WO2004022914A1 - Procede de traitement de formations souterraines a l'aide de materiaux particulaires de ceramique poreuse - Google Patents

Procede de traitement de formations souterraines a l'aide de materiaux particulaires de ceramique poreuse Download PDF

Info

Publication number
WO2004022914A1
WO2004022914A1 PCT/US2003/027611 US0327611W WO2004022914A1 WO 2004022914 A1 WO2004022914 A1 WO 2004022914A1 US 0327611 W US0327611 W US 0327611W WO 2004022914 A1 WO2004022914 A1 WO 2004022914A1
Authority
WO
WIPO (PCT)
Prior art keywords
particulate material
porous particulate
porous
selectively configured
well
Prior art date
Application number
PCT/US2003/027611
Other languages
English (en)
Inventor
Christopher John Stephenson
Allan Ray Rickards
Harold Dean Brannon
Satyanarayana D.V. Gupta
Original Assignee
Bj Services Company
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Bj Services Company filed Critical Bj Services Company
Priority to BR0314336-8A priority Critical patent/BR0314336A/pt
Priority to CA2497276A priority patent/CA2497276C/fr
Priority to BRPI0314336-8A priority patent/BRPI0314336B1/pt
Priority to AU2003270298A priority patent/AU2003270298A1/en
Priority to GB0504305A priority patent/GB2408279B/en
Publication of WO2004022914A1 publication Critical patent/WO2004022914A1/fr
Priority to GBGB0504410.2A priority patent/GB0504410D0/en
Priority to NO20051054A priority patent/NO342605B1/no
Priority to DK200500311A priority patent/DK200500311A/da

Links

Classifications

    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/80—Compositions for reinforcing fractures, e.g. compositions of proppants used to keep the fractures open
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/80—Compositions for reinforcing fractures, e.g. compositions of proppants used to keep the fractures open
    • C09K8/805—Coated proppants
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/25—Methods for stimulating production
    • E21B43/26—Methods for stimulating production by forming crevices or fractures
    • E21B43/267—Methods for stimulating production by forming crevices or fractures reinforcing fractures by propping

