NO342605B1 - Proppant or sand control particulate material of a selectively configured porous material and method of treating underground formations with this material - Google Patents

Abstract

Methods and compositions useful for underground formation treatments, such as hydraulic fracturing treatments and sand control including porous materials. Such porous materials may be particles of selectively configured porous materials prepared and / or treated with selected glazing materials, coating materials and / or penetrating materials to have the desired strength and / or density to suit particular downhole conditions for well treatment such as hydraulic fracturing treatments. and sand control treatments. Porous materials can also be used in selected combinations to optimize fracture or sand control performance and / or can be used as materials of relatively light weight in liquid carbon dioxide-based well treatment systems.

Description

The present invention generally relates to methods and compositions useful for the treatment of underground formations, such as hydraulic fracturing treatments and sand control.

The background of the invention

Hydraulic fracturing is a common stimulation technique used to enhance the production of fluids from underground 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 treatment is completed. After deposition, the proppant material serves to keep the fracture open and thereby improve the ability of fluids to migrate from the formation to the wellbore 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 typically employ proppant materials that are placed downhole with a gelatinized carrier fluid such as water-based fluid such as gelatinized saline. Gelatinizing agents for proppant carrier fluids can provide a source of proppant pack and/or formation damage, and proppant sedimentation can interfere with proper downhole placement. Formation damage can also be caused by gelatinized carrier fluids used to place particles downhole for purposes such as sand control, such as gravel packs, frac packs, and similar materials. Formulation of gelatinized carrier fluids usually requires equipment and mixing steps designed for this purpose.

Hydraulic fracturing treatments can also use proppant materials that are placed downhole with non-aqueous fluids, such as liquid CO2 and liquid CO2/N2 systems. Plugging agents commonly used with such non-aqueous fluids tend to settle in the system.

Many different materials have been used as proppants including sand, glass beads, walnut shells, and granular metal powder. Commonly used proppants today include various types of sand, resin coated sand, medium strength ceramics, and sintered bauxite; all applied for their ability to cost-effectively withstand the respective reservoir closure stress environment. As the relative strength of the different materials increases, so do the respective particle densities, which range from 2.65 g/cc for sand to 3.4 g/cc for sintered bauxite. Unfortunately, increasing particle density leads directly to increasing difficulty in proppant transport and a reduced proppant fracture volume for equal amounts of the respective proppant, which reduces fracture conductivity. Previous efforts to use lower density materials as a proppant have generally resulted in failure due to insufficient strength to maintain fracture conductivity even at the lowest closure loads (6.9 MPa).

Recently, deformable particles have been developed. Such deformable particles for sand backflow control are significantly lighter than conventional proppants and exhibit high compressive strength. Such deformable materials include polystyrene divinylbenzene (PSDVB) deformable beads. However, such beads have not been completely successful, primarily due to limitations in the base material. While PSDVB beads offered excellent deformability and elasticity, they lacked the structural integrity to withstand high closure loads and temperatures.

The first successful route to generate functional deformable particles was the application of modified ground walnut shells. Walnut shells in their natural state have been used as proppants, fluid loss agents and drilling mud loss materials for many years with greater or lesser degrees of success in each respective task. As a proppant, natural walnut shells have very limited applicability, because they deform quite easily after application of closure loads. This deformation dramatically reduces conductivity and limits the usability of the natural material to relatively low-closure environments.

Walnut shell-based ultra-lightweight (UCW) proppants can be manufactured in a two-step process using walnut particles with a narrow size distribution (ie 20/30 US mesh), and impregnating them with strong epoxy or other resins. These impregnated walnut shell particles are then coated with phenolic or other resins in a manner similar to most resin-coated proppants (RCPs). Such walnut shell-based ULW sealants have a bulk density of 0.85 grams/cc and withstand up to 41.4 MPa closing load at 79 ºC.

Generally speaking, the stronger the proppant, the greater the density. As the density increases, so does the difficulty of placing that particle evenly throughout the resulting fracture geometry. Excessive sedimentation can often lead to bridging of the proppant in the formation before the desired stimulation is achieved. The lower particle density reduces the fluid velocity required to maintain proppant transport within the fracture, which in turn ensures that a greater amount of the formed fracture area is plugged.

ULW proppants that allow optimization of fracturing treatment with improved fracture length and well productivity are therefore desired.

In GB 2360534 A, an underground formation is treated by injecting a mixture of fracture plug and deformable particulate material into the formation. This deformable particulate material can be combined with the fracture proppant for the purpose of increasing fracture conductivity, reducing fine particle formation and/or reducing proppant flowback.

The fracture plug can then be a material such as sand, and the deformable particulate material can be a material such as particle grains of polystyrene-divinylbenzene.

Summary of the invention

The present invention provides a plugging agent or sand control particulate material of a selectively configured porous particulate material, wherein the selectively configured porous particulate material comprises a porous particulate material, the porous particulate material is a ceramic material, polyolefin, styrene-divinylbenzene copolymer or polyalkyl acrylate esters, and is treated with a non-porous penetrating, coating and/or glazing material so that one of the following conditions applies:

(i) the porosity and permeability of the selectively configured porous particulate material is such that a fluid can be drawn at least partially into its porous matrix by capillary action; or

(ii) the apparent specific gravity or apparent density of the selectively configured porous particulate material is less than the apparent specific gravity or apparent density of the porous particulate material; or

(iii) the penetrating, coating and/or glazing material is capable of encapsulating air or a light weight fluid within the porous particulate material;

and further where the porous particulate material exhibits inherent or induced permeability.

The invention further relates to a method for treating a well that penetrates an underground formation, which comprises introducing the plugging agent or sand control, particularly the material according to the invention.

In a preferred embodiment, the penetrating material and/or coating layer and/or glaze layer on 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 . Furthermore, the coating layer and/or the penetrating material and/or the glaze 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 itself. Furthermore, the selectively configured porous material exhibits compressive strength under conditions as high as 69 MPa, closure load, API RP 56 or API RP 60.

In a preferred mode, the porous particulate composition is a suspension of porous particles in a carrier fluid. The suspension preferably forms a pack of particulate material which is permeable to fluids produced from the wellbore and substantially prevents or reduces the production of formation materials from the formation into the wellbore.

Furthermore, the porous particulate material can exhibit a porosity and permeability so that a fluid can 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 can be drawn at least partially into the porous matrix of the porous particulate material using a vacuum and/or can be forced at least partially into the porous matrix under pressure.

The selectively configured porous particulate material may consist of a plurality of coated particles bound together. In this way, the porous material is a cluster of particles coated with a coating or penetrating layer or glaze layer. Suitable coating layers or penetrating materials include liquid and/or curable resins, plastic materials, cements, sealants or binders, such as a phenol, phenol formaldehyde, melamine formaldehyde, urethane, epoxy resin, nylon, polyethylene, polystyrene or a combination thereof. In a preferred mode, the coating layer or penetrating material is an ethyl carbamate-based resin.

In a preferred embodiment, the selectively configured porous particulate materials are derived from particles of lightweight and/or substantially neutral liquid particles. The use of the selected particles of porous material and relatively lightweight particulate material and/or substantially neutral liquid particulate material as a particulate fracture plug agent advantageously provides substantially improved overall system performance in hydraulic fracturing applications, or in other well treatment applications such as sand control.

The compositions containing porous particulate material used in the invention may further contain a carrier fluid. The carrier fluid may be a replenishing or recovery salt solution, salt water, fresh water, a liquid hydrocarbon, or a gas such as nitrogen or carbon dioxide.

The compositions containing porous particulate material may further contain a gelatinizing agent, cross-linking agent, gel breaker, surfactant, foaming agent, de-emulsifier, buffer, clay stabilizer, acid or a mixture thereof.

Brief description of the drawings

For a more complete understanding of 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 showing bulk apparent density comparison of the data according to Example 1

Fig. 2 is a graph showing permeability versus closure load data according to Example 2

Fig. 3 is a graph showing conductivity versus closing load data according to Example 2

Fig. 4 is a graph showing conductivity versus closing load data according to Example 2

Fig. 5 is a graph showing permeability versus closure load data according to Example 2

Fig. 6 is a graph showing conductivity comparison data according to Example 2. Fig. 7 is a graph showing permeability comparison data according to Example 2. Fig. 8 is an SEM photograph of a particle of porous material according to Example 3.

