Method of Increasing the Permeability of a Subterranean Formation by Creating a Multiple Fracture Network

Abstract

The stimulated rock volume (SRV) of a subterranean formation may be increased by pumping viscous fracturing fluid into the formation in a first stage to create or enlarge a primary fracture, decreasing the pumping in order for the fluid to increase in viscosity within the primary fracture, and then continuing to pump viscous fluid into the formation in a second stage. The fluid pumped into the second stage is diverted away from the primary fracture and a secondary fracture is created. The directional orientation of the secondary fracture is distinct from the directional orientation of the primary fracture. The fluid of the first stage may contain a viscosifying polymer or viscoelastic surfactant or may be slickwater.

Description

[0001]This application claims the benefit of U.S. Patent Application Ser. No. 61 / 623,515, filed on Apr. 12, 2012.FIELD OF THE DISCLOSURE[0002]A complex network of fractures may be created within a subterranean formation by pumping fracturing fluid into the formation in discrete stages. The stimulated rock volume (SRV) of the formation is increased by developing an extended area for migration of the fracturing fluid within the formation.BACKGROUND OF THE DISCLOSURE[0003]Hydraulic fracturing is widely used to create high-conductivity communication with a large area of a subterranean formation, thereby allowing for an increased rate of oil and gas production. The stimulation process enhances the permeability of the formation in order that entrapped oil or gas may be produced.[0004]During hydraulic fracturing of low permeability formations (i.e. such as less than 1.0 md), a fracturing fluid is pumped at high pressures and at high rates into the wellbore penetrating the subterranean form...

AI Technical Summary

Benefits of technology

[0019]The stimulated rock volume (SRV) of a subterranean formation subjected to a hydraulic fracturing treatment may be increased by pumping the fracturing fluid into stages to provide a wider distribution fracturing pattern and an extended area for migration of the fluid. The method uses a high shear thinning fluid, i.e., a fluid having high viscosity at low shear rates, which may be diverted into secondary fractures. The viscosity of the fluid is typically greater than about 10,000 cP at a shear rate of 0.01 sec−1.

Problems solved by technology

After the viscosity of the fluid has been reduced, removal of the polymer is often difficult, often times resulting in residual polymer being left on the face of the formation and within the proppant pack.

This causes clogging of the pores of the formation and proppant pack.

Slickwater fluids typically do not contain a viscoelastic surfactant or viscosifying polymer but do contain a sufficient amount of a friction reducing agent to minimize tubular friction pressures.

This often results in the development of greater created fracture area from which hydrocarbons may flow into.

In some shale formations, an excessively long primary fracture often results along the minimum stress orientation.

In most instances, primary fractures dominate and secondary fractures are limited.

Production of hydrocarbons from the fracturing network created by such treatments is limited by the low SRV.

Slickwater fracturing more commonly in shale formations create complex fracture networks near the wellbore and are generally considered to be inefficient in the opening or creation of complex network of fractures farther away from the wellbore.

However, the secondary fractures created by the operation are near to the wellbore where the surface area is increased.

While SRV is increased in slickwater fracturing, production is high only initially and then drops rapidly to a lower sustained production since there is little access to hydrocarbons far field from the wellbore.

Like slickwater fracturing, conventional fracturing operations typically render an undesirably lengthy primary fracture.

While slightly more secondary fractures may be created farther from the wellbore using viscous fluids versus slickwater, fluid inefficiency, principally exhibited by a reduced number of secondary fractures generated near the wellbore, is common in conventional hydraulic fracturing operations.

This decreases the efficiency of the stimulation operation.

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