Definitions

  • This invention relates generally to methods and compositions useful for subterranean formation treatments, such as hydraulic fracturing treatments and sand control.
  • Hydraulic fracturing is a common stimulation technique used to enhance production of fluids from subterranean formations.
  • 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.
  • proppant material is deposited in a fracture, where it remains after the treatment is completed. After deposition, the proppant material serves to hold the fracture open, thereby enhancing the ability of fluids to migrate from the formation to the well bore through the fracture. Because fractured well productivity depends on the ability of a fracture to conduct fluids from a formation to a wellbore, fracture conductivity is an important parameter in determining the degree of success of a hydraulic fracturing treatment.
  • Hydraulic fracturing treatments commonly employ proppant materials that are placed downhole with a gelled carrier fluid such as aqueous-based fluid such as gelled brine.
  • Gelling agents for proppant carrier fluids may provide a source of proppant pack and/or formation damage, and settling of proppant may interfere with proper placement downhole. Formation damage may also be caused by gelled carrier fluids used to place particulates downhole for purposes such as for sand control, such as gravel packs, frac packs, and similar materials.
  • Formulation of gelled carrier fluids usually requires equipment and mixing steps designed for this purpose.
  • Hydraulic fracturing treatments may also employ proppant materials that are placed downhole with non-aqueous-based fluids, such as liquid CO 2 and liquid CO 2 /N 2 systems. Proppants commonly employed with such non-aqueous-based fluids tend to settle in the system.
  • proppants including sand, glass beads, walnut hulls, and metal shot.
  • Commonly used proppants today include various sands, resin-coated sands, intermediate strength ceramics, and sintered bauxite; each employed for their ability to cost effectively withstand the respective reservoir closure stress environment.
  • the respective particle densities ranging from 2.65 g/cc for sands to 3.4 g/cc for the sintered bauxite.
  • increasing particle density leads directly to increasing degree of difficulty with proppant transport and a reduced propped fracture volume for equal amounts of the respective proppant, reducing fracture conductivity.
  • Previous efforts undertaken to employ lower density materials as proppant have generally resulted in failure due to insufficient strength to maintain fracture conductivity at even the lowest of closure stresses (1,000 psi).
  • deformable particles have been developed. Such deformable particles for sand flowback control are significantly lighter than conventional proppants, and exhibit high compressive strength
  • deformable materials include polystyrene divinylbenzene (PSDNB) deformable beads. Such beads, however, have not been entirely successful primarily due to limitations of the base material. While PSDNB beads offered excellent deformability and elasticity, they lacked the structural integrity to withstand high closure stresses and temperatures.
  • the first successful path to generate functional deformable particles was the usage of modified ground walnut hulls.
  • Walnut hulls in their natural state have been used as proppants, fluid loss agents and lost circulation materials for many years with greater or lesser degrees of success in each respective task.
  • proppant natural walnut hulls have very limited applicability, because they deform fairly readily upon application of closure stress. This deformation drastically reduces conductivity and limits utility of the natural material to relatively low-closure environments.
  • Walnut hull based ultra-lightweight (UCW) proppants may be manufactured in a two- step process by using closely sized walnut particles (i.e. 20/30 US mesh), and impregnating them with strong epoxy or other resins. These impregnated walnut hull particles are then coated with phenolic or other resins in a fashion similar to most resin coated proppants (RCP).
  • Such walnut hull based ULW proppants have a bulk density of 0.85 grams/cc and withstand up to 6,000 psi (41.4 MPa) closure stress at 175°F (79°C).
  • the stronger a proppant the greater the density. As density increases, so too does the difficulty of placing that particle evenly throughout the created fracture geometry.
  • the invention relates to methods for treating subterranean formations by treating a well with a composition containing porous ceramic or organic polymeric particulates.
  • the compositions introduced into the well are particularly suitable in hydraulic fracturing of a well as well as sand consolidation methods such as gravel packing and frac packing.
  • the porous particulate material may be a selectively configured porous particulate material, as defined herein.
  • the porous particulate material may be a non-selectively configured porous particulate material, as defined herein.
  • the porous particulate material may be selectively configured with a non-porous penetrating material, coating layer or glazing layer.
  • the porous particulate material is a selectively configured porous particulate material wherein either (a.) the apparent density or apparent specific gravity of the selectively configured porous particulate material is less than the apparent density or apparent specific gravity of the porous particulate material; (b.) the permeability of the selectively configured porous particulate material is less than the permeability of the porous particulate material; or (c.) the porosity of the selectively configured porous particulate material is less than the porosity of the porous particulate material.
  • the penetrating material and/or coating layer and/or glazing layer of the selectively configured porous particulate material is capable of trapping or encapsulating a fluid having an apparent specific gravity less than the apparent specific gravity of the carrier fluid.
  • the coating layer and/or penetrating material and/or glazing material may be a liquid having an apparent specific gravity less than the apparent specific gravity of the matrix of the porous particulate material.
  • the strength of the selectively configured porous particulate material is typically greater than the strength of the porous particulate material per se. Further, the selectively configured porous material exhibits crush resistance under conditions as high as 10,000 psi closure stress, API RP 56 or API RP 60.
  • the porous particulate composition is a suspension of porous particulates in a carrier fluid.
  • the suspension preferably forms a pack of particulate material that is permeable to fluids produced from the wellbore and substantially prevents or reduces production of formation materials from the formation into the wellbore.
  • the porous particulate material may exhibit a porosity and permeability such that a fluid may be drawn at least partially into the porous matrix by capillary action.
  • the porous particulate material has a porosity and permeability such that a penetrating material may be drawn at least partially into the porous matrix of the porous particulate material using a vacuum and/or may be forced at least partially into the porous matrix under pressure.
  • the selectively configured porous particulate material may consist of a multitude of coated particulates bonded together.
  • the porous material is a cluster of particulates coated with a coating or penetrating layer or glazing layer.
  • Suitable coating layers or penetrating materials include liquid and/or curable resins, plastics, cements, sealants, or binders such as a phenol, phenol formaldehyde, melamine formaldehyde, urethane, epoxy resin, nylon, polyethylene, polystyrene or a combination thereof.
  • the coating layer or penetrating material is an ethyl carbamate-based resin.
  • the selectively configured porous particulate materials are derived from lightweight and/or substantially neutrally buoyant particles.
  • the application of selected porous material particulates and relatively lightweight and/or substantially neutrally buoyant particulate material as a fracture proppant particulate advantageously provides for substantially improved overall system performance in hydraulic fracturing applications, or in other well treating applications such as sand control.
  • the porous particulate material-containing compositions used in the invention may further contain a carrier fluid.
  • the carrier fluid may be a completion or workover brine, salt water, fresh water, a liquid hydrocarbon, or a gas such as nitrogen or carbon dioxide.
  • the porous particulate material-containing compositions may further contain a gelling agent, crosslinking agent, gel breaker, surfactant, foaming agent, demulsifier, buffer, clay stabilizer, acid or a mixture thereof.
  • FIG. 1 is a graph depicting bulk apparent density comparison of the data of Example 1.
  • FIG. 2 is a graph depicting permeability versus closure stress data of Example 2.
  • FIG. 3 is a graph depicting conductivity versus closure stress data of Example 2.
  • FIG. 4 is a graph depicting conductivity versus closure stress data of Example 2.
  • FIG. 5 is a graph depicting permeability versus closure stress data of Example 2.
  • FIG. 6 is a graph depicting conductivity comparison data of Example 2.
  • FIG. 7 is a graph depicting permeability comparison data of Example 2.
  • FIG. 8 is a SEM photograph of a porous material particle of Example 3.
  • FIG. 9 is a SEM photograph of a porous material particle of Example 3.
  • FIG. 10 is a SEM photograph of a porous material particle of Example 3.
  • FIG. 11 is a SEM photograph of a porous material particle of Example 3.
  • FIG. 12 is a SEM photograph of a porous material particle of Example 3.
  • FIG. 13 is a SEM photograph of a porous material particle of Example 3.
  • FIG. 14 is a SEM photograph of a porous material particle of Example 3.
  • FIG. 15 is a SEM photograph of a porous material particle of Example 3.
  • FIG. 16 illustrates proppant distribution for a selected combination of well treatment particulates according to one embodiment of the disclosed compositions and methods described in Example 4.
  • FIG. 17 illustrates comparative proppant distribution data of Example 4 for Ottawa sand alone.
  • porous particulate material shall refer to porous ceramic or porous organic polymeric materials.
  • types of materials suitable for use as porous material particulates include particulates having a porous matrix;
  • porous particulate material shall refer to any porous particulate material, natural or non-natural, which has been chemically treated, such as treatment with a coating material; treatment with a penetrating material; or modified by glazing.
  • the term shall include, but not be limited to, those porous particulate materials which have been altered to achieve desired physical properties, such as particle characteristics, desired strength and/or apparent density in order to fit particular downhole conditions for well treating such as hydraulic 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, like pumice, as well as perlite and other porous "lavas” like porous (vesicular) Hawaiian Basalt, porous Nirginia Diabase, and Utah Rhyolite.
  • inorganic ceramic materials such as alumina, magnetic glass, titanium oxide, zirconium oxide, and silicon carbide may also be used.
  • the term shall refer to a synthetic porous particulate material which has not been chemically treated and which imparts desired physical properties, such as particle characteristics, desired strength and/or apparent density in order to fit particular downhole conditions for well treating;
  • “relatively lightweight” shall refer to a porous particulate material that has a apparent density (API RP 60) that is substantially less than a conventional particulate material employed in hydraulic fracturing or sand control operations, such as sand having an apparent specific gravity (API RP 60) of 2.65 and bauxite having an apparent specific gravity of 3.55.
  • the apparent specific gravity of a relatively lightweight material is less than about 2.4.
  • substantially neutrally buoyant shall refer to a porous particulate material that has an apparent density sufficiently close to the apparent density of a selected ungelled or weakly gelled carrier fluid, such as an ungelled or weakly gelled completion brine, other aqueous-based fluid, slick water, or other suitable fluid, which allows pumping and satisfactory placement of the proppant/particulate using the selected ungelled or weakly gelled carrier fluid.
  • a selected ungelled or weakly gelled carrier fluid such as an ungelled or weakly gelled completion brine, other aqueous-based fluid, slick water, or other suitable fluid, which allows pumping and satisfactory placement of the proppant/particulate using the selected ungelled or weakly gelled carrier fluid.
  • a "weakly gelled carrier fluid” is a carrier fluid having a viscosifier or friction reducer to achieve friction reduction when pumped down hole, for example when pumped down tubing, work string, casing, coiled tubing, drill pipe, or similar location, wherein the polymer or viscosifier concentration from about 0 pounds of polymer per thousand gallons of base fluid to about 10 pounds of polymer per thousand gallons of base fluid, and/or the viscosity from about 1 to about 10 centipoises.
  • An "ungelled carrier fluid” is a carrier fluid having no polymer or viscosifier. The ungelled carrier fluid may contain a friction reducer known in the art.
