. Suitable resins include phenol formaldehyde resins, melamine formaldehyde resins, and urethane resins, low volatile urethane resins, such as these and other types of resins available from Borden Chemical Inc., Santrol, Hepworth of England, epoxy resins and mixtures thereof.

Specific examples of suitable resins include, but are not limited to, resins ft-om Borden Chemical and identified as 500-series and 700-series resins (e.g., 569C, 794C, ere). Further specific examples of resins include, but are not limited to, SIGMASET series low temperature curing urethane resins fi-om Borden Chemical, such as SIGMASET, SIGMASET LV, SIGMASET XL, ALPHASET phenolic resin fi"om Borden Chemical, OPTI-PROP phenolic resin fi-om Santrol, and POLAR PROP low temperature curing resin fi"om Santrol. W"Tiere desired, curing characteristics, such as curing time, may be adjusted to fit particular treatment methods and/or final product specifications by, for example, adjusting relative amounts of resin components. Still fijrther examples of suitable resins and coating methods include, but are not limited to, those found in European Patent Application EP 0 771 935 Al; and in U.S. Patents No. 4,869,960; 4,664,819; 4,518.039: 3,929,191; 3,659,651; and 5,422,183, each of the foregoing references being incorporated herein by reference in its entirety.
In one exemplary embodiment, a curable phenolic resin or other suitable curable material may be selected and applied as a coating material so that individual coated particles may be bonded together under downhole temperature, after the resin flows and crosslinks/cures downhole, such as to facilitate proppant pack/sand control particulate consolidation after placement.
Alternatively, a cured phenolic type resin coat or other suitable cured material may be selected to contribute additional strength to the particles and/or reduce in situ fines migration once placed in a subterranean formation. The degree of penetration of the coating or penetrating fluid into the porous particulate material may be limited by disconnected porosity, such as substantially impermeable or isolated porosity, within the interior matrix of the particulate.
This may either limit the extent of uniform penetration of penetrating material in a uniform manner toward the core, such as leaving a stratified particle cross section having outside penetrating layer with unpenetrated substantially spherical core, and/or may cause uneven penetration all the way to the core, such as bypassing "islands" of disconnected ])orosity but penetrating all the way to the core. In any event, a penetrating and/or coatijig material may trap or encapsulate air (or other fluid having apparent specific gravity less than particle matrix and less than coating/penetrating material) within the disconnected porosity in order to reduce apparent specific gravity by the desired amoimt. Such materials coat and/or penetrate the porous particulate without invading the porosity to effectively encapsulate the air within the porosity of the particle. Encapsulation of tiie air provides preservation of the ultra-lightvveight character of the particles once placed in the b-ansport fluid. If the resin coating or transport fluids were to significantly peneh-ate the porosity of the particle, the density increases accordingly, and the

particle no longer has the same lightweight properties. The resin coat also adds strength and substantially enhances the proppant pack permeability at elevated stress.
Coating la\ers may be applied as desired to contribute to particle strength and/or reduce in situ fmes migration once placed in a subterranean formation. The coating significantly increases the strength and crush resistance of the ultra-lightweiglit ceramic particle, hi the case of natural sands the resin coat protects the particle from crushing, helps resist embedment, and prevents the liberarion of fines.
The coating or penetrating fluid is typically selected to have an apparent specific gravity less than the apparent specific gravity of the porous particulate material so that once penetrated at least partially into the pores of the matrix it results in a particle having a apparent specific gravity less than that of the porous particulate material prior to coating or penetration, i.e., filling the pore spaces of a porous particulate material results in a solid or substantially solid particle having a much reduced apparent density.
For example, the selected porous particulate material may be treated with a selected penetrating material in such a way that the resultant selectively configured porous particulate material has a much reduced apparent density, such as having a apparent density closer to or approaching the apparent specific gravity of a carrier fluid so that it is neutrally buoyant or semi-buoyant in a fi’cturing fluid or sand control fluid.
Alternatively, a penetrating material may be selected so that it helps structurally support the matrix of the porous particulate material (i.e., increases the strength of the porous matrix) and increases the ability of the particulate to withstand the closure stresses of a hydrauhc firactured formation, or other downhole stresses.
For example, a penetrating material may be selected by balancing the need for low apparent density versus the desire for strength, i.e., a more dense material may provide much greater strength, hi this regard, the inherent and/or induced porosity of the porous particulate material may be selected so as to help provide the desired balance between apparent density and strength. It wiU be understood that other variable, such as downhole temperature and/or fluid conditions, may also impact the choice of penetrating materials.
The coating layer or penetrating material is generally present in the selectively configured porous particulate material in an amount of firora about 0.5% to about 10% by weight of total weight. The thickness of the coating layer of the selectively configured porous particulate material is generally between fi-om about 1 to about 5 microns. The extent of penetration of the penetrating material of the selectively configured porous particulate material is firom less than about 1% penetration by volume to less than about 25% penetrationby volume.