Fig. 9 is an SEM photograph of a particle of porous material according to Example 3. Fig. 10 is an SEM photograph of a particle of porous material according to Example 3. Fig. 11 is an SEM photograph of a particle of porous material according to Example 3 Fig. 12 is an SEM photograph of a particle of porous material according to Example 3. Fig. 13 is an SEM photograph of a particle of porous material according to Example 3. Fig. 14 is an SEM photograph of a particle of porous material according to Example 3. Fig. 15 is an SEM photograph of a particle of porous material according to Example 3. Fig. 16 illustrates proppant distribution for a selected combination of well treatment particles according to one embodiment of the shown compositions and methods described in Example 4.

Fig. 17 illustrates comparative proppant distribution data according to Example 4 for Ottawa sand alone.

Detailed description of the preferred designs

As used herein, the following terms shall have their respective meanings: "porous particulate material" shall refer to porous ceramic or porous organic polymeric materials. Examples of material types suitable for use as particles of porous materials include particles 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 that have been modified to achieve desired physical properties, such as particle characteristics, desired strength and/or apparent density to suit particular downhole conditions for well treatment such as hydraulic fracturing treatments and sand control treatments.

"non-selectively configured porous particulate material" shall refer to any porous natural ceramic material, such as lightweight volcanic rocks such as pumice, as well as perlite and other porous "lavas" such as porous (vesicular) Hawaiian basalt, porous Virginia diabase, and Utah rhyolite. Furthermore, inorganic ceramic materials, such as alumina, magnetic glass, titanium oxide, zirconium oxide, and silicon carbide can also be used. In addition, the term shall refer to a synthetic porous particulate material which has not been chemically altered and which provides desired physical properties, such as particle characteristics, desired strength and/or apparent density to suit particular downhole well treatment conditions;

"relatively lightweight" shall refer to a porous particulate material having an apparent density (API RP 60) that is significantly less than a conventional particulate material used in hydraulic fracturing or sand control operations, such as sand having an apparent specific gravity (API RP 60) of 2.65 and bauxite which has an apparent specific gravity of 3.55. The apparent specific gravity of a relatively lightweight material is less than about 2.4.

"substantially neutral liquid" shall refer to a porous particulate material having an apparent density sufficiently close to the apparent density of a selected ungelatinized or weakly gelatinized carrier fluid, such as an ungelatinized or weakly gelatinized supplemental salt solution, other aqueous fluid, "slick water", or other suitable fluid, which allows pumping and adequate placement of the propellant/particulate material using the selected ungelatinized or weakly gelatinized carrier fluid.

a "weakly gelatinized carrier fluid" is a carrier fluid that has a viscosity increaser or friction reducer to achieve friction reduction when pumped downhole, for example, when pumped down a pipeline, work string, casing, coiled pipeline, drill pipe, or similar location, in which polymer- or the viscosity enhancer concentration is from about 0 kg of polymer per cubic meter of base fluid (0 pounds of polymer per 1000 gallons of base fluid), to about 1.19 kg of polymer per cubic meter of base fluid (10 pounds of polymer per 1000 gallons of base fluid), and/or the viscosity is from about 1 to about 10 centipoise. An "ungelatinized carrier fluid" is a carrier fluid that has no polymer or viscosity increaser. The ungelatinized carrier fluid may contain a friction reducer known in the art.

The selectively configured porous particulate materials as well as the non-selectively configured particulate materials are particularly effective in hydraulic fracturing as well as sand control fluids such as water, brine, slick water such as "slick water" fracturing treatments at relatively low concentrations to achieve partial monolayer fracture, low concentration polymer gel fluids (linear or cross-linked), foam (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 example, the particles of the selectively configured porous material or the particles of the non-selectively configured porous material 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 particles of the selectively configured porous particulate material or the particles of the non-selectively configured porous particulate material into a well and/or subterranean formation fracture in communication therewith may be used including, but not limited to but not limited to, carrier fluids comprising salt water, fresh water, potassium chloride solution, a saturated sodium chloride solution, liquid hydrocarbons and/or nitrogen or other gases may be used. Suitable carrier fluids include or may be used in combination with fluids having gelatinizing agents, cross-linking agents, gel breakers, surfactants, foaming agents, de-emulsifiers, buffers, clay stabilizers, acids, or mixtures thereof.

When used in hydraulic fracturing, the particles of the selectively configured porous particulate material or the particles of the non-selectively configured porous particulate material may be injected into a subterranean formation in conjunction with a hydraulic fracturing treatment or other treatment at pressures sufficiently high to cause the formation or enlargement of fractures. Such other treatments may be near-wellbore in nature (affecting near-wellbore regions) and may be aimed at improving wellbore productivity and/or controlling the production of fracture plug or formation sand. Specific examples include gravel packing and frac packs. Furthermore, such particles can be used alone as a fracture proppant/sand control particulate material, or in mixtures in amounts and with types of fracture proppant/sand control materials, such as conventional fracture or sand control particulate material. Additional information on hydraulic fracturing methods and materials for use therein can be found in U.S. Pat. Patent No. 6,059,034 and in the U.S. Patent No. 6,330,916, which is incorporated herein by reference.

When used in well treatments, particles of selected porous materials that have been selectively configured, such as glazed and/or treated with one or more selected coating and/or penetrating materials, may be introduced into a borehole at any concentration(s) deemed appropriate or effective for the down hole conditions encountered. For example, a well treatment fluid may include a suspension of proppant or sand control particulate material that is comprised entirely of particles of selected relatively light weight porous materials that have been selectively configured, such as glazed and/or treated with one or more selected coatings and/or penetrating materials. Alternatively, it is possible that a well treatment fluid may include a suspension containing a mixture of conventional fracture plug or sand control particulate materials such as sand with particles of selected relatively light weight porous material that has been selectively configured such as glazed and/or treated with one or several selected coating and/or penetrating materials.

In an exemplary embodiment, a gravel pack operation may be performed on a wellbore penetrating a subterranean formation to prevent or substantially reduce the production of formation particles into the wellbore from the formation during the production of formation fluids. The underground formation may be completed to be in communication with the interior of the wellbore by any suitable method known in the art, for example by perforations in a cased wellbore, and/or by an open hole section. A screen assembly as is known in the art can be placed or otherwise disposed within the wellbore so that at least a portion of the screen assembly is disposed adjacent to the underground formation. A slurry including the selectively configured porous particulate material or the non-selectively configured porous particulate material and a carrier fluid may then be introduced into the wellbore and placed adjacent the subterranean formation by circulation or other suitable method to form a fluid permeable package in an annulus area between the screen exterior and the wellbore interior capable of reducing or substantially preventing the passage of formation particles from the formation, while simultaneously allowing the passage of formation fluids from the underground formation to the wellbore during the production of fluids from the underground formation through the screen to the wellbore. It is possible that the slurry may contain all or a proportion of the selectively configured porous particulate material or the non-selectively configured porous particulate material. In the latter case, the balance of the particulate material in the slurry may be another material such as a conventional gravel pack particulate material.

As an alternative to using a screen, the sand control method may utilize the selectively configured porous particulate material or the non-selectively configured porous particulate material according to any method in which a package of particulate material is formed within a wellbore that is permeable to fluids produced from a wellbore , such as oil, gas or water, but which significantly prevents or reduces the production of formation materials, such as formation sand, from the formation into the wellbore. Such methods may, but do not necessarily, 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 used in conjunction with resins such as sand consolidation resins if wished.

The porous particulate material shall include any naturally occurring or manufactured or designed porous ceramic particulate material having an inherent and/or induced porosity. A commercially available instrument, the ACCUPYC 1330 Automatic Gas Pycnometer (Micromeritics, Norcross, GA), which uses helium as an inert gas and the manufacturer's recommended procedure can be used to determine the internal porosity of the particulate materials. The internal porosity is generally from about 10 to 75 percent by volume. Such particulate material may also have an inherent or induced permeability, i.e. individual pore spaces within the particle are connected such that fluids are capable of at least partially moving through the porous matrix, such as penetrating the porous matrix of the particle, or may have inherent or induced non-permeability, individual pore spaces within the particle are freestanding such that fluids are substantially unable to move through the porous matrix, such as unable to penetrate the porous matrix of the particle. The degree of desired porosity connection can be selected and designed into the non-selectively configured porous particulate material. Further, such porous particles may be selected to have a size and shape consistent with typical fracturing proppant particle specifications (ie, having a uniform shape and size distribution), although such uniformity in shape and size is not required.