  • the selectively configured porous particulate materials as well as non-selectively configured porous particulate materials are particularly effective in hydraulic fracturing as well as sand control fluids such as water, salt brine, slickwater such as slick water fracture treatments at relatively low concentrations to achieve partial monolayer fractures, low concentration polymer gel fluids (linear or crosslinked), foams (with gas) fluid, liquid gas such as liquid carbon dioxide fracture treatments for deeper proppant penetration, treatments for water sensitive zones, and treatments for gas storage wells.
  • sand control fluids such as water, salt brine, slickwater such as slick water fracture treatments at relatively low concentrations to achieve partial monolayer fractures, low concentration polymer gel fluids (linear or crosslinked), foams (with gas) fluid, liquid gas such as liquid carbon dioxide fracture treatments for deeper proppant penetration, treatments for water sensitive zones, and treatments for gas storage wells.
  • the selectively configured porous material particles or non-selectively configured porous material particles may be mixed and pumped during any desired portion/s of a well treatment such as hydraulic fracturing treatment or sand control treatment and may be mixed in any desired concentration with a carrier fluid.
  • a carrier fluid suitable for transporting the selectively configured porous particulate material or non-selectively configured porous particulate material particles into a well and/or subterranean formation fracture in communication therewith may be employed including, but not limited to, carrier fluids comprising salt water, fresh water, potassium chloride solution, a saturated sodium chloride solution, liquid hydrocarbons, and/or nitrogen or other gases may be employed.
  • Suitable carrier fluids include or may be used in combination with fluids have gelling agents, cross-linking agents, gel breakers, surfactants, foaming agents, demulsifiers, buffers, clay stabilizers, acids, or mixtures thereof.
  • the selectively configured porous particulate material or non-selectively configured porous particulate material particles may be injected into a subterranean formation in conjunction with a hydraulic fracturing treatment or other treatment at pressures sufficiently high enough to cause the formation or enlargement of fractures.
  • Such other treatments may be near wellbore in nature (affecting near wellbore regions) and may be directed toward improving wellbore productivity and/or controlling the production of fracture proppant or formation sand.
  • Such particles may be employed alone as a fracture proppant/sand control particulate, or in mixtures in amounts and with types of fracture proppant/sand control materials, such as conventional fracture or sand control particulate. Further information on hydraulic fracturing methods and materials for use therein may be found in United States Patent No. 6,059,034 and in United States Patent No. 6,330,916, which are incorporated herein by reference.
  • a well treatment fluid may include a suspension of proppant or sand control particulate that is made up completely of relatively lightweight selected porous material particles that have been selectively configured, such as glazed and/or treated with one or more selected coating and/or penetrating materials.
  • a well treatment fluid may include a suspension that contains a mixture of conventional fracture proppant or sand control particulates such as sand with relatively lightweight selected porous material particles that have been selectively configured such as glazed and/or treated with one or more selected coating and/or penetrating materials.
  • a gravel pack operation may be carried out on a wellbore that penetrates a subterranean formation to prevent or substantially reduce the production of formation particles into the wellbore from the formation during production of formation fluids.
  • the subterranean formation may be completed so as to be in communication with the interior of the wellbore by any suitable method known in the art, for example by perforations in a cased wellbore, and/or by an open hole section.
  • a screen assembly such as is known in the art may be placed or otherwise disposed within the wellbore so that at least a portion of the screen assembly is disposed adjacent the subterranean formation.
  • a slurry including the selectively configured porous particulate material or non-selectively configured porous particulate material and a carrier fluid may then be introduced into the wellbore and placed adjacent the subterranean formation by circulation or other suitable method so as to form a fluid-permeable pack in an annular area between the exterior of the screen and the interior of the wellbore that is capable of reducing or substantially preventing the passage of formation particles from the subterranean formation into the wellbore during production of fluids from the formation, while at the same time allowing passage of formation fluids from the subterranean formation through the screen into the wellbore.
  • the slurry may contain all or only a portion of selectively configured porous particulate material or the non-selectively configured porous particulate material.
  • the balance of the particulate material of the slurry may be another material, such as a conventional gravel pack particulate.
  • the sand control method may use the selectively configured porous particulate material or non-selectively configured porous particulate material in accordance with any method in which a pack of particulate material is formed within a wellbore that it is permeable to fluids produced from a wellbore, such as oil, gas, or water, but that substantially prevents or reduces production of formation materials, such as formation sand, from the formation into the wellbore.
  • Such methods may or may not employ a gravel pack screen, may be introduced into a wellbore at pressures below, at or above the fracturing pressure of the formation, such as frac pack, and/or may be employed in conjunction with resins such as sand consolidation resins if so desired.
  • the porous particulate material shall include any naturally occurring or manufactured or engineered porous ceramic particulate material that has an inherent and/or induced porosity.
  • a commercially available instrument, ACCUPYC 1330 Automatic Gas Pycnometer (Micromeritics, Norcross, GA), that uses Helium as an inert gas and the manufacturer's recommended procedure can be used to determine the internal porosity of the particulates.
  • the internal porosity is generally from about 10 to 75 volume percent.
  • Such particulate material may also have an inherent or induced permeability, i.e., individual pore spaces within the particle are interconnected so that fluids are capable of at least partially moving through the porous matrix, such as penetrating the porous matrix of the particle, or may have inherent or induced non- permeability, individual pore spaces within the particle are disconnected so that fluids are substantially not capable of moving through the porous matrix, such as not being capable of penetrating the porous matrix of the particle.
  • the degree of desired porosity interconnection may be selected and engineered into the non-selectively configured porous particulate material.
  • porous particles may be selected to have a size and shape in accordance with typical fracturing proppant particle specifications (i.e., having a uniform shape and size distribution), although such uniformity of shape and size is not necessary.
  • the apparent specific gravity of 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.
  • the particles may be selected based on porosity and/or permeability characteristics so that they have desired lightweight characteristics, such as when suspended in a selected carrier fluid for a well treatment.
  • desired lightweight characteristics such as when suspended in a selected carrier fluid for a well treatment.
  • the inherent and/or induced porosity of a porous material particle may be selected so as to help provide the desired balance between apparent density and strength.
  • Optional materials may be employed along with a glazing, penetrating and/or coating material to control penetration, such as enhancing or impairing penetration.
  • an cationic clay stabilizer such as CLAY MASTER 5C from BJ Services, may be first applied to the exterior surface of a porous ceramic material to inhibit penetration by coating/penetrating material, such as epoxy or resin described elsewhere herein.
  • the porous particulate material is a relatively lightweight or substantially neutral buoyant particulate material.
  • a relatively lightweight particulate material may be easier to place within a targeted zone due to lessened settling constraints, and a reduced mass of such relatively lightweight particulate material is generally required to fill an equivalent volume than is required with conventional sand control particulates, used, for example, for gravel packing purposes.
  • Relatively lightweight and/or substantially neutrally buoyant fracture proppant/particulate material used in hydraulic fracturing/sand control treatment such as porous ceramic particles having untreated bulk apparent density of 1.16 and untreated porosity of about 59.3%, may be employed.
  • the disclosed porous material particulates may be employed as relatively lightweight particulate/proppant material that may be introduced or pumped into a well as neutrally buoyant particles in, for example, a saturated sodium chloride solution carrier fluid or a carrier fluid that is any other completion or workover brine known in the art, thus eliminating the need for damaging polymer or fluid loss material.
  • a saturated sodium chloride solution carrier fluid or a carrier fluid that is any other completion or workover brine known in the art, thus eliminating the need for damaging polymer or fluid loss material.
  • such a material may be employed as proppant/sand control particulate material at temperatures up to about 700°F, and closure stresses up to about 8000 psi.
  • the disclosed porous material particulates are employed as relatively lightweight and/or substantially neutrally buoyant particulate/proppant materials, they may be employed with carrier fluids that are gelled, non-gelled, or that have a reduced or lighter gelling requirement as compared to carrier fluids employed with conventional fracture treatment/sand control methods.
  • mixing equipment need only include such equipment that is capable of (a) mixing the brine (dissolving soluble salts), and (b) homogeneously dispersing in the substantially neutrally buoyant particulate material.
  • a substantially neutrally buoyant particulate/proppant material may be advantageously pre-suspended and stored in a storage fluid, such as brine of near or substantially equal density, and then pumped or placed downhole as is, or diluted on the fly.
  • a storage fluid such as brine of near or substantially equal density
  • 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 United States Patent No. 5,188,175 which is incorporated herein by reference.
  • porous ceramic particles such as those particles available from Carbo Ceramics Inc. as "Econoprop", and those fired kaolinitic described in United States Patent No. 5,188,175 which is incorporated herein by 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 may be employed.
  • Such particles may be characterized as having a ratio of silicon dioxide to alumina content of from about 1.39 to about 2.41, and a apparent specific gravity of between about 2.20 and about 2.60 or between about 2.20 and about 2.70.
  • porous ceramic particles may be selectively manufactured 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, which are each incorporated herein by reference, such as by inclusion of selected process steps in the initial material manufacturing process to result in a material that possesses desired characteristics of porosity, permeability, apparent density or apparent specific gravity, combinations thereof.
  • raw materials may be fired at relatively low temperature of about 1235°F or about 1300°F
  • about 20/40 mesh size porous material fired kaolinitic particles from Carbo Ceramics Inc. may be selected for use in the disclosed method. These particles have the following internal characteristics: bulk apparent density about 1.16, internal porosity about 59.3%. These particles may be treated with a variety of penetrating/coating materials in an amount of from about 0.5 to about 10% by total weight of particle. Such coated particles may be manufactured and/or supplied, for example, by Fritz Industries of Mesquite, Texas.
  • size of such a material may be selected to range from about 200 mesh to about 8 mesh.
  • the particles may be selected based on porosity and/or permeability characteristics so that they have desired lightweight characteristics, such as when suspended in a selected carrier fluid for a well treatment.
  • desired lightweight characteristics such as when suspended in a selected carrier fluid for a well treatment.
  • the inherent and/or induced porosity of a porous material particle may be selected so as to help provide the desired balance between apparent density and strength.
  • Optional materials may be employed along with a glazing, penetrating and/or coating material to control penetration such as enhance or impair penetration.