Especially preferred results are obtained when the porous particulate material is a porous ceramic particle having an apparent density of 1.25 or less and untreated porosity is approximately 60%. Such materials may be treated with a coating material that does not penetrate the porous matrix of the porous pailiculate material, or that only partially penetrates the porous matrix of the ceramic particulate material. Such treated ceramic materials may have an apparent density from about 1.1 g/cm"" to about 1.8 g"cm’ (alternatively from about 1.75 g/cm"" to about 2 g/cm’ and further altematively about 1.9 g/cm’;). a bulk apparent densit> from about 1.03 g/cm’ to about 1.5 g/cm\ and a treated internal porosity from about 45"? o to about 55%. However, values outside these exemplary ranges are also possible.
.\s an example, a porous ceramic treated with about 6% epoxy has been ."‘een to exhibit a bulk apparent density of about 1.29 and a porosity of about 50.6%, a porous ceramic treated with about 8% epoxy exhibits a bulk apparent density of about 1.34 and a porosity of about 46.9%, a porous ceramic treated with about 6% phenol formaldehyde resin exhibits a bulk apparent density of about 1.32 and a porosity of about 51.8%, and a porous ceramic treated with about 8% phenol formaldehyde resin exhibits a bulk apparent density of about 1.20 and a porosity of about 54.1%.
In this embodiment, a coating material or penetrating material may be selected to be present in an amount of from about 0.5% to about 10% by weight of total weight of individual particles. When present, thickness of a coating material may be selected to be from about 1 to about 5 microns on the exterior of a particle. Wlien present, extent of penefration penefrating material into a porous material particle may be selected to be from less than about 1% penetration by volume to less than about 25% penetration by volume of the particle. It will be understood that coating amounts, coating thickness, and penetration amounts may be outside these exemplary ranges as well.
Further, the porous particulate material may be at least partially selectively configured by glazing, such as, for example, surface glazing with one or more selected non-porous glaze materials. In such a case, the glaze, like the coating or penetrating material, may extend or penetrate at least partially into the porous matrix of the porous particulate material, depending on the glazing method employed and/or the permeability (i.e., connectivity of internal porosity) characteristics of the selected porous particulate material, such as non-connected porosity allowing substantially no penetration to occur. For example, a selected porous particulate material may be selectively configured, such as glazed and/or coated with a non-porous material, in a manner so that the porous matrix of the resulting particle is at least partially or completely filled with air or some other gas, i:e.." the interior of the resulting particle includes only air/gas

and the structural material forming and surrounding the pores. Once again, the inherent and/or induced porosity of a porous material particle may be selected so as to help provide the desired balance between apparent density and strength, and glazing and/or coating with no penetration (or extension of configured area into the particle matrix) may be selected to result in a particle having all or substantially all porosity of the particle being unpenetrated and encapsulated to trap air or other relatively lightweight fluid so as to achieve minimum apparent specific gravity. In addition to sealing a particle, such as to seal air/gas within the porous matrix of the particle, such selective configuration, such as using glazing and"or coating materials, may be selected to provide other advantages.
In a preferred embodiment, the porous particulate material, such as the above-described fired kaolinitic particles, is irianufactured by using a glaze-forming material to form a glaze to seal or otiierwise alter the permeability of the particle surface, so that a gi\en particle is less susceptible to invasion or saturation by a well treatment fluid and thus capable of retaining relatively lightweight or substantially neutrally buoyant characteristics relative to the well treatment fluid upon exposure to such fluid. Such glazing may be accomplished using any suitable method for forming a glaze on the surface or in the near surface of a particle, including by incorporating a glaze-forming material into the raw material "green paste" that is then formed such as molded into shape of the particle prior to firing. Those skilled in the art recognize that glazes may be made firora a variety of methods, including the application of a smooth, glassy coating such that a hard, nonporous surface is formed. Glazes may be formed firom powdered glass with oxides. The mixture of powders is suspended in water and applied to the substrate. The glaze can be dried and then fixed onto the substrate by firing or similar process known to those skilled in the art. Additionally, the use of borates or similar additives may improve the glaze.
Examples of such glaze-forming materials include, but are not limited to, materials such as magnesium oxide-based material, boric acid/boric oxide-based material, etc. During firing, the glaze-forming material/s "bloom" to the surface of the particles and form a glaze. Alternatively, glazing may be accomplished, for example, by applying a suitable glaze-forming material onto the surface of the formed raw material or "green" particles prior to firing such as by spraying, dipping, and similar methods so that glazing occurs during partitle firing. Further alternatively, a glaze-forming material may be applied to a fired ceramic particle, and then fired again in a separate glaze-forming step. In one embodiment, the glaze forms a relatively hard and relatively non-porous surface during firing of the particles.