The apparent specific gravity of the porous particulate material is generally less than or equal to 2.4, preferably less than or equal to 2.0, even more preferably less than or equal to 1.75, most preferably less than or equal to 1.25.

In a selectively configured porous particulate material, the particles can 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 particle of a porous material can be chosen to help provide the desired balance between apparent density and strength. Optional materials may be used together with a glazing, penetrating and/or coating material to control penetration, such as to enhance or impair penetration. For example, in one embodiment, a cationic clay stabilizer, such as CLAY MASTER 5C from BJ Services, may first be applied to the outer surface of a porous ceramic material to inhibit penetration by a coating/penetrating material, such as an epoxy or resin described elsewhere herein .

In a preferred embodiment, the porous material is a relatively light weight particulate material or substantially neutral liquid particulate material. Such materials can be used in a way that eliminates the need for carrier fluid gelatinization, thereby eliminating a source of potential proppant pack and/or formation damage. Furthermore, a relatively light weight particulate material may be easier to place within a target zone due to reduced sedimentation constraints, and a reduced mass of such relatively light weight particulate material is generally required to fill an equivalent volume required with conventional sand control particulates materials, used for example for gravel packing purposes.

Relatively lightweight and/or substantially neutral fluid fracture proppant/particulate material used in hydraulic fracturing/sand control treatment, such as porous ceramic particles having an untreated bulk apparent density of 1.16 and untreated porosity of about 59.3% may be used.

In one embodiment, the porous particulate materials shown can be used as relatively lightweight particulate/propagant material that can be introduced or pumped into a well as neutrally floating particles in, for example, a saturated sodium chloride solution carrier fluid, or a carrier fluid that is any other completion - or recovery salt solution known in the art, thereby eliminating the need for harmful polymer or fluid loss material. In one embodiment, such a material can be used as a proppant/sand control particulate material at temperatures up to about 371 ºC, and closure loads up to about 55.2 MPa. However, these temperature ranges and closing loads are only exemplary, it is understood that the materials shown can be used as proppant/sand control materials at temperatures greater than about 371 ºC and/or at closing loads greater than about 55.2 MPa. In any event, it will be understood with the benefit of this presentation that porous particulate material and/or coating/penetrating materials may be selected by those skilled in the art to meet and withstand expected downhole conditions for a given application.

In those embodiments where the shown particles of porous material are used as relatively lightweight and/or substantially neutral liquid particulate/propagant materials, they can be used with carrier fluids that are gelatinized, non-gelatinized, or have a reduced or lighter gelatinization requirement compared to carrier fluids used with conventional fracture treatment/sand control methods. In one embodiment using one or more of the disclosed substantially neutral liquid particulate materials and a salt solution carrier fluid, mixing equipment need only include such equipment capable of (a) mixing the salt solution (dissolving soluble salts), and (b) homogeneously dispersion in the substantially neutrally liquid particulate material. In one embodiment, a substantially neutral liquid particulate/propagant material may advantageously be pre-suspended and stored in a storage fluid, such as saline solution of close or substantially similar density, and then pumped or placed downhole as is, or diluted in place.

Examples of non-natural porous particulate materials for use in the invention include, but are not limited to, porous ceramic particles such as those particles available from Carbo Ceramics Inc. as "Econoprop". and those fired kaolinitic described in U.S. Patent No. 5,188,175 which is incorporated herein by reference. As described in this reference, such particles may include solid spherical pellets or particles from raw materials (such as kaolin clay) having an alumina content of between about 25% and 40% and a silica content of between about 50% and 65%. A starch binder can be used. Such particles can be characterized as having a silica to alumina content ratio of from about 1.39 to about 2.41, and an apparent specific gravity of between about 2.20 and about 2.60 or between about 2.20 and about 2.70.

It will also be understood that porous ceramic particles can be selectively prepared from raw materials such as those described in United States Patent No. 5,188,175; United States Patent No. 4,427,068 and United States Patent No. 4,522,731, all of which are incorporated herein by reference, such as by including selected process steps in the initial material manufacturing process to result in a material possessing desired characteristics of porosity, permeability, apparent density or apparent specific gravity, combinations thereof. For example, such raw materials can be fired at a relatively low temperature of about 668 ºC or about 700 ºC to achieve a desired crystalline structure and a more porous and lighter structure. In an exemplary embodiment of such particles, as described elsewhere herein, approximately 20/40 mesh size porous material fired kaolinitic particles from Carbo Ceramics Inc. may be selected for use in the method shown. These particles have the following internal characteristics: bulk apparent density about 1.16, internal porosity about 59.3%. These particles can be treated with a variety of penetrating/coating materials in an amount from about 0.5 to about 10% of the total weight of the particles. Such coated particles may be manufactured and/or supplied, for example, by Fritz Industries of Mesquite, Texas.

In one exemplary case, the size of such material can be chosen to range from about 200 mesh to about 8 mesh.

In such a case, the particles can be selected based on porosity and/or permeability characteristics so that they have the 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 particle of porous material can be chosen to help provide the desired balance between apparent density and strength. Optional materials may be used in conjunction with a glazing, penetrating and/or coating material to control penetration such as enhance or impair penetration. For example, in one embodiment, a cationic clay stabilizer, such as CLAY MASTER 5C from BJ Services, may first be applied to the outer surface of a porous ceramic material to inhibit penetration by a coating/penetrating material, such as an epoxy or resin described elsewhere herein .

In a selectively configured porous particulate material, the porous particulate material is chemically treated to impart desired physical properties, such as porosity, permeability, apparent density or apparent specific gravity, or combinations thereof to the particulate materials. Such desired physical properties are different from the physical properties of the porous particulate materials before treatment.

The desired physical properties can further be present in non-selectively configured porous particulate materials. Non-selectively configured porous particulate materials shall include naturally occurring porous ceramic materials as well as non-natural (synthetic) materials manufactured in a manner that provides 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 the non-selectively configured porous particulate material exhibit compressive strength under conditions as high as 69 MPa closure stress, API RP 56 or API RP 60, generally between from about 1.7 MPa to about 55.2 MPa closure stress, in combination with an apparent specific gravity less than or equal to 2.4, to meet the pumping and/or downhole formation conditions of a particular application, such as hydraulic fracturing treatment, sand control treatment.

Such desired physical properties can be transferred to a portion or portions of the porous particulate material that the selectively configured porous particulate material or the non-selectively configured porous particulate material, such as on the particle surface of the particulate material, at or in the particle surface of the particulate material , in an area near the particle surface of the particulate material, in the internal particle matrix of a particulate material or a proportion 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 the non-selectively configured porous particulate material can be taken advantage of to result in a larger fracture or frac pack width for the same charge, such as kg per square meter of proppant (pounds per square foot of proppant), to give much greater total volume and increased width for the same mass. Alternatively, this characteristic allows less loading of proppant material to be pumped while still achieving an equivalent width.

In a preferred embodiment, selective configuration, such as by the use of glazing, coating and/or penetrating materials, such as those materials described elsewhere herein, can be selectively used to modify or adjust 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, can be advantageously used, for example, to provide proppant or sand control particles of adapted apparent specific gravity for use as a substantially neutral floating particulate material of a variety of different weights - or apparent specific gravity carrier fluids.

The selectively configured porous particulate material has an apparent density from about 1.1 g/cm<3> to about 2.6 g/cm<3>, an apparent bulk density from about 1.03 g/cm<3> to about 1 .5 g/cm<3>, and an internal porosity of from about 10 to about 75 percent by volume. In one example, bulk densities can be controlled to range from about 1.1 g/cm<3> to about 1.5 g/cm<3>, although larger and smaller 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 that has been selectively modified by treatment with a coating or penetrating material using any suitable wet or dry process. Methods of coating particles, such as fracture propellant particles, with materials such as resin are known in the art, and such materials are available, for example, from manufacturers listed herein. With respect to coating the porous particulate materials shown, coating operations may be performed using any suitable method known in the art.