  • an cationic clay stabilizer such as CLAY MASTER 5C from BJ Services, may be first applied to the exterior surface of a porous ceramic material to inhibit penetration by coating/penetrating material, such as epoxy or resin described elsewhere herein.
  • the porous particulate material is chemically treated in order to impart desired physical properties, such as porosity, permeability, apparent density or apparent specific gravity, or combinations thereof to the particulate materials.
  • desired physical properties are distinct from the physical properties of the porous particulate materials prior to treatment.
  • 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 renders such desired characteristics.
  • the non-selectively configured particulate material is selected based on desired physical properties, such as porosity, permeability, apparent density, particle size, chemical resistance or combinations thereof.
  • the selectively configured porous particulate material as well as non-selectively configured porous particulate material exhibit crush resistance under conditions as high as 10,000 psi closure stress, API RP 56 or API RP 60, generally between from about 250 to about 8,000 psi closure stress, in combination with a apparent specific gravity less than or equal to 2.4, to meet the pumping and/or downhole formation conditions of a particular application, such as hydraulic fracturing treatment, sand control treatment.
  • Such desired physical properties may be imparted to a portion or portions of the porous particulate material of the selectively configured porous particulate material or non-selectively configured porous particulate material, such as on the particle surface of the material particulate, at or in the particle surface of the particulate material, in an area near the particle surface of a particulate material, in the interior particle matrix of a particulate material or a portion thereof, combinations thereof, etc.
  • the low apparent specific gravity of the porous particulate material of the selectively configured porous particulate material or non-selectively configured porous particulate material may be taken advantage of to result in a larger fracture or frac pack width for the same loading, such as pound per square foot of proppant, to give much larger total volume and increased width for the same mass.
  • this characteristic allows for smaller loading of proppant material to be pumped while still achieving an equivalent width.
  • selective configuration such as by using glaze-forming, coating and/or penetrating materials, such as those materials described elsewhere herein, may be selectively employed to modify or customize the apparent specific gravity of a selected porous particulate material.
  • Modification of particulate apparent specific gravity to have a greater or lesser apparent specific gravity, may be advantageously employed, for example, to provide proppant or sand control particulates of customized apparent specific gravity for use as a substantially neutrally buoyant particulate with a variety of different weight or apparent specific gravity carrier fluids.
  • the selectively configured porous particulate material has an apparent density from about 1.1 g/cm 3 to about 2.6 g/cm 3 , a bulk apparent density from about 1.03 g/cm 3 to about 1.5 g/cm 3 , and an internal porosity from about 10 to about 75 volume percent.
  • bulk densities may be controlled to be in the range of from about 1.1 g/cm 3 to about 1.5 g/cm 3 , although greater and lesser values are also possible.
  • the selectively configured porous particulate material, as well as the non-selectively configured particulate material is generally between from about 200 mesh to about 8 mesh.
  • the selectively configured porous particulate material may comprise porous particulate material selectively altered by treating with a coating or penetrating material using any suitable wet or dry process.
  • Methods for coating particulates, such as fracture proppant particles, with materials such as resin are known in the art, and such materials are available, for example, from manufacturers listed herein.
  • coating operations may be performed using any suitable methods known in the art.
  • penetration shall further refer to partially or completely impregnated with a penetrating material, by for example, vacuum and/or pressure impregnation.
  • 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.
  • one or more coating and/or penetrating materials may be selected to treat a porous material particulate to meet particular criteria or requirements of given downhole application based on the information and examples disclosed herein, as well as knowledge in the art.
  • porous material particle characteristics 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, may be so selected.
  • the coating or penetrating material is typically non- porous.
  • the porosity and permeability characteristics of the porous particulate material allows the penetrating material to be drawn at least partially into the porous matrix of the porous particulate material by capillary action, for example, in a manner similar to a sponge soaking up water.
  • 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.
  • penetrating materials examples include, but are not limited to, liquid resins, plastics, cements, sealants, binders or any other material suitable for at least partially penetrating the porous matrix of the selected particle to provide desired characteristics of strength/crush resistance, apparent specific gravity, etc. It will be understood that selected combinations of any two or more such penetrating materials may also be employed, either in mixture or in sequential penetrating applications.
  • resins that may be employed as penetrating and/or coating materials include, but are not limited to, resins and/or plastics or any other suitable cement, sealant or binder that once placed at least partially within a selected particle may be crosslinked and/or cured to form a rigid or substantially rigid material within the porous structure of the particle.
  • plastics include, but are not limited to, nylon, polyethylene, styrene, etc. and combinations thereof.
  • Suitable resins include phenol formaldehyde resins, melamine formaldehyde resins, and urethane resins, low volatile urethane resins, such as these and other types of resins available from Borden Chemical Inc., Santrol, Hepworth of England, epoxy resins and mixtures thereof.
  • suitable resins include, but are not limited to, resins from Borden Chemical and identified as 500-series and 700-series resins (e.g., 569C, 794C, etc.). Further specific examples of resins include, but are not limited to, SIGMASET series low temperature curing urethane resins from Borden Chemical, such as SIGMASET, SIGMASET LN, 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, curing characteristics, such as curing time, may be adjusted to fit particular treatment methods and/or final product specifications by, for example, adjusting relative amounts of resin components.
  • suitable resins and coating methods include, but are not limited to, those found in European Patent Application EP 0 771 935 Al; and in U.S. Patents No. 4,869,960; 4,664,819; 4,518,039; 3,929,191; 3,659,651; and 5,422,183, each of the foregoing references being incorporated herein by reference in its entirety.
  • a curable phenolic resin or other suitable curable material may be selected and applied as a coating material so that individual coated particles may be bonded together under downhole temperature, after the resin flows and crosslinks/cures downhole, such as to facilitate proppant pack/sand control particulate consolidation after placement.
  • a cured phenolic type resin coat or other suitable cured material may be selected to contribute additional strength to the particles and/or reduce in situ fines migration once placed in a subterranean formation.
  • the degree of penetration of the coating or penetrating fluid into the porous particulate material may be limited by disconnected porosity, such as substantially impermeable or isolated porosity, within the interior matrix of the particulate.
  • a penetrating and/or coating material may trap or encapsulate air (or other fluid having apparent specific gravity less than particle matrix and less than coating/penetrating material) within the disconnected porosity in order to reduce apparent specific gravity by the desired amount.
  • Such materials coat and/or penetrate the porous particulate without invading the porosity to effectively encapsulate the air within the porosity of the particle. Encapsulation of the air provides preservation of the ultra-lightweight character of the particles once placed in the transport fluid. If the resin coating or transport fluids were to significantly penetrate the porosity of the particle, the density increases accordingly, and the particle no longer has the same lightweight properties.
  • the resin coat also adds strength and substantially enhances the proppant pack permeability at elevated stress.
  • Coating layers may be applied as desired to contribute to particle strength and/or reduce in situ fines migration once placed in a subterranean formation.
  • the coating significantly increases the strength and crush resistance of the ultra-lightweight ceramic particle.
  • the resin coat protects the particle from crushing, helps resist embedment, and prevents the liberation of fines.
  • the coating or penetrating fluid is typically selected to have an apparent specific gravity less than the apparent specific gravity of the porous particulate material so that once penetrated at least partially into the pores of the matrix it results in a particle having a apparent specific gravity less than that of the porous particulate material prior to coating or penetration, i.e., filling the pore spaces of a porous particulate material results in a solid or substantially solid particle having a much reduced apparent density.
  • the selected porous particulate material may be treated with a selected penetrating material in such a way that the resultant selectively configured porous particulate material has a much reduced apparent density, such as having a apparent density closer to or approaching the apparent specific gravity of a carrier fluid so that it is neutrally buoyant or semi- buoyant in a fracturing fluid or sand control fluid.
  • a penetrating material may be selected so that it helps structurally support the matrix of the porous particulate material (i.e., increases the strength of the porous matrix) and increases the ability of the particulate to withstand the closure stresses of a hydraulic fractured formation, or other downhole stresses.
  • a penetrating material may be selected by balancing the need for low apparent density versus the desire for strength, i.e., a more dense material may provide much greater strength.
  • the inherent and/or induced porosity of the porous particulate material may be selected so as to help provide the desired balance between apparent density and strength. It will be understood that other variable, such as downhole temperature and/or fluid conditions, may also impact the choice of penetrating materials.
  • the coating layer or penetrating material is generally present in the selectively configured porous particulate material in an amount of from about 0.5% to about 10% by weight of total weight.
  • the thickness of the coating layer of the selectively configured porous particulate material is generally between from about 1 to about 5 microns.
  • the extent of penetration of the penetrating material of the selectively configured porous particulate material is from less than about 1% penetration by volume to less than about 25% penetration by volume.
  • the porous particulate material is a porous ceramic particle having an apparent density of 1.25 or less and untreated porosity is approximately 60%.
  • Such materials may be treated with a coating material that does not penetrate the porous matrix of the porous particulate material, or that only partially penetrates the porous matrix of the ceramic particulate material.
  • Such treated ceramic materials may have an apparent density from about 1.1 g/cm 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%.
  • values outside these exemplary ranges are also possible.
  • a porous ceramic treated with about 6% epoxy has been seen to exhibit a bulk apparent density of about 1.29 and a porosity of about 50.6%
  • a porous ceramic treated with about 8% epoxy exhibits a bulk apparent density of about 1.34 and a porosity of about 46.9%
  • a porous ceramic treated with about 6% phenol formaldehyde resin exhibits a bulk apparent density of about 1.32 and a porosity of about 51.8%
  • 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%.
  • a coating material or penetrating material may be selected to be present in an amount of from about 0.5% to about 10% by weight of total weight of individual particles.
  • thickness of a coating material may be selected to be from about 1 to about 5 microns on the exterior of a particle.
  • extent of penetration penetrating material into a porous material particle may be selected to be from less than about 1% penetration by volume to less than about 25% penetration by volume of the particle. It will be understood that coating amounts, coating thickness, and penetration amounts may be outside these exemplary ranges as well.
  • the porous particulate material may be at least partially selectively configured by glazing, such as, for example, surface glazing with one or more selected non-porous glaze materials.