Advantages cf such a glazing treatment include maintaming the relati\ ely low apparent density of a relatively lightweight porous particle without the necessity of further alteration, such as necessity of coating with a separate polymer coating although optional coatings may be applied if so desired. Furthermore, the resulting relatively smooth glazed surface of such a particle also may ser\e to enhance the ease of multi phase fluid flow, such as flow of water and gas and oil, through a particulate pack, such as thrcugli a proppant pack in a fracmre, resulting in increased fracture conductivity.
In an alternative embodiment, one or more types of the disclosed selectively configured porous particulate material or non-selectively configured porous particulate material may be employed as particulates for well treating purposes in combination with a variety of different types of well treating fluids (including liquid CO’-based systems and other liquefied-gas or foamed-gas carrier fluids) and/or other types of particulates such as to achieve synergistic benefits, it being understood that benefits of the disclosed methods and compositions may also be achieved when employing only one type of the disclosed porous materials as a sole well treating particulate. Furthermore, although exemplary embodiments are described herein with reference to porous materials and to relatively lightweight porous materials, it will be understood that benefits of the disclosed methods and compositions may also be realized when applied to materials that may be characterized as non-relatively lightweight and/or non-porous in nature.
Elimination of the need to formulate a complex suspension gel may mean a reduction in tubing fiiction pressures, particularly in coiled tubing and in the amount of on-location mixing equipment and/or mixing time requirements, as well as reduced costs. Furthermore, when selectively configured, such as by glazing and/or by treating with coating/penetrating material, to have sufficient strength and relative lightweight properties, the disclosed relatively particles may be employed to simplify hydraulic fi-acturing treatments or sand control treatments performed through coil tubing, by greatly reducing fluid suspension property requirements. Downhole, a much reduced propensity to settle (as compared to conventional proppant or sand control particulates) may be achieved, particularly in highly deviated or horizontal wellbore sections. In this regard, the disclosed particulate material may be advantageously employed in any deviated well having an angle of deviation of between about 0 degree and about 90 degrees with respect to the vertical. However, in one embodiment, the disclosed particulate material may be advantageously employed in horizontal wells, or in deviated wells having an angle with respect to the vertical of between about 30 degrees and about 90 degrees, alternatively between about 75 degrees and about 90 degrees. Thus, use of the disclosed particulate materials disclosed herein may be employed to achieve surprising and unexpected improvements in fracturing and sand