As used herein, the term "penetrating" shall further refer to being partially or completely impregnated with a penetrating material, by, for example, vacuum and/or pressure impregnation. For example, a 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 skilled in the art will appreciate that one or more coating and/or penetrating materials may be selected to treat a particulate porous material to meet particular criteria or requirements of a given downhole application based on the information and examples shown herein, as well as knowledge in the art. In this context, characteristics of particles of porous material such as composition, porosity and permeability characteristics of the particulate material, size and/or coating or penetrating material characteristics, such as composition, amount, thickness or degree of penetration, can be selected as such. The coating or penetrating material is typically non-porous.

The porosity and permeability characteristics of the porous particulate material allow 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 absorbing water. Alternatively, one or more penetrating materials 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.

Examples of penetrating materials that may be selected for use include, but are not limited to, liquid resins, plastic materials, 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/compressive strength, apparent specific gravity, etc. It will be understood that selected combinations of any two or more such penetrating materials may also be used either in admixture or in sequential penetrating applications.

Examples of resins that can be used as penetrating and/or coating materials include, but are not limited to, resins and/or plastic materials or any other suitable cement, sealant or binder which, once placed at least partially within a selected particle, can be cross-linked and/or hardened to form a rigid or substantially rigid material within the porous structure of the particle. Specific examples of plastic materials 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 volatility 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 from Borden Chemical and identified as 500 series and 700 series resins (eg, 569C, 794C, etc.). Additional specific examples of resins include, but are not limited to the SIGMASET series of low temperature curing urethane resins from Borden Chemical, such as SIGMASET, SIGMASET LV, SIGMASET XL, ALPHASET phenolic resin from Borden Chemical, OPTI-PROP phenolic resin from Santrol, and POLAR PROP low temperature curing resin from Santrol. Where desired, cure characteristics, such as cure time, can be adjusted to suit particular processing methods and/or end product specifications by, for example, adjusting relative amounts of resin components. Still further examples of suitable resins and coating methods include, but are not limited to those found in European Patent Application EP 0771 935 A1; and the U.S. Patents No. 4,869,960; 4,664,819; 4,518,039; 3,929,191; 3,659,651; and 5,422,183, all of the foregoing references are incorporated herein by reference in their entirety.

In an exemplary embodiment, a curable phenolic resin or other suitable curable material can be selected and used as a coating material so that individually coated particles can be bonded together at downhole temperature, after the resin flows and cross-links/cures downhole, to facilitate proppant pack/sand control particulate consolidation by location.

Alternatively, a cured phenolic type resin coating 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 subsurface formation. The degree of penetration of the coating or penetrating fluid into the porous particulate material can be limited by interrupted porosity, such as substantially impermeable or isolated porosity, within the internal matrix of the particulate material.

This can either limit the extent of uniform penetration of penetrating material uniformly towards the core, such as leaving a layered particle cross-section having an outer penetrating layer with unpenetrated substantially spherical core, and/or can cause uneven penetration all the way to the core, such as to bypass "islands" of interrupted porosity but penetrate all the way to the core. In any case, a penetrating and/or coating material may trap or encapsulate air (or other fluid having an apparent specific gravity less than the particle matrix and less than the coating/penetrating material) within the interrupted porosity to reduce the apparent specific gravity at the desired the quantity. Such materials coat and/or penetrate the porous particulate material without invading the porosity to effectively encapsulate the air within the particulate porosity. Encapsulation of the air provides preservation of the ultra-light weight character of the particles once they are placed in the transport fluid. If the resin coating or transport fluids should significantly penetrate the porosity of the particle, the density increases accordingly, and the particle no longer has the same lightweight properties. The resin coating also adds strength and significantly improves proppant packing permeability at elevated loads.

Coating layers may be applied as desired to contribute to particle strength and/or reduce in situ fines migration once placed in the subsurface formation. The coating significantly increases the strength and compressive strength of the ultra-lightweight ceramic particle. In the case of natural sand types, the resin coating protects the particle from crushing, helps resist encapsulation and prevents the release 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 it has 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 greatly reduced apparent density.

For example, the selected porous particulate material may be treated with a selected penetrating material in such a manner that the resulting selectively configured porous particulate material has a greatly reduced apparent density, such as having an apparent density closer to or approaching the apparent specific gravity of a carrier fluid so that it is neutrally fluid or semi-fluid in a fracturing fluid or sand control fluid.

Alternatively, a penetrating material may be selected to help structurally support the matrix of the porous particulate material (ie, increase the strength of the porous matrix) and increase the ability of the particulate material to withstand the closure loads of a hydraulically fractured formation, or other downhole loads. .

For example, a penetrating material can be chosen by balancing the need for low apparent density against the desire for strength, ie a denser material can provide much greater strength. In this context, the inherent and/or induced porosity of the porous particulate material can be selected to provide the desired balance between apparent density and strength. It will be understood that other variables, such as downhole temperature and/or fluid conditions, can also influence the choice of penetrating material.

The coating material or penetrating material is generally present in the selectively configured porous particulate material in an amount from about 0.5% to about 10% by weight of the total weight. The thickness of the coating layer of the selectively configured porous particulate material is generally between from about 1 to about 5 microns. The extent of penetration of the penetrating material by the selectively configured porous particulate material is from less than about 1% by volume penetration to less than about 25% by volume penetration.

Particularly 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 about 60%. Such materials can be treated with a coating material which does not penetrate the porous matrix of the porous particulate material, or which only partially penetrates the porous matrix of the ceramic particulate material. Such treated ceramic materials may have an apparent density of from about 1.1 g/cm<3> to about 1.8 g/cm<3> (alternatively from about 1.75 g/cm<3> to about 2 g/cm <3>and further alternatively about 1.9 g/cm<3>), a bulk apparent density from about 1.03 g/cm<3>to about 1.5 g/cm<3>, and a treated internal porosity from about 45% to about 55%. However, values outside these example ranges are also possible.

As an example, it has been seen that a porous ceramic treated with about 6% epoxy exhibits 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 from about 0.5 wt. % to about 10% by weight of the total weight of individual particles. When present, the thickness of a coating material can be chosen to be from about 1 to about 5 microns on the exterior of the particle. When present, the extent of penetration of penetrating material into a particle of porous material can be selected to be from less than about 1% by volume penetration to less than about 25% by volume penetration of the particle. It will be understood that coating amounts, coating thickness and penetration amounts may also be outside these example ranges.

Furthermore, the porous particulate material can be at least partially selectively configured by glazing, such as, for example, surface glazing with one or more selected non-porous glazing 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 used and/or the permeability (ie connectivity of internal porosity ) characteristics of the selected porous particulate material, such as unconnected porosity that allows substantially no penetration to occur. For example, a selected porous particulate material can be selectively configured, such as being glazed and/or coated with a non-porous material, in such a way that the porous matrix of the resulting particle is at least partially or completely filled with air or another gas , i.e. the interior of the resulting particle includes only air/gas and the structural material that forms and surrounds the pores. Again, the inherent and/or induced porosity of a particle of porous material can be chosen to assist and provide the desired balance between apparent density and strength, and glazing and/or coating without penetration (or extension of configured area into the particle matrix). can be chosen to result in a particle where all or substantially all of the porosity in the particle is unpenetrated and encapsulated to trap air or other fluid of relatively light weight to achieve minimum apparent specific gravity. In addition to sealing the particle, such as sealing air/gas within the porous matrix of the particle, such selective configuration, such as the use of glaze and/or coating materials, may be chosen to provide other benefits.

In a preferred embodiment, the porous particulate material, such as the calcined kaolinitic particles described above, is prepared by using a glaze-forming material to form a glaze to seal or otherwise alter the permeability of the particle surface so that a given particle is less exposed for penetration or saturation of a well treatment fluid and therefore is able to maintain relatively light weight or substantially neutral flow characteristics in relation to the well treatment fluid after exposure to such fluid. Such glazing may be accomplished using any suitable method of forming a glaze on the surface or in the near surface of a particle, including by incorporating a glaze-forming material into the "green paste" of raw material which is then shaped as cast into a mold of the particle before burning. Those skilled in the art recognize that glazes can be made from a variety of methods, including the application of a smooth, vitreous coating to form a hard, non-porous surface. Glazes can be formed from 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 to the substrate by firing or similar processes known to those skilled in the art. In addition, the use of borates or similar additives can improve the glaze.