  • the glaze may extend or penetrate at least partially into the porous matrix of the porous particulate material, depending on the glazing method employed and/or the permeability (i.e., connectivity of internal porosity) characteristics of the selected porous particulate material, such as non-connected porosity allowing substantially no penetration to occur.
  • a selected porous particulate material may be selectively configured, such as glazed and/or coated with a non-porous material, in a manner so that the porous matrix of the resulting particle is at least partially or completely filled with air or some other gas, i.e., the interior of the resulting particle includes only air/gas and the structural material forming and surrounding the pores.
  • the inherent and/or induced porosity of a porous material particle may be selected so as to help provide the desired balance between apparent density and strength, and glazing and/or coating with no penetration (or extension of configured area into the particle matrix) may be selected to result in a particle having all or substantially all porosity of the particle being impenetrated and encapsulated to trap air or other relatively lightweight fluid so as to achieve minimum apparent specific gravity.
  • sealing a particle such as to seal air/gas within the porous matrix of the particle
  • such selective configuration such as using glazing and/or coating materials, may be selected to provide other advantages.
  • the porous particulate material such as the above-described fired kaolinitic particles
  • 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 susceptible to invasion or saturation by a well treatment fluid and thus capable of retaining relatively lightweight or substantially neutrally buoyant characteristics relative to the well treatment fluid upon exposure to such fluid.
  • Such glazing may be accomplished using any suitable method for forming a glaze on the surface or in the near surface of a particle, including by incorporating a glaze-forming material into the raw material "green paste” that is then formed such as molded into shape of the particle prior to firing.
  • glazes may be made from a variety of methods, including the application of a smooth, glassy coating such that a hard, nonporous surface is formed.
  • Glazes may 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 onto the substrate by firing or similar process known to those skilled in the art. Additionally, the use of borates or similar additives may improve the glaze. Examples of such glaze-forming materials include, but are not limited to, materials such as magnesium oxide-based material, boric acid/boric oxide-based material, etc. During firing, the glaze-forming material/s "bloom" to the surface of the particles and form a glaze.
  • glazing may be accomplished, for example, by applying a suitable glaze-forming material onto the surface of the formed raw material or "green" particles prior to firing such as by spraying, dipping, and similar methods so that glazing occurs during particle firing.
  • a glaze-forming material may be applied to a fired ceramic particle, and then fired again in a separate glaze-forming step.
  • 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 lightweight porous particle without the necessity of further alteration, such as necessity of coating with a separate polymer coating although optional coatings may be applied if so desired.
  • the resulting relatively smooth glazed surface of such a particle also may serve to enhance the ease of multi phase fluid flow, such as flow of water and gas and oil, through a particulate pack, such as through a proppant pack in a fracture, resulting in increased fracture conductivity.
  • one or more types of the disclosed selectively configured porous particulate material or non-selectively configured porous particulate material may be employed as particulates for well treating purposes in combination with a variety of different types of well treating fluids (including liquid CO 2 -based systems and other liquefied-gas or foamed-gas carrier fluids) and/or other types of particulates such as to achieve synergistic benefits, it being understood that benefits of the disclosed methods and compositions may also be achieved when employing only one type of the disclosed porous materials as a sole well treating particulate.
  • Elimination of the need to formulate a complex suspension gel may mean a reduction in tubing friction pressures, particularly in coiled tubing and in the amount of on-location mixing equipment and/or mixing time requirements, as well as reduced costs.
  • the disclosed relatively particles may be employed to simplify hydraulic fracturing treatments or sand control treatments performed through coil tubing, by greatly reducing fluid suspension property requirements. Downhole, a much reduced propensity to settle (as compared to conventional proppant or sand control particulates) may be achieved, particularly in highly deviated or horizontal wellbore sections.
  • the disclosed particulate material may be advantageously employed in any deviated well having an angle of deviation of between about 0 degree and about 90 degrees with respect to the vertical.
  • the disclosed particulate material may be advantageously employed in horizontal wells, or in deviated wells having an angle with respect to the vertical of between about 30 degrees and about 90 degrees, alternatively between about 75 degrees and about 90 degrees.
  • use of the disclosed particulate materials disclosed herein may be employed to achieve surprising and unexpected improvements in fracturing and sand control methodology, including reduction in proppant pack and/or formation damage, and enhancement of well productivity.
  • thermoplastic materials such as composition, amounts, types
  • characteristics of glazing materials, penetrating materials and/or coating materials are exemplary only. In this regard, such characteristics may be selected with benefit of this disclosure by those of skill in the art to meet and withstand anticipated downhole conditions of a given application using methods known in the art, such as those described herein.
  • blends of two or more different types of particles having different particulate characteristics may be employed as well treatment particulates.
  • Such blends may contain at least one porous particulate material and at least one other particulate material that may or may not be a porous particulate material.
  • the selectively configured porous particulate material and non-selectively configured porous particulate material may be used as two or more multiple layers.
  • successive layers of such materials may be employed.
  • multiple layers may consist of at least one selectively configured porous particulate material and at least one non- selectively configured porous particulate material.
  • a selected coating or penetrating material may be a urethane, such as ethyl carbamate-based resin, applied in an amount of about 4% by weight of the total weight of the selected porous material particle.
  • a selected coating material may be applied to achieve a coating layer of at least about 2 microns thick on the exterior of the selected porous material particle.
  • Such blends may be further employed in any type of well treatment application, including in any of the well treatment methods described elsewhere herein. In one exemplary embodiment, such blends may be employed to optimize hydraulic fracture geometries to achieve enhanced well productivity, such as to achieve increased propped fracture length in relatively "tight" gas formations.
  • Choice of different particulate materials and amounts thereof to employ in such blends may be made based on one or more well treatment considerations including, but not limited to, objective/s of well treatment, such as for sand control and/or for creation of propped fractures, well treatment fluid characteristics, such as apparent specific gravity and/or rheology of carrier fluid, well and formation conditions such as depth of formation, formation porosity/permeability, formation closure stress, type of optimization desired for geometry of downhole-placed particulates such as optimized fracture pack propped length, optimized sand control pack height, optimized fracture pack and/or sand control pack conductivity and combinations thereof.
  • objective/s of well treatment such as for sand control and/or for creation of propped fractures
  • well treatment fluid characteristics such as apparent specific gravity and/or rheology of carrier fluid
  • well and formation conditions such as depth of formation, formation porosity/permeability, formation closure stress
  • type of optimization desired for geometry of downhole-placed particulates such as optimized fracture pack propped length, optimized sand control pack
  • Such different types of particles may be selected, for example, to achieve a blend of different specific gravities or densities relative to the selected carrier fluid.
  • a blend of three different particles may be selected for use in a water fracture treatment to form a blend of well treatment particulates having three different specific gravities, such as apparent specific gravity of first type of particle from about 1 to less about 1.5; apparent specific gravity of second type of particle from greater than about 1.5 to about 2.0; and apparent specific gravity of third type of particle from about greater than about 2.0 to about 3.0; or in one specific embodiment the three types of particles having respective specific gravities of about 2.65, about 1.7 and about 1.2, it being understood that the preceding apparent specific gravity values are exemplary only and that other specific gravities and ranges of specific gravities may be employed.
  • At least one of the types of selected well treatment particulates may be selected to be substantially neutrally buoyant in the selected carrier fluid.
  • Such different types of particles may be selected for use in any amount suitable for achieving desired well treatment results and/or costs.
  • multiple types of particles may be selected for use in a blend of well treatment particulates in amounts that are about equal in proportion on the basis of total weight of the blend.
  • three different types of particles may each be employed in respective amounts of about 1/3 of the total blend such as by total weight of the blend, four different types of particles may each be employed in respective amounts of about % of the total blend such as by total weight or the blend.
  • each selected type of well particulate may be employed, such as for one exemplary embodiment of blend having three different types of particles, such as selected from the different types of particles described elsewhere herein, the amounts of each selected type of particle may be present in the blend in an amount ranging from about 10% to about 40% such as by total weight of the blend to achieve 100% weight of the total blend.
  • Examples of different particle types which may be selected for use in such blends include, but are not limited to, conventional sand particulates, such as Ottawa sand, relatively lightweight well treatment particulates, such as ground or crushed nut shells at least partially surrounded by at least one layer component of protective or hardening coating, selectively configured porous materials, such as any one or more of the selectively configured porous materials described herein, such as deformable particles.
  • Further examples of particle types which may be selected for use in such blends include any of those particles described in U.S. Patent Application Serial No. 10/113,844, filed April 1, 2002; U.S. Patent Application Serial No. 09/579,146, filed May 25, 2000; U.S. Patent No. 6,364,018; U.S. Patent No. 6,330,916; and U.S. Patent No. 6,059,034, each of which is incorporated herein by reference.
  • selected blends of conventional sand proppant, relatively lightweight particulates of ground or crushed nut shells at least partially surrounded by at least one layer component of protective or hardening coating, and selectively configured porous materials such as relatively lightweight porous material fired kaolinitic particles treated with a penetrating/coating materials described herein may be employed in a hydraulic fracture treatment utilizing ungelled or weakly gelled carrier fluid.
  • a hydraulic fracture treatment utilizing ungelled or weakly gelled carrier fluid.
  • these different types of particles may be employed in any relative volume or weight amount or ratio suitable for achieving desired well treatment results.
  • these different types of particles may be employed in a well treatment particulate composition including about 1/3 by weight of conventional sand proppant by total weight of well treatment particulate, about 1/3 by weight of relatively lightweight particulate, such as core of ground or crushed nut shells at least partially surrounded by at least one layer component of protective or hardening coating) by total weight of well treatment particulate, and about 1/3 by weight of selectively configured relatively lightweight porous material, such as fired kaolinitic particles treated with a penetrating/coating materials described herein, by total weight of well treatment particulate.
  • relatively lightweight particulate such as core of ground or crushed nut shells at least partially surrounded by at least one layer component of protective or hardening coating
  • selectively configured relatively lightweight porous material such as fired kaolinitic particles treated with a penetrating/coating materials described herein
  • porous polymeric materials such as polyolefins, styrene-divinylbenzene based materials, pqlyalkylacrylate esters and modified starches.