control methodology, including reduction in proppant pack and/or formation damage, and enhancement of well productivity.
It will be understood that the characteristics of glazing materials, penetrating materials and/or coating materials given herein, such as composition, amounts, types, are exemplary only. In this regard, such characteristics may be selected with benefit of this disclosure by those of skill in the art to meet and withstand anticipated downhole conditions of a given application using methods known in the art, such as those described herein.
In another disclosed embodiment, blends of two or more different types of particles having different particulate characteristics, such as different porosity, permeability, apparent density or apparent specific gravity, settling velocity in carrier fluid, may be employed as well treatment particulates. Such blends may contain at least one porous particulate material and at least one other particulate material that may or may not be a porous particulate material.
In addition, the selectively configured porous particulate material and non-selectively configured porous particulate material may be used as two or more multiple layers. In this regard, successive layers of such materials may be employed. For instance, multiple layers may consist of at least one selectively configured porous particulate material and at least one non-selectively configured porous particulate material.
In one exemplary embodiment, a selected coating or penetrating material may be a urethane, such as ethyl carbamate-based resin, applied in an amount of about 4% by weight of the total weight of the selected porous material particle. A selected coating material may be applied to achieve a coating layer of at least about 2 microns thick on the exterior of the selected porous material particle.
Such blends may be fiirther employed in any type of well treatment application, including in any of the well treatment methods described elsewhere herein. In one exemplary embodiment, such blends may be employed to optimize hydraulic fracture geometries to achieve aihanced well productivity, such as to achieve increased propped fi-acture length in relatively "tight" gas formations. Choice of different particulate materials and amounts thereof to employ in such blends may be made based on one or more well treatment considerations including, but not limited to, objective/s of well treatmait, such as for sand control and/or for creation of propped firactures, well treatment fluid characteristics, such as apparent specific gravity and/or rheology of carrier fluid, well and formation conditions such as depth of formation, formation porosity/permeability, formation closure stress, type of optimization desired for geometry of downhole-placed particulates such as optimized fracture pack propped length, optimized sand

control pack heighi, optimized fracture pack and/or sand control pacK conduinivity and combinations thereof.
Such different types of particles may be selected, for example, to achieve a blend of different specific gra\ities or densities relative to tlie selected carrier fluid. For example, a blend of three different parricles may be selected for use in a water fracture treatment to form a blend of well treatment particulates having three different specific gravities, such as .-pparent specific gravity of first type of particle from about 1 to less about 1.5; apparent specific gravity of second type of particle from greater than about 1.5 to about 2,0; and apparent specific gravity of third tjpe of particle from about greater than about 2.0 to about 3.0; or in one specific embodiment the three types of particles having respective specific gravities of about 2.65, about 1.7 and about 1.2, it being understood that the preceding apparent specific gravity values are exemplary only and that other specific gravities and ranges of specific gravities may be employed. In one example, at least one of the types of selected well treatment particulates may be selected to be substantially neutrally buoyant in the selected carrier fluid.
Such different types of particles may be selected for use in any amount suitable for achieving desired well treatment results and/or costs. However, in one embodiment multiple types of particles may be selected for use in a blend of well treatment particulates in amounts that are about equal in proportion on the basis of total weight of the blend. Thus, three different types of particles may each be employed in respective amounts of about 1/3 of the total blend such as by total weight of the blend, four different types of particles may each be employed in respective amounts of about "A of the total blend such as by total weight or the blend However, these relative amounts are exemplary only, it being understood that any desired relative amount of each selected type of well particulate may be employed, such as for one exemplary embodiment of blend having three different types of particles, such as selected from the different types of particles described elsewhere herein, the amounts of each selected type of particle may be present in the blend in an amount ranging from about 10% to about 40% such as by total weight of the blend to achieve 100% weight of the total blend.
It will be understood with benefit of this disclosure that choice of different particulate materials and amounts thereof to employ in such blends may be made using any methodology suitable for evaluating such blends in view of one or more desired well treatment considerations. In one embodiment, any method known in the art suitable for modeling or predicting sand control pack or fracture pack geometry/conductivity may be employed, such as illustrated and described in relation to Example 4 herein.