Examples of such glaze-forming materials include, but are not limited to, materials such as magnesium oxide-based materials, boric acid/boric oxide-based materials, etc. During firing, the glaze-forming material(s) "sweat" out to the surface of the particles and form a glaze. Alternatively, glazing can be carried out, for example, by applying a suitable glazing-forming material to the surface of the formed raw material or the "green" particles before firing such as by spraying, dipping and similar methods, so that glazing occurs during particle firing. Further alternatively, a glaze-forming material can 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 of such a glazing treatment include maintaining the relatively low apparent density of a relatively low weight porous particle without the necessity of further modification, such as the necessity of coating with a separate polymer coating although optional coatings may be applied if desired. Furthermore, the resulting relatively smooth glazed surface of such a particle may also serve to improve the ease of multiphase fluid flow, such as flow of water and gas and oil, through a particle pack, such as through a proppant pack in a fracture, resulting in increased breakdown conductivity.

In an alternative embodiment, one or more types of the shown selectively configured porous particulate material or non-selectively configured porous particulate material may be used as particulate matter for well treatment purposes in combination with a variety of different types of well treatment fluids (including liquid CO2-based systems and other liquid -gas or foamed-gas carrier fluids) and/or other types of particulate matter to achieve synergistic benefits, it is understood that benefits of the disclosed methods and compositions can also be obtained when using only one type of the disclosed porous materials as a sole particulate material for well treatment. Furthermore, although exemplary embodiments are described herein with reference to porous materials and relatively light weight porous materials, it will be understood that advantages of the disclosed methods and compositions may also be realized when applied to materials that can be characterized as of non-relatively light weight weight and/or non-porous in nature.

Eliminating the need to formulate a complex suspension gel can mean a reduction in pipeline frictional pressure, particularly in coiled pipeline and in the amount of on-site mixing equipment and/or mixing time requirements, as well as reduced costs. Further, when selectively configured, such as by glazing and/or coating/penetrating material treatment, to have sufficient strength and relatively light weight properties, the disclosed relatively light weight particles may be used to facilitate hydraulic fracturing treatments or sand control treatments carried out through coiled pipeline, by greatly reducing the requirements for fluid suspension properties. Downhole, a greatly reduced propensity for sedimentation (compared to conventional proppant or sand control particulate materials) can be achieved, especially in highly deviated or horizontal wellbore sections. In this context, the particulate material shown can be advantageously used in any deflected well having a deflection angle between about 0 degrees to about 90 degrees with respect to the vertical. In one embodiment, however, the particulate material shown can be advantageously used in horizontal wells or in deflected 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. Therefore, use of the disclosed particulate materials shown herein can be used to achieve surprising and unexpected improvements in fracturing and sand control methodology, including reduction in proppant pack and/or formation damage and improvement in well productivity.

It will be understood that the characteristics of glaze materials, penetrating materials and/or coating materials given herein, such as composition, amounts, types are only exemplary. In this context, such characteristics may be selected by those skilled in the art, with the benefit of this presentation, to meet and withstand expected downhole conditions of a given application using methods known in the art such as those described herein.

In another shown embodiment, mixtures of two or more different types of particles having different particulate characteristics, such as different porosity, permeability, apparent density or apparent specific gravity, sedimentation rate in carrier fluid, can be used as particulate materials for well treatment. Such mixtures may contain at least one porous particulate material and at least one other particulate material which may be, but is not necessarily, a porous particulate material.

In addition, the selectively configured porous particulate material and the non-selectively configured porous particulate material can be used as two or more multiple layers. In this context, successive layers of such materials can be used. For example, 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, the 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 particle of porous material. A selected coating material can be applied to achieve a coating layer at least about 2 microns thick on the outside of the selected particle of porous material.

Such mixtures can further be used in any type of well treatment application, including in any of the well treatment methods described elsewhere herein. In one exemplary embodiment, such mixtures can be used to optimize hydraulic fracture geometries to achieve improved well productivity, such as achieving increased plugged fracture length in relatively "tight" gas formations. The selection of various particulate materials and amounts thereof for use in such mixtures may be made based on one or more well treatment considerations including but not limited to well treatment purposes, such as for sand control and/or for the formation of plugged fractures, well treatment fluid characteristics, such as apparently specific weight and/or rheology of carrier fluid, well and formation conditions such as formation depth, formation porosity/permeability, formation closure load, type of optimization desired for the geometry of downhole placed particulate materials such as optimized fracture package plugged length, optimized sand control package height, optimized fracture package and/or sand control package conductivity and combinations thereof.

Such different types of particles can be selected, for example, to obtain a mixture of different specific weights or densities in relation to the selected carrier fluid. For example, a mixture of three different particles may be selected for use in a water fracturing treatment to form a mixture of well treatment particulate materials having three different specific gravities, such as apparent specific gravity of the first particle type from about 1 to less than about 1, 5; apparent specific gravity of the second particle type from greater than about 1.5 to about 2.0; and apparent specific gravity of the third particle type from about greater than 2.0 to about 3.0; or in one specific embodiment, the three particle types have respective specific gravities of about 2.65, about 1.7 and about 1.2, it being understood that the foregoing values of apparent specific gravity are exemplary only and that other specific gravities and ranges of specific weights can be used. In one example, at least one of the types of selected well treatment particulate materials may be selected to be substantially neutrally fluid in the selected carrier fluid.

Such different types of particles may be selected for use in any amount appropriate to achieve desired well treatment results and/or costs. In one embodiment, however, several particle types may be selected for use in a mixture of particulate materials for well treatment in amounts approximately equal in proportion based on the total weight of the mixture. Therefore, three different particle types can all be used in respective amounts of about 1/3 of the total mixture as in the total weight of the mixture, four different particle types can all be used in respective amounts of about 1/4 of the total mixture as in the mixture's total weight. However, these relative amounts are only exemplary, it is understood that any desired relative amount of each selected type of well particulate material may be used such as for one exemplary embodiment of a mixture having three different particle types, as selected from the various particle types described elsewhere herein , the amounts of each selected particle type may be present in the mixture in an amount ranging from about 10% to about 40% such as by total weight of the mixture to achieve 100% by weight of the total mixture.

It will be appreciated from this presentation that the selection of various particulate materials and amounts thereof for use in such mixtures may be made using any methodology appropriate for evaluating such mixtures in light of one or more well treatment considerations. In one embodiment, any method known in the art that is appropriate for modeling or predicting sand control package or fracture package geometry/conductivity can be used, as illustrated and described in connection with Example 4 herein.

Examples of different particle types that may be selected for use in such mixtures include, but are not limited to, conventional sand particulate materials, such as Ottawa sand, well treatment particulate materials of relatively light weight, such as ground or crushed nut shells that are at least partially surrounded by at least one layer component of protective or hardening coating, selectively configured porous materials, such as one or more of the selectively configured porous materials described herein, such as deformable particles. Additional examples of particle types that may be selected for use in such compositions include any of the particles described in U.S. Pat. Patent application serial number 10/113,844, filed April 1, 2002; U.S. Patent application serial number 09/579,146, filed May 25, 2000; U.S. Patent No. 6,364,018; U.S. Patent No. 6,330,916; and the U.S. Patent No. 6,059,034, all of which are incorporated herein by reference.

In one exemplary embodiment, selected mixtures of conventional sand proppant, particulate materials of ground or crushed nutshells of relatively light weight, which are at least partially surrounded by at least one layer of component of protective or hardening coating, and selectively configured porous materials such as porous material burned kaolinitic particles of relatively light weight treated with penetrating/coating materials described herein are used in a hydraulic fracturing treatment that uses ungelatinized or weakly gelatinized carrier fluid. One specific example of such a mixture is described in Example 4 herein. In such an embodiment, these three different particle types may be used in any relative volume or weight amount or ratio appropriate to achieve desired well treatment results.

In one specific example, these different particle types can be used in a well treatment particulate composition that includes about 1/3 by weight of conventional sand proppant of the total weight of well treatment particulate material, about 1/3 by weight of the relatively light weight particulate material , such as ground or crushed nut shell core that is at least partially surrounded by at least one layer of protective or hardening coating component) of total weight of well treatment particulate material, and about 1/3 by weight of selectively configured porous particulate material with relatively light weight, such as calcined kaolinitic particles treated with a penetrating/coating material described herein, of total weight of well treatment particulate material. It will be understood that the foregoing relative quantities are exemplary only and may be varied, for example, to achieve desired results and/or to meet cost objectives of a given treatment. It will also be understood that the methods and compositions shown can also be practiced with such mixtures using other types of relatively light weight particulate materials as described elsewhere herein, such as porous polymeric materials, such as polyolefins, styrene-divinylbenzene based materials, polyalkyl acrylate esters and modified starches. Furthermore, any of the porous materials shown may be used in "pure" or unmodified form in the mixtures shown where apparent density and other particle characteristics are appropriate to meet the requirements of the given well treatment application.