  • any of the disclosed porous materials may be employed in
  • well treating methods such as hydraulic fracturing and sand control, which may be employed to treat a well penetrating a subterranean formation, and include introducing into a well a selected porous particulate material that is treated with a selected coating material, selected penetrating material, or combination thereof.
  • Individual particles of the particulate material optionally may have a shape with a maximum length-based aspect ratio of equal to or less than about 5.
  • 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.
  • porous ceramic particles may be manufactured by firing at relatively low temperatures to avoid loss of porosity due to crystallization and driving off of water.
  • Particular examples include, but are not limited to, porous ceramic particles available from Carbo Ceramics Inc.
  • relatively lightweight particulates or blends including such particulates as described elsewhere herein may be advantageously employed as well treatment particulates, such as fracture proppant particulate or sand control particulate, in liquefied gas and foamed gas carrier fluids.
  • carrier fluids examples include, but are not limited to, liquid CO 2 -based systems, liquid CO 2 , CO /N 2 , and foamed N in CO 2 systems that may be employed in hydraulic fracturing applications.
  • porous ceramic well particulates having a bulk apparent density of close to or about 1.0 g/cm may be employed with such liquefied gas and/or foamed gas carrier fluids, such as liquid CO 2 -based systems, liquid CO 2 , CO 2 /N 2 , and foamed N 2 in CO 2 systems.
  • selectively configured particulates and/or non-selectively configured particulates may be employed that may be characterized as substantially neutrally buoyant in such liquefied gas and/or foamed gas carrier fluids.
  • Liquid CO 2 has a density close to about 1.02 g/cm under typical fracturing conditions, and conventional proppants, such as sand, or non-relatively lightweight ceramic proppants have a tendency to settle in liquid CO 2 -based systems. Furthermore, liquid CO 2 has very little if any viscosity, and therefore proppant transport in a liquid CO 2 -based system is provided by turbulence and frictional forces, and fractures created by liquid CO 2 are typically relatively narrow.
  • proppant transport of relatively lightweight particulates is easier than is proppant transport of conventional sand proppants or non-relatively lightweight ceramic proppants.
  • relatively lightweight porous ceramic particles may be employed in liquid CO 2 -based systems.
  • types of such relatively lightweight porous ceramic particles include, but are not limited to, those porous ceramic particles available from Carbo Ceramics for controlled release applications altered in the manufacturing process to have a bulk apparent density close to about 1.0 g/cm 3 .
  • Other suitable examples of relatively lightweight porous particles include, but are not limited to, those particles having a bulk apparent density of less than about 2.5 g/cm 3 , alternatively having a bulk apparent density of from about 1.0 to about 2.0 g/cm , further alternatively having a bulk apparent density of from about 1.2 g/cm to about 2.0 g/cm 3 .
  • relatively lightweight porous ceramic particle for use in CO 2 -based systems of this embodiment is porous ceramic material described elsewhere herein, either in selectively configured form, as described herein in Example 1, or in non-selectively configured or non-altered or "neat” form.
  • relatively lightweight porous ceramic materials or blends thereof may be employed as fracture proppant materials in liquid CO 2 -based fracturing systems using methodologies similar or the same to those employed with conventional proppants in liquid CO 2 -based fracturing systems.
  • liquid CO 2 -based fracturing job characteristics such as proppant amounts, proppant sizes, mixing and pumping methodologies, using relatively lightweight porous ceramic materials may be the same as described for conventional proppants in "The History and Success of Liquid
  • relatively lightweight porous ceramic particles employed as fracture proppant particulate in a liquid CO 2 -based system may be used in "neat" or non-altered form and may have a apparent specific gravity of from about 1.17 to about 2.0
  • using relatively lightweight porous ceramic particles as fracture proppant particulate in a liquid CO -based system allows the concentration of proppant in such a system to be advantageously extended to about 1200 Kg/cubic meter.
  • Other advantages of using the disclosed relatively lightweight porous ceramic particles in liquid CO 2 - based fracturing systems include, but are not limited to, reduced proppant settling in surface mixing equipment prior to pumping downhole and improved proppant transport downhole and into the formation.
  • liquid CO 2 -based systems using other relatively lightweight porous material particulate materials and blends thereof described elsewhere herein, such as porous polymeric materials such as polyolefins. Any of such materials may be employed in "neat" or non-altered form with liquid CO 2 -based systems where apparent density and other characteristics of the particle are suitable to meet requirements of the given well treating application, or may alternatively be employed in selectively configured form as described elsewhere herein.
  • Example 1 is illustrative and should not be construed as limiting the scope of the invention or claims thereof.
  • Example 1
  • FIG. 1 illustrates comparisons of the bulk densities of various proppants/sand control materials to samples of a selected porous ceramic material (from Carbo Ceramics, Inc.).
  • Carbolite is a commercial proppant available from Carbo Ceramics, Inc.
  • Nitro is untreated porous ceramic material from Carbo Ceramics, Inc.
  • 2/2 is porous ceramic material from Carbo Ceramics, Inc. treated with 2% by weight of particle epoxy inner coating/penetrating material (epoxy is 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.
  • Figs. 2 and 5 illustrate the permeability versus closure stress for coated and uncoated ceramic ULW particulates.
  • resin coating and impregnation of the ULW particle imparts significant strength across the closure range and in particular, enhances the low to mid- range performance of the material.
  • the data represents equal pack widths for all of the proppants with adjustments made for each respective density.
  • Both the coated and uncoated ceramics ULW were tested at 1.4 pounds per square foot (33.2 kg/ m 2 ). Each of these tests had nearly identical width measurements for ease of comparison.
  • Example 2 Example 2:
  • the porous particulate material employed was from "Carbo Ceramics” having a size of about 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 material was tested alone, with no other particulate material blended 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 is a function of the width times the permeability.
  • a selected porous material particulate may be treated with a selected coating and/or penetrating material to produce a relatively lightweight particulate sample that at the same lb/sq ft loading as a conventional sand will occupy a greater width. Even if the pack permeability is the same, the conductivity, and thus the proppant pack producability, will be higher. Thus, as represented by the conductivity data, the benefit of the combination of increased width and the improved permeability may be achieved.
  • a selected porous material particulate may be treated with a selected coating and/or penetrating material so that particle strength is maintained to as high a confining (or closure) stress as possible, which is reflected more directly by the permeability data.
  • a certain amount of fracture conductivity at a given stress/temp condition may be maintained without increasing the cost, and/or by offsetting any cost increase with improved value.
  • substantially less particulate material may be employed to achieve a substantially equivalent conductivity due to the lesser mass/unit volume.
  • particles may be produced that are capable for use, such as having sufficient crush resistance for use or do not crush, under conditions of 2000 psi closure stress or greater, alternatively 2500 psi closure stress or greater, alternatively 3000 psi closure stress or greater, alternatively up to at least about 6000 psi closure stress, alternatively up to at least about 7000 psi closure stress, and alternatively at least about 8000 psi closure sfress, i.e., almost as resistant to crush as commercial ceramic proppants which are heavier (e.g., commercial ceramic proppant (CarboLite) is about 40% heavier).
  • Commercial ceramic proppant CarboLite
  • particles may be produced that are capable for use (e.g., have sufficient crush resistance for use or do not crush) under conditions of from about 2000 psi closure sfress to about 8000 psi closure stress, alternatively from about 2500 psi closure stress to about 8000 psi closure stress, alternatively from about 3000 psi closure stress to about 8000 psi closure sfress.
  • particles may produced that are capable of use at higher closure stresses than 8000 psi and lower closure stresses than about 2000 psi as well.
  • FIGS. 8-15 are cross-sectional and surface SEM photographs of various treated and untreated samples of porous ceramic materials from CARBO CERAMICS.
  • the particular coating/penetrating material is either the same epoxy or phenol formaldehyde resin employed and identified in Example 1.
  • FIG. 8 shows particles treated with about 10% by weight of particle resin.
  • FIG. 9 shows particles treated first with 2% by weight epoxy and second with 2% by weight resin.
  • FIG. 10 shows untreated particles.
  • FIG. 11 shows particles treated first with 2% by weight epoxy and second with 2% by weight resin.
  • FIG. 12 shows surface of 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 shows particles treated with about 10% by weight of particle resin.
  • FIG. 9 shows particles treated first with 2% by weight epoxy and second with 2% by weight resin.
  • FIG. 10 shows untreated particles.
  • FIG. 11 shows particles treated first with 2% by weight epoxy and second with 2% by weight resin.
  • FIG. 12 shows surface of untreated particle.
  • FIG. 13 shows untreated particles.
  • a selected blend of three different apparent specific gravity well treatment particulates were evaluated for use in a water fracture treatment of a "tight" gas well based on a Canyon Sand gas well.
  • the three different apparent specific gravity particulates were chosen to represent, for example, a selected blend of the following different types of well treatment particulates: I. 20/40 mesh Ottawa sand having the following properties: apparent specific gravity of
  • ⁇ re +/- 500 (Typical for water fracs) III. 20/40 mesh ground or crushed nut shells coated with protective or hardening coating
  • particulate III weighs about half as much as Particulate I, but settles at a rate less than about 1/4 as fast.
  • a well treatment particulate including a selected blend of roughly equal amounts of the above types of particulates i.e., about 1/3 by weight of above particulate I of the total weight of the blend, about 1/3 by weight of above particulate II of the total weight of the blend, and about 1/3 by weight of above particulate III of the total weight of the blend
  • FIG. 16 illustrates proppant distribution in the resulting simulated hydraulic fracture created downhole.
  • FIG. 17 illustrates proppant distribution in the resulting simulated hydraulic fracture created downhole.
  • blends of these and other types of well treatment blends may be selected and employed for other types of wells, including wells productive of liquids as well as gas, and wells having relatively higher formation permeability values.
  • benefits of the disclosed method may be realized using blends of other than three different types of well treatment particulates, for example, using two different types of well treatment particulates or more than three different types of well treatment particulates (e.g., as many as four, five, six, seven, eight, nine and more different types of well treatment particulates) having varying characteristics.
  • Example 6 Example 6:
  • ULW- 1.75 corresponds to 2/2 discussed above in Example 1 and can be characterized as a porous ceramic particle with the roundness and sphericity common to ceramic proppants.
  • the porosity averages 50%, yielding a bulk density of 1.10 to 1.15g/cm 3 .
  • Median-sized 20/40 particles of the ULW- 1.75 and 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 rate between the conventional proppant and the ULW particles. Median sized 20/40 particles of each proppant were used for the evaluations. Stokes Law calculations giving the fall velocity in ft/minute are presented in Table 3 and were calculated as:
  • V I ⁇ flmd (Sp.Gr. Vmv - Sp.Gr. flmd ) where velocity is in ft/min., diameter d is the average particle diameter and, ⁇ is fluid viscosity in cps.
  • the ULW-1.75 test was initiated at 90 gpm.
  • ULW-1.75 was observed to be subject to some settling at 90 gpm, with the bed height growing to 4 inches.
  • the fluid rate was lowered to 80 gpm and bed height grew to 6 inches.
  • the ULW-1.75 bed was observed to grow with reduced rate to 12 inches.
  • the rate was lowered further to 5 gpm and the bed height grew to 19 inches or 86% of the total slot height.
  • bed height decreases due to erosion and fluidization of the bed.
  • the ULW-1.75 results are presented in Table 5.