Examples of different particle types which may be selected for xise in such blends include, but are not limited to, conventional sand particulates, such as Ottawa sand, relatively lightweight well treatment particulates, such as ground or crushed nut shells at least partially surrounded by at least one layer component of protective or hardening coating, selectively configured porous materials, such as any one or more of the selectively configured porous materials described herein, such as deformable particles. Further examples of pjurticle types which may be selected for use in such blends include any of those particles described in U.S. Patent Application Serial No. 10/113,844, filed April 1, 2002; U.S. Patent Application Serial No. 09/579,146, filed May 25, 2000; U.S. Patent No. 6,364,018; U.S. Patent No. 6.330,916; and U.S. Patent No. 6,059,034, each of which is incorporated herein by reference.
In one exemplary embodiment, selected blends of conventional sand proppant, relatively lightweight particulates of ground or crushed nut shells at least partially surrounded by at least one layer component of protective or hardening coating, and selectively configured porous materials such as relatively lightweight porous material fired kaolinitic particles treated with a penetrating/coating materials described herein may be employed in a hydraulic firacture treatment utilizing ungelled or weakly gelled carrier fluid. One specific example of such a blend is described in Example 4 herein. In such an embodiment, these different types of particles may be employed in any relative volume or weight amount or ratio suitable for achieving desired well treatment results.
In one specific example, these different types of particles may be employed in a well treatment particulate composition including about 1/3 by weight of conventional sand proppant by total weight of well treatment particulate, about 1/3 by weight of relatively lightweight particulate, such as core of ground or crushed nut shells at least partially surrounded by at least one layer component of protective or hardening coating) by total weight of well treatment particulate, and about 1/3 by weight of selectively configured relatively lightweight porous material, such as fired kaolinitic particles treated with a penetrating/coating materials described herein, by total weight of well tireatment particulate. It will be understood that the foregoing relative amo\ints are exemplary only and may be varied, for example, to achieve desired results and/or to meet cost objectives of a given treatinent. It will also be understood that the disclosed methods and compositions may also be practiced with such blends using other types of relatively lightweight particulate materials as described elsewhere herein, such as porous polymeric materials, such as polyolefins, styrene-divinylbenzene based materials, pqlyalkylacrylate esters and modified starches. Further, any of the disclosed porous materials may be employed in "neat" or non-altered form in the disclosed blends where apparent density jind other

characteristics of the particle are suitable to mcsi requirements of the gi\en well treating application.
In one respect, disclosed are well treating methods, such as hydraulic fiacturing and sand control, which may be employed to treat a well penetrating a subterranean formation, and include introducing into a well a selected porous particulate material that is treated with a selected coating material, selected penetrating material, or combination thereof Indi\idual particles of the particulate material optionally may have a shape with a maximum length-based aspect ratio of equal to or less than about 5. In one embodiment porous particulate materials may be any particulate material with suitable internal porosity and/or permeability characteristics to achieve the desired finished particle properties when combined with selected penetrating/coating materials as described elsewhere herein.
Examples of suitable porous material particulates that may be selected for use in aqueous based carrier fluids include, but are not limited to porous ceramics, porous pohmeric materials or any other porous material or combinations thereof suitable for selection for combination of internal porosity and permeability to achieve desired properties, such as strength and/or apparent specific gravity, for particular downhole conditions and/or well treatment applications as described elsewhere herein. For example, porous ceramic particles may be manufactured by firing at relatively low temperatures to avoid loss of porosity due to crystallization and driving off of water. Particular examples include, but are not limited to, porous ceramic particles available from Carbo Ceramics Inc. of Lrving, Texas composed of fired kaolinitic clay that is fired at relatively low temperature of about 1235"? or about ISOO’F (or about 700°C and that has trace amounts of components such as cristobalite, mullite and opalite), polyolefin particles, and similar components.
In another disclosed embodiment, relatively lightweight particulates or blends including such particulates as described elsewhere herein, such as including selectively (Xinfigured particulates and/or non-selectively configured particulates described elsewhere herein, may be advantageously employed as well treatment particulates, such as fi-acture proppant particulate or sand control particulate, in liquefied gas and foamed gas carrier fluids.
Examples of types of such carrier fluids include, but are not limited to, liquid C02-based systems, liquid CO2, CO2/N2, and foamed N2 in CO2 systems that may be employed in hydraulic fi-acturing applications. In one specific embodiment, porous ceramic well particulates having a bulk apparent density of close to or about 1.0 g/cm’ in either selectively configured or non-selectively configured form, may be employed with such liquefied gas and/or foamed gas carrier fluids, such as liquid COj-based systems, liquid C02,-C02/N2, and foamed Ni in CO2 systems.