In one aspect, well treatment methods, such as hydraulic fracturing and sand control, are shown that can be used to treat a well penetrating a subterranean formation, and include introducing into a well a selected porous particulate material that has been treated with a selected casing material , selected penetrating material, or combination thereof. Individual particles of the particulate material may optionally have a shape with a maximum length-based aspect ratio 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 particulate porous materials that may be selected for use in aqueous carrier fluids include, but are not limited to, porous ceramics, porous polymeric materials, or any other porous material or combinations thereof suitable for selection for combining 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 can be prepared by firing at relatively low temperatures to avoid loss of porosity due to crystallization and water drift. Specific examples include, but are not limited to, porous ceramic particles available from Carbo Ceramics Inc. of Irving, Texas, composed of fired kaolinitic clay fired at a relatively low temperature of about 668 ºC or about 704 ºC (or about 700 ºC and which have trace amounts of components such as cristobalite, mullite and opalite), polyolefin particles, and similar components.

In another shown embodiment, relatively light-weight particulate materials or mixtures including such particulate materials as described elsewhere herein, such as including selectively configured particulate materials and/or non-selectively configured particulate materials as described elsewhere herein, may advantageously used as well treatment particulate materials, such as fracture plug particulate material or sand control particulate material, in condensed gas and foamed gas carrier fluids.

Examples of types of such carrier fluids include, but are not limited to, liquid CO2-based systems, liquid CO2, CO2/N2, and foamed N2i CO2 systems that may be used in hydraulic fracturing applications. In one specific embodiment, porous ceramic well particulate materials having a bulk apparent density of near or about 1.0 g/cm<3>, in either selectively configured or non-selectively configured form, may be used with such condensed gas and/or foamed gas carrier fluids, such as liquid CO2-based systems, liquid CO2, CO2/N2 and foamed N2i CO2 systems.

In another specific embodiment, selectively configured particulate materials and/or non-selectively configured particulate materials can be used which can be characterized as substantially neutrally fluid in such condensed gas and/or foamed gas carrier fluids.

Liquid CO2 has a density close to about 1.02 g/cm<3> under typical fracturing conditions, and conventional proppants, such as sand, or ceramic proppants that have a non-relatively light weight, tend to settle in liquid CO2-based systems. Furthermore, liquid CO2 has very little, if any, viscosity, and therefore proppant transport in a liquid CO2-based system is provided by turbulence and frictional forces, and fractures formed by liquid CO2 are typically relatively narrow. Advantageously, using the methods and compositions shown, proppant transport of particulate materials with relatively light weight is easier than proppant transport of conventional sand proppants or ceramic proppants which do not have relatively light weight.

In one exemplary embodiment, porous ceramic particles of relatively light weight can be used in liquid CO2-based systems. Examples of types of such relatively light weight porous ceramic particles include, but are not limited to, the porous ceramic particles available from Carbo Ceramics for controlled release applications modified in the manufacturing process to have a bulk apparent density close to about 1.0 g/cm<3>. Other suitable examples of relatively light weight porous particles include, but are not limited to, those particles having a bulk apparent density of less than about 2.5 g/cm<3>, alternatively having a bulk apparent density of from about 1.0 g/cm<3>, to about 2.0 g/cm<3>, further alternatively having a bulk apparent density of from about 1.2 g/cm<3>, to about 2.0 g/ cm<3>.

One specific example of suitable relatively light weight porous ceramic particles for use in CO2-based systems in this embodiment is porous ceramic material described elsewhere herein, either in selectively configured form, as described herein in Example 1, or non-selectively configured or unmodified or "pure" form.

In one exemplary embodiment, the practical embodiment of the disclosed methods and compositions, relatively light weight porous ceramic materials or mixtures thereof can be used as fracture proppant materials in liquid CO2-based fracturing systems that employ methodologies similar or the same as those used with conventional proppants in liquid CO2-based fracturing systems. In this regard, liquid CO2-based fracturing job characteristics, such as proppant amounts, proppant sizes, mixing and pumping methodologies, use of relatively light-weight porous ceramic materials, can 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. Additional information on liquid CO2-based fracturing job characteristics that can be used with relatively light weight porous ceramic materials can be found in United States Patent No. 4,374,545, United States Patent No. 5,558,160, United States Patent No. 5,883,053, Canadian Patent No. 2,257,028 and Canadian Patent No. 2,255,413, all of the foregoing references being incorporated herein by reference.

In one exemplary embodiment shown, porous ceramic particles used as fracture proppant particulate material in a liquid CO2-based system may be used in "pure" or unmodified form and may have an apparent specific gravity of from about 1.17 to about 2 ,0. In another exemplary embodiment shown, the use of porous ceramic particles of relatively light weight as fracture proppant particulate material in a liquid CO2-based system allows the concentration of proppant in such a system to be advantageously expanded to around 1200 kg/cubic meter. Other advantages of using the disclosed relatively light weight porous ceramic particles in fluid CO2 based fracturing systems include, but are not limited to, reduced proppant sedimentation in surface mixing equipment prior to pumping downhole and improved proppant transport downhole and into the formation. It will be understood that although shown above for embodiments using porous ceramic particles of relatively light weight, the methods and compositions shown can also be practiced with liquid CO2-based systems using porous material, particulate material of relatively light weight and mixtures thereof such as described elsewhere herein, such as porous polymeric materials such as polyolefins. Any of such materials that can be used in "pure" or unaltered form with liquid CO2-based systems where the apparent density and other characteristics of the particle are appropriate to meet the requirements of the given well treatment application or alternatively can be used in selectively configured form as described elsewhere herein.

The following examples will illustrate the practical implementation of the present invention in a preferred embodiment. Other embodiments within the scope of the claims herein will be obvious to one skilled in the art from consideration of the specification and the practical embodiment of the invention as shown herein. It is intended that the specification, together with the example, should be regarded as exemplary only, while the scope of the invention is indicated by the claims that follow.

EXAMPLES

The following examples are illustrative and should not be considered as limiting the scope of the invention or the claims thereof.

Example 1

To obtain the data for this example, the following procedure was followed: Measured mass of 25 ml sample on a graduated cylinder. The cylinder was tapped several times on the work surface and the volume adjusted to a constant 25 ml before weighing.

Mass/volume = bulk density.

The data for this example is shown in Table 1:

Fig. 1 illustrates comparisons of the bulk densities of various proppant/sand control materials with samples of a selected porous ceramic material (from Carbo Ceramics, Inc).

In the examples, “CarboLite” is a commercial plug available from Carbo Ceramics, Inc. “Clean” is untreated porous ceramic material from Carbo Ceramics, Inc., “2/2” is porous ceramic material from Carbo Ceramics, Inc. treated with 2 wt. -% of particle epoxy inner coating/penetrating material (epoxy is a reaction product of epichlorohydrin and bis-phenol A) and with 2% by weight of particle phenol formaldehyde resin outer coating material, "6%" is porous ceramic material from Carbo Ceramics, Inc. treated with 6% by weight of particle coating/penetrating material (epoxy is the reaction product of epichlorohydrin and bis-phenol A), "8% P-A" is porous ceramic material from Carbo Ceramics, Inc. treated with 8% by weight of particle phenol formaldehyde resin ( sample A), "8% P-B" is porous ceramic material from Carbo Ceramics, Inc. treated with 8% by weight of particulate phenol formaldehyde resin (sample B), and "10% P" is porous ceramic material from Carbo Ceramics, Inc. treated with 10% by weight of particle kel phenol formaldehyde resin.

Data are presented for both the untreated particle of porous material, and for the particle of porous material treated with different types and concentrations of selected penetrating materials. As can be seen, the bulk apparent density of the resulting particles varies with varying degrees of infiltration or penetration of the penetrating material into the porous ceramic particle. The samples designated as 2/2 and 8% P-B can be characterized from SEM thin film analysis as having limited penetration towards the particle core, effective encapsulation of the air in the particle core porosity, but significant improvement in particle strength as illustrated by the conductivity tests.