Landscapes

  • Engineering & Computer Science (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Mining & Mineral Resources (AREA)
  • Geology (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Chemical & Material Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • Materials Engineering (AREA)
  • Organic Chemistry (AREA)
  • Porous Artificial Stone Or Porous Ceramic Products (AREA)
  • Manufacture Of Porous Articles, And Recovery And Treatment Of Waste Products (AREA)
  • Solid-Sorbent Or Filter-Aiding Compositions (AREA)
  • Road Paving Structures (AREA)

Abstract

L'invention concerne des procédés et des compositions utilisés dans les traitements de formations souterraines, tels que des traitements par fracturation hydraulique et anti-sable contenant des matériaux poreux. Ces matériaux poreux peuvent être des particules de matériaux poreux sélectivement configurés, fabriquées et/ou traitées à l'aide de matériaux de vitrification, de matériaux de revêtement et/ou de matériaux d'imprégnation sélectionnés afin d'obtenir la force et/ou la densité apparente désirées d'adaptation à des conditions de fond spécifiques pour le traitement des puits, par exemple les traitements par fracturation hydraulique et les traitements anti-sable. Ces matériaux poreux peuvent également être utilisés dans des combinaisons sélectionnées afin d'optimiser l'efficacité de la fracturation ou de l'élimination du sable, et/ou peuvent être utilisés commes matériaux relativement légers dans des systèmes de traitement de puits à base de dioxyde de carbone liquide.
PCT/US2003/027611 2002-09-03 2003-09-02 Procede de traitement de formations souterraines a l'aide de materiaux particulaires de ceramique poreuse WO2004022914A1 (fr)

Priority Applications (8)

Application Number Priority Date Filing Date Title
BR0314336-8A BR0314336A (pt) 2002-09-03 2003-09-02 Processo de tratamento de formações subterrâneas com materiais porosos particulados de cerâmica
CA2497276A CA2497276C (fr) 2002-09-03 2003-09-02 Procede de traitement de formations souterraines a l'aide de materiaux particulaires de ceramique poreuse
BRPI0314336-8A BRPI0314336B1 (pt) 2002-09-03 2003-09-02 Particulado poroso configurado seletivamente e processo para tratamento de poço que penetra em uma formação subterrânea
AU2003270298A AU2003270298A1 (en) 2002-09-03 2003-09-02 Method of treating subterranean formations with porous ceramic particulate materials
GB0504305A GB2408279B (en) 2002-09-03 2003-09-02 Method of treating subterranean formations with porous ceramic particulate materials
GBGB0504410.2A GB0504410D0 (en) 2002-09-03 2005-02-22 Method of treating subterranean formations with porous ceramic particulate materials
NO20051054A NO342605B1 (no) 2002-09-03 2005-02-25 Proppemiddel eller sandkontroll partikulært materiale av et selektivt konfigurert porøst materiale og fremgangsmåte for å behandle underjordiske formasjoner med dette materialet
DK200500311A DK200500311A (da) 2003-09-02 2005-03-01 Fremgangsmåde til behandling af underjordiske formationer med poröse keramiske patikulære materialer

Applications Claiming Priority (4)

Application Number Priority Date Filing Date Title
US40773402P 2002-09-03 2002-09-03
US60/407,734 2002-09-03
US42883602P 2002-11-25 2002-11-25
US60/428,836 2002-11-25

Publications (1)

Publication Number Publication Date
WO2004022914A1 true WO2004022914A1 (fr) 2004-03-18

Family

ID=31981540

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/US2003/027611 WO2004022914A1 (fr) 2002-09-03 2003-09-02 Procede de traitement de formations souterraines a l'aide de materiaux particulaires de ceramique poreuse

Country Status (6)

Country Link
AU (1) AU2003270298A1 (fr)
BR (2) BRPI0314336B1 (fr)
CA (1) CA2497276C (fr)
GB (3) GB2408279B (fr)
NO (1) NO342605B1 (fr)
WO (1) WO2004022914A1 (fr)

Cited By (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP2192094A1 (fr) 2008-11-27 2010-06-02 Services Pétroliers Schlumberger Compositions de résine aqueuses et procédés de réparation du ciment
CN103194204A (zh) * 2013-04-10 2013-07-10 北京奥陶科技有限公司 一种用于煤层气与页岩气水力压裂的支撑剂及其制备方法
WO2015067556A1 (fr) * 2013-11-06 2015-05-14 Statoil Petroleum As Agents de soutènement fonctionnalisés
CN107829731A (zh) * 2017-11-06 2018-03-23 陈国军 一种黏土蚀变的火山岩孔隙度校正方法
CN110872505A (zh) * 2019-12-03 2020-03-10 成都理工大学 有机多孔纳米颗粒/表面活性剂复合驱油体系及其制备方法
US11339323B2 (en) 2015-11-24 2022-05-24 Carbo Ceramics Inc. Lightweight proppant and methods for making and using same

Families Citing this family (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CA2536957C (fr) 2006-02-17 2008-01-22 Jade Oilfield Service Ltd. Methode de traitement d'une formation par agents de soutenement deformables
CA2948953A1 (fr) * 2014-03-28 2015-10-01 Beijing Rechsand Science & Technology Group Co., Ltd Agent de soutenement auto-suspendu, sa preparation et son utilisation
CN116063051A (zh) * 2021-11-02 2023-05-05 中国石油化工股份有限公司 一种无机胶凝防砂材料及制备方法