In another specific embodiment, selectively configured particulates and/or non-selectively configured particulates may be employed that may be characterized as substantially neutrally buoyant in such liquefied gas and/or foamed gas carrier fluids.
Liquid CO2 has a density close to about 1.02 g/cra’ under typical fiacturing conditions, and conventional proppants, such as sand, or non-relatively lightweight ceramic proppants have a tendency to settle in liquid C02-based systems. Furthermore, liquid CO2 has \ery little if any viscosity, and therefore proppant transport in a liquid COj-based system is provided by turbulence and fiictional forces, and fractures created by liquid CC)2 are typically relatively narrow. Advantageously, using the disclosed methods and compositions, proppant transport of relatively lightweight particulates is easier than is proppant transport of conventional sand proppants or non-relatively lightweight ceramic proppants.
In one exemplary embodiment, relatively lightweight porous ceramic particles may be employed in liquid CC’-based systems. Examples of types of such relatively lightweight porous ceramic particles include, but are not limited to, those porous ceramic particles available from Carbo Ceramics for controlled release applications altered in the manufacturing process to have a bulk apparent density close to about 1.0 g/cm". Other suitable examples of relatively lightweight porous particles include, but are not limited to, those particles having a bulk apparent density of less than about 2.5 g/cm"", alternatively having a bulk apparent density of from about 1.0 to about 2.0 g/cm\ fijrther alternatively having a bulk apparent density of from about 1.2 g/cin" to about 2.0 g/cml
One specific example of suitable relatively lightweight porous ceramic particle for use in C02-based systems of this embodiment is porous ceramic material described elsewhere herein, either in selectively configured form, as described herein in Example 1, or in non-selectively configured or non-altered or "neat" form.
In one exemplary embodiment, the practice of the disclosed methods and compositions, relatively lightweight porous ceramic materials or blends thereof may be employed as fracture proppant materials in liquid COa-based fracturing systems using methodologies similar or the same to those employed with conventional proppants in liquid COa-based firacturing systems. In this regard, liquid COa-based firacturing job characteristics, such as proppant amounts, proppant sizes, mixing and pumping methodologies, using relatively lightweight porous ceramic materials may be the same as described for conventional proppants in "The History and Success of Liquid CO2 and CO2/N2 Fracturing System" by Gupta and Bobier, SPE 40016, March 1998. Further information on liquid COa-based firacturing job characteristics that may be employed with " relatively lightweight porous ceramic materials may be found in United States Patent No.

4,374,545, United States Patent No. 5,558,160, United States Patent No. 5,SS}.053, Canadian Patent No. 2,257,028 and Canadian Patent No. 2,255,413, each of the foregoing references being incorporated herein b>- reference.
In one disclosed exemplary embodiment, relatively lightweight porous ceramic particles employed as fracture proppant particulate in a liquid CO:-based system may be lused in "neat" or non-altered form and may have a apparent specific gravity of from about 1.17 to about 2.0 In another disclosed exemplary embodiment, using relatively lightweight porous ceramic particles as fracture proppant particulate in a liquid CIO-based system allows the concentration of proppant in such a system to be advantageously extended to about 1200 Kg cubic meter. Other advantages of using the disclosed relatively lightweight porous ceramic panicle.’ in liquid CO2-based fracturing systems include, but are not limited to, reduced proppant settling in surface mixing equipment prior to pumping downhole and improved proppant transport downhole and into the formation. It will be understood that although described abo\e for embodiments employing relatively lightweight porous ceramic particles, the disclosed methods and compositions may also be practiced with liquid CO’-based .systems using other relatively lightweight porous material particulate materials and blends thereof described elsewhere herein, such as porous polymeric materials such as polyolefin’s. Any of such materials may be employed in "neat" or non-altered fond with liquid COo-based systems where apparent density and other characteristics of the particle are suitable to meet requirements of the gi\en well treating application, or may alternatively be employed in selectively configured form as described elsewhere herein.
The following examples will illustrate the practice of the present invention in a preferred embodiment. Other embodiments within the scope of the claims herein will he apparent to one skilled in the art from consideration of the specification and practice of the invention as disclosed herein. It is intended that the specification, together with the example, be considered exemplary only, with the scope and spirit of the invention being indicated by the claims which follow. EXAMPLES
The following examples are illustrative and should not be construed as limiting the scope of the invention or claims thereof. Example 1:
To obtain the data for this example, the following procedure was followed: Measured mass of 25 ml of sample on a graduate cylinder. Cylinder was tapped several times on the