Figures 2 and 5 illustrate the permeability against closure load for coated and uncoated ceramic ULW particles. As shown, resin coating and impregnation of ULW particles provides significant strength over the closure area and, in particular, improves the performance of the material at low to medium area. The data represent equal pack widths for all proppants with adjustments made for each respective density. Both the coated and uncoated ceramic ULW were tested at 33.2 kg/m<2>. Each of these tests had nearly identical width measurements for easy comparison.

Example 2

The porous particulate material used was from "Carbo Ceramics" and had a size of around 20/40 mesh. The particulate material was treated with various penetrating/coating materials corresponding to the same epoxy or phenol formaldehyde materials used above. The treated particulate matter was tested alone, with no other particulate matter mixed in. Comparison materials include Jordan sand, "Econoprop" proppant from Carbo Ceramics, "Econoflex" (coated Econoprop proppant), Hickory sand (Brady sand), "PR6000", 2% coated Ottawa sand from BORDEN and "Carbolite" proppant from Carbo Ceramics.

Conductivity tests were conducted according to API RP 61 (1st revision, October 1, 1989) using an API conductivity cell with Ohio sandstone "waffle" side liners. Each particulate material sample was loaded into the cell and closure load applied to the particulate material using a "DAKE" hydraulic press equipped with a "ROSEMOUNT" differential transducer (#3051C) and controlled by a "CAMILE" controller. In the testing, a "CONSTAMETRIC 3200" pump with a constant efficiency was also used, which was used to flow deionized water through each particulate sample.

Table 2 shows the proppant package permeability and conductivity data generated for this example.

Data are presented graphically in figures 2-6.

Conductivity is a function of width times permeability. Advantageously, as shown herein in one embodiment, a selected porous particulate material may be treated with a selected coating and/or penetrating material to produce a particulate sample of relatively light weight as at the same kg/m<2>(lb/sq ft ) loading as a conventional sand will occupy a larger width. Even if the pack permeability is the same, the conductivity, and consequently the proppant pack productivity, will be higher. Therefore, as presented by the conductivity data, the advantage of the combination of increased width and the improved permeability can be obtained. Further, as shown herein, in one embodiment, a selected porous particulate material may be treated with a selected coating and/or penetrating material such that particle strength is maintained to as high an envelope (or closure) load as possible, which is reflected more directly of the permeability data. Therefore, a certain amount of breakdown conductivity at a given load/temp condition can be maintained without increasing cost, and/or by offsetting any cost increase with improved value. Even in the case of increased cost of particulate material, substantially less particulate material can be used to achieve substantially equivalent conductivity due to the smaller mass/smaller unit volume.

Example 3:

By using the selected treated material according to the examples above, particles can be produced which are capable of use, such as having sufficient compressive strength for use or not crushing under conditions of 13.8 MPa closing load or greater, alternatively 17.2 MPa closing load or greater, alternatively 20.7 MPa closing stress or greater, alternatively up to at least about 41.4 MPa closing stress, alternatively up to at least about 48.3 MPa closing stress, and alternatively at least about 55.2 MPa closing stress, i.e. approximately as resistant to crushing as commercial ceramic stoppers which are heavier (eg commercial ceramic stopper (CarboLite) is about 40% heavier). In another embodiment, particles can be prepared that are capable of use, (eg, have sufficient compressive strength for use or do not crush) under conditions of from about 13.8 MPa to about 55.2 MPa closing stress, alternatively from about 17 .2 MPa closing load to about 55.2 MPa closing load, alternatively from about 20.7 MPa closing load to about 55.2 MPa closing load. However, it will be understood that particles can be produced which are capable of use both at higher closing loads than 55.2 MPa and at lower closing loads than about 13.8 MPa.

Figures 8-15 are cross-sectional and surface SEM photographs of various treated and untreated samples of porous ceramic materials from CARBO CERAMICS. When indicated as "epoxy" or as "resin", both the specific coating/penetrating material is the same epoxy or phenol formaldehyde resin used and identified in Example 1.

Fig. 8 shows particles treated with around 10% by weight of particle resin. Fig. 9 shows particles treated first with 2% by weight epoxy and secondly with 2% by weight resin. Fig.10 shows untreated particles. Fig.11 shows particles treated first with 2% by weight epoxy and secondly with 2% by weight resin. Fig.12 shows the surface of an untreated particle. Fig.13 shows untreated particles. Fig.14 shows particles treated with 8% by weight epoxy. Fig.15 shows particles treated with 6% by weight epoxy.

Example 4:

In this example, a selected mixture of three different apparent specific gravity well treatment particulate materials was evaluated for use in a water fracture treatment of a "tight" gas well based on a Canyon Sand gas well. The three particulate materials with different apparent specific gravity particles were chosen to represent, for example, a selected mixture of the following different types of well treatment particulate materials:

I. 20/40 mesh Ottawa sand having the following properties: apparent specific gravity of 2.65; final velocity (fall velocity), Vt= 5.4 m/min at Reynolds number (Nre) = /- 500 (Typical for water "fracs")

II. 20/40 mesh porous ceramic particles coated with 2% resin (described elsewhere herein) having the following properties: apparent specific gravity of 1.70; Vt= 2.9 m/min at Nre = /- 500 (Typical for water fracs)

III. 20/40 mesh ground or crushed walnut shell coated with a protective or hardening coating (e.g. "LiteProp" from BJ Services described in U.S. Patent No.

6,364,018 and US Patent Application Serial No. 09/579,146, both of which are incorporated herein by reference) having the following characteristics: apparent specific gravity of 1.20; Vt= 1.2 m/min at Nre = /- 500 (Typical for water fracs) As can be seen from the data above, particulate material III weighs about half as much as particulate material I, but settles at a rate less than about 1/4 as fast.

A particulate material for well treatment that includes a selected mixture of roughly equal amounts of the above types of particulate materials (ie, about 1/3 by weight of the above particulate material I of the total weight of the mixture, about 1/3 by weight of the above-mentioned particulate material II of the total weight of the mixture, and about 1/3 by weight of the above-mentioned particulate material III of the total weight of the mixture) was modeled for use in a water fracture treatment of a "tight" gas well using a hydraulic fracture simulation program. Fig.16 illustrates proppant distribution in the resulting simulated hydraulic fracture formed downhole. For comparison purposes, a well treatment particulate material that includes only particulate material I (Ottawa sand) was modeled for use in a water fracturing treatment of the same "tight" gas well that was modeled in a similar manner using the same pumping schedule (but in this case using 61.235 kg Ottawa sand). Fig.17 illustrates proppant distribution in the resulting simulated hydraulic fracture formed downhole.

As can be seen from a comparison of the resulting plugged profiles of Figures 16 and 17, the well treatment particulate materials that include only particulate material I (Ottawa sand) resulted in a proppant distribution that plugged the lower half of the pay out to about 1000 ' (see Fig.18), while the particulate material for well treatment which includes a selected mixture of roughly equal amounts of particulate material I, II and III resulted in a synergistic plugging agent distribution that plugged the entire "the pay" out to almost 2000' ( see Fig.16), or approximately four times the plugged fracture surface area.

Example 5:

The proppant distributions according to Fig.16 and Fig.17 were then used as input values in a reservoir production simulator ("M-Prod") and gas production was separately simulated for each proppant distribution. An assumption was made that the effective conductivity of the proppant distribution according to Fig.16 (ie roughly equal amounts of particulate material I, II and III) would have only 1/10 of the effective conductivity of the proppant distribution according to Fig.17 (i.e. only particulate matter I). The proppant distribution according to Fig.17 (i.e. only particulate material I) produced at an initial potential of 20 million m<3>/day (707 MCFD) with a cumulative production of 595 MMCF during ten years, while the proppant distribution according to Fig.16 (ie roughly equal amounts of particulate matter I, II and III) produced at an initial potential of 26 million m<3>/day (920 mcf/day ("MCFD")) with a cumulative production of 1312 MMCF during of ten years. Therefore, the proppant distribution according to Fig. 16 (i.e. roughly equal amounts of particulate material I, II and III) resulted in the production of twice the reserves from the same well as the proppant distribution according to Fig. 17 (i.e. only particulate material I), despite of it having only 1/10 of the assumed conductivity. This shows how the presented mixture of different types of particulate materials for well treatment can be advantageously used to achieve increased production rates and reserves from relatively tight gas formations by increasing plugged fracture lengths, even with reduced effective conductivities.