Citations (10)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP0308257A2 (fr) * 1987-09-17 1989-03-22 Minnesota Mining And Manufacturing Company Particules céramiques revêtues de novolaque
US4921820A (en) * 1989-01-17 1990-05-01 Norton-Alcoa Proppants Lightweight proppant for oil and gas wells and methods for making and using same
US5582249A (en) * 1995-08-02 1996-12-10 Halliburton Company Control of particulate flowback in subterranean wells
US5582250A (en) * 1995-11-09 1996-12-10 Dowell, A Division Of Schlumberger Technology Corporation Overbalanced perforating and fracturing process using low-density, neutrally buoyant proppant
US6047772A (en) * 1995-03-29 2000-04-11 Halliburton Energy Services, Inc. Control of particulate flowback in subterranean wells
US6059034A (en) * 1996-11-27 2000-05-09 Bj Services Company Formation treatment method using deformable particles
GB2360534A (en) * 2000-03-06 2001-09-26 Bj Services Co Formation treatment using deformable particles and a proppant
WO2002026656A1 (fr) * 2000-09-28 2002-04-04 Fairmount Minerals Ltd Composition de soutenement pour fracturation de puits de gaz et de petrole
CA2329834A1 (fr) * 2000-12-28 2002-06-28 David Droppert Granules de ceramique a haute resistance, resistant a la chaleur et a la corrosion, pour agents de soutenement
US6439310B1 (en) * 2000-09-15 2002-08-27 Scott, Iii George L. Real-time reservoir fracturing process

Family Cites Families (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
GB9808490D0 (en) * 1998-04-22 1998-06-17 Aea Technology Plc Well treatment for water restriction

Patent Citations (11)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP0308257A2 (fr) * 1987-09-17 1989-03-22 Minnesota Mining And Manufacturing Company Particules céramiques revêtues de novolaque
US4921820A (en) * 1989-01-17 1990-05-01 Norton-Alcoa Proppants Lightweight proppant for oil and gas wells and methods for making and using same
US6047772A (en) * 1995-03-29 2000-04-11 Halliburton Energy Services, Inc. Control of particulate flowback in subterranean wells
US5582249A (en) * 1995-08-02 1996-12-10 Halliburton Company Control of particulate flowback in subterranean wells
US5582250A (en) * 1995-11-09 1996-12-10 Dowell, A Division Of Schlumberger Technology Corporation Overbalanced perforating and fracturing process using low-density, neutrally buoyant proppant
US6059034A (en) * 1996-11-27 2000-05-09 Bj Services Company Formation treatment method using deformable particles
US6330916B1 (en) * 1996-11-27 2001-12-18 Bj Services Company Formation treatment method using deformable particles
GB2360534A (en) * 2000-03-06 2001-09-26 Bj Services Co Formation treatment using deformable particles and a proppant
US6439310B1 (en) * 2000-09-15 2002-08-27 Scott, Iii George L. Real-time reservoir fracturing process
WO2002026656A1 (fr) * 2000-09-28 2002-04-04 Fairmount Minerals Ltd Composition de soutenement pour fracturation de puits de gaz et de petrole
CA2329834A1 (fr) * 2000-12-28 2002-06-28 David Droppert Granules de ceramique a haute resistance, resistant a la chaleur et a la corrosion, pour agents de soutenement

Cited By (9)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP2192094A1 (fr) 2008-11-27 2010-06-02 Services Pétroliers Schlumberger Compositions de résine aqueuses et procédés de réparation du ciment
US8967254B2 (en) 2008-11-27 2015-03-03 Schlumberger Technology Corporation Aqueous resin compositions and methods for cement repair
CN103194204A (zh) * 2013-04-10 2013-07-10 北京奥陶科技有限公司 一种用于煤层气与页岩气水力压裂的支撑剂及其制备方法
CN103194204B (zh) * 2013-04-10 2016-03-23 北京奥陶科技有限公司 一种用于煤层气与页岩气水力压裂的支撑剂及其制备方法
WO2015067556A1 (fr) * 2013-11-06 2015-05-14 Statoil Petroleum As Agents de soutènement fonctionnalisés
US11339323B2 (en) 2015-11-24 2022-05-24 Carbo Ceramics Inc. Lightweight proppant and methods for making and using same
CN107829731A (zh) * 2017-11-06 2018-03-23 陈国军 一种黏土蚀变的火山岩孔隙度校正方法
CN110872505A (zh) * 2019-12-03 2020-03-10 成都理工大学 有机多孔纳米颗粒/表面活性剂复合驱油体系及其制备方法
CN110872505B (zh) * 2019-12-03 2020-09-15 成都理工大学 有机多孔纳米颗粒/表面活性剂复合驱油体系及其制备方法

Also Published As

Publication number Publication date
BRPI0314336B1 (pt) 2019-02-12
GB2430453A (en) 2007-03-28
GB2430453B (en) 2007-06-20
NO20051054L (no) 2005-04-01
CA2497276C (fr) 2010-11-02
GB2408279B (en) 2006-12-20
BR0314336A (pt) 2005-07-26
CA2497276A1 (fr) 2004-03-18
AU2003270298A1 (en) 2004-03-29
GB0504410D0 (en) 2005-04-06
GB0619263D0 (en) 2006-11-08
GB2408279A (en) 2005-05-25
GB0504305D0 (en) 2005-04-06
NO342605B1 (no) 2018-06-18

Similar Documents

Publication Publication Date Title
US7861780B2 (en) Method of treating subterranean formations with porous particulate materials
US8127849B2 (en) Method of using lightweight polyamides in hydraulic fracturing and sand control operations
US7772163B1 (en) Well treating composite containing organic lightweight material and weight modifying agent
US6749025B1 (en) Lightweight methods and compositions for sand control
CA2400597C (fr) Procedes legers et compositions pour le traitement de puits
US7971643B2 (en) Methods and compositions of a storable relatively lightweight proppant slurry for hydraulic fracturing and gravel packing applications
CA2668505C (fr) Procede de colmatage d'une formation fracturee
CA2644213C (fr) Methode de traitement de formations souterraines faisant appel a des agents de soutenement de differentes densites ou a des etages sequentiels d'agent de soutenement
US20100132943A1 (en) Resin Compositions and Methods of Using Resin Compositions to Control Proppant Flow-Back
US20080179057A1 (en) Well Treating Agents of Metallic Spheres and Methods of Using the Same
WO2009088317A1 (fr) Particules allongées pour la fracturation et la consolidation avec des graviers
NO342605B1 (no) Proppemiddel eller sandkontroll partikulært materiale av et selektivt konfigurert porøst materiale og fremgangsmåte for å behandle underjordiske formasjoner med dette materialet
WO2001066908A2 (fr) Procedes legers et compositions de controle du sable
CA2713734C (fr) Procede de traitement de formations souterraines a l'aide de materiaux particulaires de ceramique poreuse
WO2009078744A1 (fr) Additif pour empêcher l'agent de soutènement de refluer des fractures hydrauliques

Legal Events

Date Code Title Description
AK Designated states

Kind code of ref document: A1

Designated state(s): AE AG AL AM AT AU AZ BA BB BG BR BY BZ CA CH CN CO CR CU CZ DE DK DM DZ EC EE ES FI GB GD GE GH GM HR HU ID IL IN IS JP KE KG KP KR KZ LC LK LR LS LT LU LV MA MD MG MK MN MW MX MZ NI NO NZ OM PG PH PL PT RO RU SC SD SE SG SK SL SY TJ TM TN TR TT TZ UA UG UZ VC VN YU ZA ZM ZW

AL Designated countries for regional patents

Kind code of ref document: A1

Designated state(s): GH GM KE LS MW MZ SD SL SZ TZ UG ZM ZW AM AZ BY KG KZ MD RU TJ TM AT BE BG CH CY CZ DE DK EE ES FI FR GB GR HU IE IT LU MC NL PT RO SE SI SK TR BF BJ CF CG CI CM GA GN GQ GW ML MR NE SN TD TG

121 Ep: the epo has been informed by wipo that ep was designated in this application
WWE Wipo information: entry into national phase

Ref document number: 2497276

Country of ref document: CA

ENP Entry into the national phase

Ref document number: 0504305

Country of ref document: GB

Kind code of ref document: A

Free format text: PCT FILING DATE = 20030902

WWE Wipo information: entry into national phase

Ref document number: 519/CHENP/2005

Country of ref document: IN

122 Ep: pct application non-entry in european phase
NENP Non-entry into the national phase

Ref country code: JP

WWW Wipo information: withdrawn in national office

Ref document number: JP