WE CLAIM :
1. A particulate material which is (a) a ceramic, polyolefin, styrene-divinylbenzene
copolymer or polyalkylacrylate ester (b) porous; and (c) treated with a coating material,
penetrating material or glaze, wherein one of the following conditions prevail:
(i) air or a relatively lightweight fluid is encapsulated or entrapped within the pores of the particulate material and wherein the ceramic, polyolefin, styrene-divinylbenzene copolymer or polyalkylacrylate ester exhibits inherent or induced permeability;
(ii) the apparent specific gravity of the treated porous particulate material is less than the apparent specific gravity of the untreated porous particulate material and wherein the ceramic, polyolefin, styrene-divinylbenzene copolymer or polyalkylacrylate ester exhibits inherent or induced permeability;
(iii) the strength of the treated porous particulate material is greater than the strength of the untreated porous particulate material when the porous ceramic, polyolefin, styrene-divinylbenzene copolymer or polyalkylacrylate ester and wherein the ceramic, polyolefin, styrene-divinylbenzene copolymer or polyalkylacrylate ester exhibits inherent or induced permeability;
(iv.) the porous particulate material is treated or modified with a glazing material.
2. The material as claimed in claim 1, which is of size 200 mesh to 8 mesh.
3. The material as claimed in claim 1 or 2 wherein the apparent specific gravity of the porous particulate is not more than 2.
4. The material as claimed in claim 3, which the apparent specific gravity of the porous particulate is not more than 1.75.

5. The material as claimed in claim 4, wherein the apparent specific gravity of the porous particulate is not more than 1.25.
6. The material as claimed in any preceding claim, wherein the treated porous particulate material has an apparent density of 1.1-2.6 g/cm^.
7. The material of any preceding claim, wherein the treated porous particulate material has a bulk apparent density of 1.03-1.4 g/cm"".
8. The material of any of the preceding claims, wherein individual particles of the porous particulate material have a maximum length-based aspect ratio of equal to or less than about 5.
9. The material of any preceding claim, wherein the particles of the porous ceramic material have a cationic clay stabilizer applied to their exterior surfaces for inhibiting penetration by coating/penetrating material.
10. The material as claimed in any preceding claim, coated with material of thickness 1-5|jjn.
11. The material as claimed in any preceding claim, wherein the penetrating or coating material is a liquid resin, plastic, cement, sealant or binder.
12. The material as claimed in claim 11, wherein the particulate material is coated or penetrated with a curable resin.
13. The material as claimed in any of claims 1 to 11, wherein the coating or penetrating material is a phenol, phenol formaldehyde, melamine formaldehyde, urethane, epoxy resin, nylon, polyethylene or polystyrene or a combination thereof

14. The material as claimed in claim 13, treated with an epoxy resin or phenol formaldehyde resin.
15. The material as claimed in any of claims 1 to 10, wherein the particles comprise an epoxy inner coating/penetrating material and a phenol formaldehyde outer coating material.
16. The material as claimed in any preceding claim, wherein particles of the treated particulate material comprise a multitude of the porous particles bonded together.
17. The material as claimed in claim 16, wherein the particulate material is coated or penetrated with a curable resin.
18. The material as claimed in any preceding claim, wherein the permeability of the treated porous particulate material is less than the permeability of the untreated porous particulate material.
19. A method of making the material of any preceding claim which comprises:
providing porous permeable particulate material which is a ceramic, polyolefin, styrene-divinylbenzene copolymer or polyalkylacrylate ester; and
treating said porous permeable particulate material with a penetrating material which is a liquid resin, plastics, cement, sealant or binder suitable for at least partially penetrating the porous material, the porosity of the porous material being such that the penetrating material can be drawn or forced at least partially into the porous matrix of the porous particulate material by capillary action, vacuum or pressure.
20. A composition for treating a well comprising:
a carrier fluid and

at least one material as claimed in any of claims 1 to 18 or porous particulate material of a natural ceramic.
21. The composition as claimed in claim 20, wherein the porous particulate material is a natural ceramic of a lightweight volcanic rock.
22. The composition as claimed in claim 21, wherein the natural ceramic is pumice, prelate, Hawaiian basalt, Virginia diabase or Utah hyalites.
23. The composition as claimed in any of claims 20 to 22, wherein the carrier fluid is salt water, fresh water, a liquid hydrocarbon, or a gas or a mixture thereof
24. The composition as claimed in any of claims 20 to 23, wherein the particulate material is relatively lightweight and/or substantially neutrally buoyant.
25. The composition as claimed in any of claims 20 to 24, wherein the carrier fluid is a completion or workover brine.
26. The composition as claimed in any of claims 20 to 25, wherein the carrier fluid is a liquefied gas or foamed gas carrier fluid or a mixture thereof, such as liquid carbon dioxide or liquid carbon dioxide/nitrogen.
27. The composition as claimed in any of claims 20 to 24, wherein the composition is a suspension which, when introduced into the well, forms a fluid-permeable gravel pack in an annular area defined between the exterior of a screen assembly and the interior of the wellbore.
28. The composition as claimed in any of claims 20 to 27, which further comprises one or more of a friction reducer, gelling agent, crosslinking agent, gel breaker, surfactant, foaming agent, demulsifier, buffer, clay stabilizer, acid or mixture thereof

