Wells – Processes – Distinct – separate injection and producing wells
Reexamination Certificate
2002-07-23
2004-08-17
Schoeppel, Roger (Department: 3672)
Wells
Processes
Distinct, separate injection and producing wells
C166S280100, C166S308400
Reexamination Certificate
active
06776235
ABSTRACT:
TECHNICAL FIELD OF THE INVENTION
This invention relates generally to the art of hydraulic fracturing in subterranean formations and more particularly to a method and means for optimizing fracture conductivity.
BACKGROUND OF THE INVENTION
Hydrocarbons (oil, natural gas, etc.) are obtained from a subterranean geologic formation (i.e., a “reservoir”) by drilling a well that penetrates the hydrocarbon-bearing formation. This provides a partial flowpath for the hydrocarbon to reach the surface. In order for the hydrocarbon to be “produced,” that is travel from the formation to the wellbore (and ultimately to the surface), there must be a sufficiently unimpeded flowpath from the formation to the wellbore.
Hydraulic fracturing is a primary tool for improving well productivity by placing or extending channels from the wellbore to the reservoir. This operation is essentially performed by hydraulically injecting a fracturing fluid into a wellbore penetrating a subterranean formation and forcing the fracturing fluid against the formation strata by pressure. The formation strata or rock is forced to crack and fracture. Proppant is placed in the fracture to prevent the fracture from closing and thus, provide improved flow of the recoverable fluid, i.e., oil, gas or water.
The success of a hydraulic fracturing treatment is related to the fracture conductivity. Several parameters are known to affect this conductivity. First, the proppant creates a conductive path to the wellbore after pumping has stopped and the proppant pack is thus critical to the success of a hydraulic fracture treatment. Numerous methods have been developed to improve the fracture conductivity by proper selection of the proppant size and concentration. To improve fracture proppant conductivity, typical approaches include selecting the optimum propping agent. More generally, the most common approaches to improve propped fracture performance include high strength proppants (if the proppant strength is not high enough, the closure stress crushes the proppant, creating fines and reducing the conductivity), large diameter proppants (permeability of a propped fracture increases as the square of the grain diameter), high proppant concentrations in the proppant pack to obtain wider propped fractures.
In an effort to limit the flowback of particulate proppant materials placed into the formation, proppant-retention agents are commonly used so that the proppant remains in the fracture. For instance, the proppant may be coated with a curable resin activated under downhole conditions. Different materials such as fibrous material, fibrous bundles or deformable materials have also used. In the cases of fibers, it is believed that the fibers become concentrated into a mat or other three-dimensional framework, which holds the proppant thereby limiting its flowback. Additionally, fibers contribute to prevent fines migration and consequently, a reduction of the proppant-pack conductivity.
To ensure better proppant placement, it is also known to add a proppant-retention agent, e.g. a fibrous material, a curable resin coated on the proppant, a pre-cured resin coated on the proppant, a combination of curable and pre-cured (sold as partially cured) resin coated on the proppant, platelets, deformable particles, or a sticky proppant coating, to trap proppant particles in the fracture and prevent their production through the fracture and to the wellbore.
Proppant-based fracturing fluids typically also comprise a viscosifier, such as a solvatable polysaccharide to provide sufficient viscosity to transport the proppant. Leaving a highly-viscous fluid in the fracture reduces the permeability of the proppant pack, limiting the effectiveness of the treatment. Therefore, gel breakers have been developed that reduce the viscosity by cleaving the polymer into small molecules fragments. Other techniques to facilitate less damage in the fracture involve the use of gelled oils, foamed fluids or emulsified fluids. More recently, solid-free systems have been developed, based on the use of viscoelastic surfactants as viscosifying agent, resulting in fluids that leave no residues that may impact fracture conductivity.
Numerous attempts have also been made to improve the fracture conductivity by controlling the fracture geometry, for instance to limit its vertical extent and promoting longer fracture length. Since creating a fracture stimulates the production by increasing the effective wellbore radius, the longer the fracture, the greater the effective wellbore radius. Yet many wells behave as though the fracture length were much shorter because the fracture is contaminated with fracturing fluid (i.e., more particularly, the fluid used to deliver the proppant as well as a fluid used to create the fracture, both of which shall be discussed below). The most difficult portion of the fluid to recover is that retained in the fracture tip—i.e. the distal-most portion of the fracture from the wellbore. Thus, the result of stagnant fracturing fluid in the fracture naturally diminishes the recovery of hydrocarbons.
Among the methods proposed to improve fracture geometry, one includes fracturing stages with periods of non-pumping or intermittent sequences of pumping and flowing the well back as described in the U.S. Pat. No. 3,933,205 to Kiel. By multiple hydraulic fracturing, the well productivity is increased. First, a long primary fracture is created, then spalls are formed by allowing the pressure in the fracture to drop below the initial fracturing pressure by discontinuing injection and shutting the well. The injection is resumed to displace the formed spalls along the fracture and again discontinued, and the fracture is propped by the displaced spalls. According to a preferred embodiment, the method is practiced by allowing the well to flow back during at least some portion of the discontinuation of the injection.
Another placement method involves pumping a high viscosity fluid for Pad followed by less viscous fluid for proppant stages. This technique is used for fracturing thin producing intervals when fracture height growth is not desired to help keep the proppant across from the producing formation. This technique, sometimes referred to as “pipeline fracturing”, utilizes the improved mobility of the thinner, proppant-laden fluid to channel through the significantly more viscous pad fluid. The height of the proppant-laden fluid is generally confined to the perforated interval. As long as the perforated interval covers the producing formation, the proppant will remain where it is needed to provide the fracture conductivity (proppant that is placed in a hydraulic fracture that has propagated above or below the producing interval is ineffective). This technique is often used in cases where minimum stress differential exists in the intervals bounding the producing formation. Another example would be where a water-producing zone is below the producing formation and the hydraulic fracture will propagate into it. This method cannot prevent the propagation of the fracture into the water zone but may be able to prevent proppant from getting to that part of the fracture and hold it open (this is also a function of the proppant transport capability of the fracturing fluid).
Other methods for improving fracture conductivity are with encapsulated breakers and are described in a number of patents and publications. These methods involve the encapsulation of the active chemical breaker material so that more of it can be added during the pumping of a hydraulic fracturing treatment. Encapsulating the chemical breaker allows its delayed release into the fracturing fluid, preventing it from reacting too quickly so that the viscosity of the fracturing fluid would have been degraded to such an extent that the treatment could not be completed. Encapsulating the active chemical breaker allows for significantly higher amounts to be added which will result in more polymer degradation in the proppant pack. More polymer degradation means better polymer recovery and improved fracture condu
Echols Brigitte L.
Mitchell Thomas O.
Nava Robin
Schlumberger Technology Corporation
Schoeppel Roger
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