Although this example illustrates the use of a selected mixture of different types and amounts of particulate materials for well treatment in a tight gas well, it will be understood that mixtures of these and other types of well treatment mixtures may be selected and used for other types of wells, including wells that are productive for fluids as well as gas, and wells that have relatively higher formation permeability values. Furthermore, it will be understood that advantages of the disclosed method can be realized by using mixtures other than three different types of particulate materials for well treatment, for example, by using two different types of particulate materials for well treatment or more than three different types of particulate materials for well treatment ( eg as many as four, five, six, seven, eight, nine and more different types of well treatment particulate materials) that have varying characteristics.

Example 6:

ULW-1.75 corresponds to the 2/2 discussed above in Example 1 and can be characterized as a porous ceramic particle with the roundness and spherical shape common to ceramic proppants. The porosity is on average 50%, which gives a bulk density of 1.10 to 1.15 g/cm<3>. Medium size 20/40 particles of the ULW-1.75 and the Ottawa sand were used. The 20/40 Ottawa sand has an average bulk density of 1.62 g/cm with a specific gravity of 2.65. The ULW-1.75 has a bulk density of 1.05 to 1.10.

Static particle settling evaluations were conducted in fresh water to determine the differences in settling velocity between the conventional proppant and the ULW particles. Medium-sized 20/40 particles of each propellant were used for the evaluations. Stokes' law calculations which give the fall speed in m/min (ft/minute) are presented in Table 3 and were calculated as:

where velocity is in ft/min, diameter d is the average particle diameter and μ is fluid viscosity in cps.

Large-scale slot flow tests were conducted to characterize the dynamic settling rates of the ultra-lightweight proppant. Proppant transport characteristics were studied at ambient temperature through a glass slit. The transparent slit is a 56 cm (22-in.) high, 4.88 m (16 ft) long, and 1.27 cm (0.5 in.) wide parallel plate device. 3785 liters (One thousand gallons) of test fluid was prepared and the fluid rheology was measured using a standard Fann 35 viscometer. The fluid was then transferred to a ribbon mixer of 757 liters (200 gallons) capacity and pumped through the test loop to fill the transparent slot model. Once the slot was filled with the test fluid, proppant was added to the mixer to produce a slurry of the desired concentration. The "slick water" fluid used in the experiment exhibited an average viscosity of 5 to 7 cps throughout the entire series of experiments.

The shear rate in the slot is given by the equation:

where q is the velocity in gallons per minute (1 gallon/min = 3.79 l/min), w is the width in inches (1 inch = 2.54 cm), and H is the height in feet (1 foot = 30.48 cm). Fluid velocity through this slot model is given by:

The proppant transport behavior of each test slurry was observed through the slot at different flow rates. During these experiments, the proppant distribution was continuously recorded with video cameras as well as manually by observation. All bed height measurements for this work were taken near the outlet end of the slotted flow cell.

Ottawa sand suspended in "slickwater" was observed to begin settling after entering the slot even at the maximum fluid pumping rate. Within 12 minutes at 341 l/min (90 gpm) (378 sec-1 shear rate), the bed height was 38 cm, 68% of the total height of the 56 cm gap. Table 4 below shows the results in tabular form. Only at shear rates above 1000 sec-1 was the dynamic Ottawa sand proppant fall rate attenuated in the slickwater test fluid. As flow rates were reduced to 114 l/min (30 gpm), the Ottawa proppant bed reached its maximum bed height of 49.5 cm or 91.25% of the gap height. Above the proppant layer, shear rates reached 1.414 sec-1, at which point further sedimentation did not occur. As the rate increased from 114 l/min to 151 l/min (30 to 40 gpm) (1.919 sec-1), the bed height actually decreased.

The ULW 1.75 test was initiated at 341 l/min (90 gpm). ULW 1.75 was observed to be subject to some sedimentation at 341 l/min (90 gpm), while the bed height increases to 10 cm. The fluid rate was reduced to 303 l/min (80 gpm) and the bed height increased to 15.2 cm. As the rate was reduced gradually down to 113.6 l/min (30 gpm), the ULW-1.75 layer was observed to grow at a reduced rate to 30.5 cm. The rate was further reduced to 18.9 l/min (5 gpm) and the bed height increased to 48.3 cm or 86% of the total gap height. As observed in previous experiments, as the velocity is gradually increased, the bed height decreases due to erosion and fluidization of the bed. The ULW-1.75 results are presented in table 5.

Both tested materials sediment progressively more as the speed decreases. Because of the reduced density, the ULW is more easily brought back into flow as the velocity is increased. The reduced density materials require less shear increase to fluidize the proppant layer. Ottawa sand was observed to require over 1,500 sec-1 to transport the proppant in slickwater and about 2,000 sec-1 shear to begin fluidizing the proppant bed. The ULW-1.75 transporting at shear rates of 500 sec-1 and fluid shear rates of 800 sec-1 was required to fluidize the proppant bed.

The data clearly show the advantage of lower density particles over dynamic sand fall velocities. Heavier proppants require significant fluid viscosity, increased fluid density and/or high slurry velocity for efficient proppant transport.

Claims (12)

Patent claims 1. Plugging agent or sand control particulate material of a selectively configured porous particulate material, wherein the selectively configured porous particulate material comprises a porous particulate material, the porous particulate material is a ceramic material, polyolefin, styrene-divinylbenzene copolymer or polyalkyl acrylate esters, and is treated with a non-porous penetrating, coating and/or glazing material such that one of the following conditions applies: (i) the porosity and permeability of the selectively configured porous particulate material is such that a fluid can be drawn at least partially into its porous matrix by capillary action; or (ii) the apparent specific gravity or apparent density of the selectively configured porous particulate material is less than the apparent specific gravity or apparent density of the porous particulate material; or (iii) the penetrating, coating and/or glazing material is capable of encapsulating air or a light weight fluid within the porous particulate material; and further where the porous particulate material exhibits inherent or induced permeability. 2. Plugging agent or sand control particulate material according to claim 1, wherein the porous particulate material is a particulate material of relatively light weight and/or substantially neutral liquid particulate material. 3. Plugging agent or sand control particulate material according to claim 2, wherein the porous particulate material is suspended in a fluid in which the density of the fluid and the porous particulate material are of close or substantially equal density. 4. Plugging agent or sand control particulate material according to any one of claims 1 to 3, wherein the porous particulate material of the selectively configured porous particulate material is coated or penetrated with a liquid or curable resin, plastic material, cement, sealant or binder, such as phenol , phenol formaldehyde, melamine formaldehyde, urethane, epoxy resin, polyethylene, ethyl carbamate-based resin or polystyrene or a combination thereof. 5. A proppant or sand control particulate material according to any one of claims 1 to 4, wherein the thickness of the coated layer of the selectively configured porous particulate material is from 1 to 5 microns. 6. A plugging agent or sand control particulate material according to any one of claims 1 to 5, wherein the coating and/or penetrating material is a liquid having an apparent specific gravity less than the apparent specific gravity of the porous particulate material. 7. The plugging agent or sand control particulate material of any one of claims 1 to 6, wherein the porous particulate material has a maximum length-based aspect ratio equal to or less than about 5. 8. A proppant or sand control particulate material according to any one of claims 1 to 7, wherein the apparent density of the selectively configured porous particulate material is from about 1.1 g/cm<3> to about 2.6 g/cm<3>. 9. The proppant or sand control particulate material of claim 8, wherein the apparent bulk density of the selectively configured porous particulate material is from about 1.03 g/cm<3> to about 1.4 g/cm<3>. 10. A plugging agent or sand control particulate material according to any one of claims 1 to 9, wherein a coating layer or penetrating material is present in the selectively configured porous particulate material in an amount of from about 0.5 to about 10% by weight of the total weight . 11. A plugging agent or sand control particulate material according to any one of claims 1 to 10, wherein the size of the selectively configured porous particulate material is between from about 200 mesh to about 8 mesh. 12. A method of treating a well penetrating an underground formation, comprising introducing the plugging agent or sand control particulate material according to any one of claims 1 to 11 into the well.