29. The composition as claimed in any of claims 20 to 28, wherein the carrier fluid is non-gelled.
30. A method for treating a well penetrating a subterranean formation, comprising introducing into the well any of the following materials:

(a) a material according to any of claims 1 -18 or a composition of any of claims 20 to 29; or
(b) a porous organic polymeric material treated with a penetrating, coating or glazing material, wherein air or a fluid is encapsulated by or trapped within the porosity of the treated porous organic polymeric material; or
(c) a proppant of a porous material which is an organic polymeric material treated with a coating or penetrating material, wherein the coating or penetrating material penetrates the organic polymeric material, without invading the porosity of the organic polymeric material, to effectively encapsulate air within the porosity of the organic polymeric material; or
(d) a proppant of a porous organic polymeric material treated with a coating, penetrating or glazing material, wherein the proppant is introduced into the well at concentrations sufficient to achieve a partial monolayer fracture.

31. The method as claimed in claim 30, wherein the material exhibits crush resistance milder conditions from 2,500 psi to 10,000 psi closure stress.
32. The method as claimed in claim 30 to 31, wherein the organic polymeric material is a polyolefin.
33. The method as claimed in any of claims 30 to 32, wherein the material is introduced into the well as a slickwater fracturing fluid.

34. The method as claimed in any of claims 30 to 33, wherein the well is a vertical well.
35. The method as claimed in any of claims 30 to 33, wherein the well is a deviated well.
36. The method as claimed in any of claims 30 to 33, wherein the well is a horizontal well.
37. The method as claimed in any claims 30 to 33, wherein the treatment is for hydraulic fracturing.
38. The method as claimed in any of claims 30 to 33, wherein the method is for sand control.
39. Use as a proppant in a wellbore of the material as defined in any of claims 1 to 18.

Documents:

0519--chenp-2005 claims-duplicate.pdf

0519-chenp-2005 abstract-duplicate.pdf

0519-chenp-2005 abstract.pdf

0519-chenp-2005 claims.pdf

0519-chenp-2005 correspondence-others.pdf

0519-chenp-2005 correspondence-po.pdf

0519-chenp-2005 description(complete)-duplicate.pdf

0519-chenp-2005 description(complete).pdf

0519-chenp-2005 drawings-duplicate.pdf

0519-chenp-2005 drawings.pdf

0519-chenp-2005 form-1.pdf

0519-chenp-2005 form-18.pdf

0519-chenp-2005 form-26.pdf

0519-chenp-2005 form-3.pdf

0519-chenp-2005 form-5.pdf

0519-chenp-2005 others.pdf

0519-chenp-2005 pct.pdf

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Patent Number

215415

Indian Patent Application Number

519/CHENP/2005

PG Journal Number

13/2008

Publication Date

31-Mar-2008

Grant Date

26-Feb-2008

Date of Filing

01-Apr-2005

Name of Patentee

BJ SERVICES COMPANY

Applicant Address

5500 NW Central Drive, Houston, Texas 77092,

Inventors:

#	Inventor's Name	Inventor's Address
1	STEPHENSON, Christopher, John	7700 Willowchase Blvd. #737, Houston, Texas 77070,
2	RICKARDS, Allan, Ray	1003 Hickory Court, Tomball, Texas 77375,
3	BRANNON, Harold, Dean	32207 Edgewater Drive, Magnolia, Texas 77354,
4	GUPTA, Satyanarayana, D.V	38 Webb Creek Place, The Woodlands, Texas 77382,

PCT International Classification Number

E21B 43/67

PCT International Application Number

PCT/US2003/027611

PCT International Filing date

2003-09-02

PCT Conventions:

#	PCT Application Number	Date of Convention	Priority Country
1	60/407, 734	2002-09-03	U.S.A.
2	60/428, 836	2005-11-25	U.S.A.