Wells – Processes – Specific propping feature
Reexamination Certificate
2000-03-06
2001-12-18
Tsay, Frank S. (Department: 3672)
Wells
Processes
Specific propping feature
C166S310000, C507S924000
Reexamination Certificate
active
06330916
ABSTRACT:
BACKGROUND OF THE INVENTION
1. Field of the Invention
This invention relates generally to subterranean formation treatments and, more specifically, to hydraulic fracturing treatments for subterranean formations. In particular, this invention relates to deformable particles mixed with fracturing proppants to reduce fines generation, improve fracture conductivity, and/or minimize proppant flowback.
2. Description of the Related Art
Hydraulic fracturing is a common stimulation technique used to enhance production of fluids from subterranean formations. In a typical hydraulic fracturing treatment, fracturing treatment fluid containing a solid proppant material is injected into the formation at a pressure sufficiently high enough to cause the formation or enlargement of fractures in the reservoir. During a typical fracturing treatment, proppant material is deposited in a fracture, where it remains after the treatment is completed. 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.
One problem related to hydraulic fracturing treatments is the creation of reservoir “fines” and associated reduction in fracture conductivity. These fines may be produced when proppant materials are subjected to reservoir closure stresses within a formation fracture which cause proppant materials to be compressed together in such a way that small particles (“fines”) are generated from the proppant material and/or reservoir matrix. In some cases, production of fines may be exacerbated during production/workover operations when a well is shut-in and then opened up. This phenomenon is known as “stress cycling” and is believed to result from increased differential pressure and closure stress that occurs during fluid production following a shut-in period. Production of fines is undesirable because of particulate production problems, and because of reduction in reservoir permeability due to plugging of pore throats in the reservoir matrix.
Production of particulate solids with subterranean formation fluids is also a common problem. The source of these particulate solids may be unconsolidated material from the formation, proppant from a fracturing treatment and/or fines generated from crushed fracture proppant, as mentioned above. Production of solid proppant material is commonly known as “proppant flowback.” In addition to causing increased wear on downhole and surface production equipment, the presence of particulate materials in production fluids may also lead to significant expense and production downtime associated with removing these materials from wellbores and/or production equipment. Accumulation of these materials in a well bore may also restrict or even prevent fluid production. In addition, loss of proppant due to proppant flowback may also reduce conductivity of a fracture pack.
In an effort to control or prevent production of formation or proppant materials, many methods have been developed. For example, to address proppant flowback methods utilizing special types of proppants and/or additives to proppants have been employed to help form a fracture pack in the reservoir which is resistant to proppant flowback. One well known method of this type utilizes resin-coated proppant materials designed to help form a consolidated and permeable fracture pack when placed in the formation. Among the ways this method may be carried out are by mixing a proppant particulate material with an epoxy resin system designed to harden once the material is placed in the formation, or by the use of a pre-coated proppant material which is pumped into the formation with the fracturing fluid and then consolidated with a curing solution pumped after the proppant material is in place. Although resin-coated proppant techniques may reduce proppant flowback, they may also suffer from various problems, including incompatibility of resins with cross-linker and breaker additives in the fracturing fluid, and long post-treatment shut-in times which may be economically undesirable. Resin-coated proppants may also be difficult to place uniformly within a fracture and may adversely affect fracture conductivity. In addition, if desired, resin-coated proppants may only be added to the final stages of fracturing treatments due to their expense, resulting in a fracture pack that is consolidated only in a region near the well bore.
Recently, techniques employing a mixture of solid proppant materials designed to achieve proppant flowback control have been developed. In one technique, rod-like fibrous materials are mixed with proppant material for the purpose of causing particle bridging within a fracture proppant pack so as to inhibit particle movement and proppant flowback. This technique is believed to control proppant flowback by forming a “mat” of fibers across openings in the pack which tends to hold the proppant in place and limit proppant flowback during fluid production. However, in practice this method has proven to have several drawbacks, including reduction in fracture conductivity at effective concentrations of fibrous materials, and an effective life of only about two years due to slight solubility of commonly used fiber materials in brine. In addition, fiber proppant material used in the technique may be incompatible with some common well-treating acids, such as hydrofluoric acid.
In another recently developed method, thermoplastic material in the form of ribbons or flakes is mixed with proppant material in order to form a fracture proppant pack that is resistant to proppant flowback. The thermoplastic material is designed to intertwine with proppant particles and become “very tacky” at reservoir temperatures such as those greater than about 220° F. In doing so, the materials are believed to adhere to proppant material to form agglomerates that bridge against each other and help hold proppant materials in place. This method of controlling proppant flowback suffers similar drawbacks as the fiber proppant additive method described above, most notably reduced conductivity. Therefore, a method of reducing fines creation while at the same time improving fracture conductivity and reducing proppant flowback is desirable.
SUMMARY OF THE INVENTION
In one respect, this invention is a method of treating a subterranean formation by injecting into the formation a fracturing fluid composition that includes a blend of a fracture proppant material and a deformable beaded material.
In another respect, this invention is a method of treating a subterranean formation by injecting into the formation a blend of a fracture proppant material and a deformable particulate material. Individual particles of the deformable particulate material may have a shape with a maximum length-based aspect ratio of equal to or less than about 5.
In another respect, this invention is a method of treating a subterranean formation by injecting into the formation a blend of a fracture proppant material and a deformable particulate material having a shape that is at least one of beaded, cubic, bar-shaped, cylindrical, or a mixture thereof. Beaded or cylindrical shaped particulate materials may have a length to diameter aspect ratio of equal to or less than about 5, and bar-shaped particulate material may have a length to width aspect ratio of equal to or less than about 5 and a length to thickness aspect ratio of equal to or less than about 5.
In yet another respect, this invention is a method of treating a subterranean formation by injecting into the formation a fracturing fluid composition that includes a blend of fracture proppant material and deformable particulate material. In this method, the fracturing fluid composition is deposited in the subterranean formation so that the blend of fracture propp
Brannon Harold D.
DiLullo Gino A.
Rae Philip J.
Rickards Allan R.
Stephenson Christopher J.
BJ Services Company
O'Keefe Egan & Peterman, LLP
Tsay Frank S.
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