This paper presents a model for an alternative stimulation technology for naturally fractured tight gas or hot dry rock (HDR) reservoirs in which conventional hydraulic fracturing is relatively inefficient. The model stochastically simulates field-representative natural fractures by processing field data from cores, logs, and other sources. Deformations of these fractures are formulated as functions of fluid pressure inside fractures and in-situ stresses. The permeability enhancement and reservoir growth pattern are then formulated as functions of fracture deformations. While verified, the capability of the model to simulate field representative natural fractures is found to be satisfactory. The model is also applied to central Australian reservoirs to investigate permeability enhancement behavior with respect to various fracture attributes. The production performance of the proposed stimulation technology is assessed, and its potential for applications to tight gas reservoirs is also found to be very high.


Despite a long success history of conventional hydraulic fracturing, in which fractures are initiated and propagated by induced fluid pressure and retained by proppants, there are experiences of treatment failure in some regions, particularly those in the Cooper Basin in central Australia. Investigations suggest that these regions are usually subjected to high deviatoric stresses (the difference between maximum and minimum horizontal in-situ stresses) and pre-existing natural fractures.1 For similar reasons, conventional hydraulic fracturing has also been found to be inefficient in HDR reservoirs - an emerging source of energy. Therefore, while further studies will continue to improve the effectiveness of conventional hydraulic fracture technology, an alternative technology should also be sought, in parallel, that would fundamentally incorporate geological parameters to design effective hydraulic stimulation for the stated conditions. This paper contributes to the evolution, understanding, modeling, and application of such an alternative technology for hydraulic stimulation. This alternative stimulation technology is known by various names, such as low proppant, no-proppant, proppant-free, waterfrac treatments, etc. Recently, it has been called "shear dilation" treatment because of its underlying engineering principles.

Although it is believed that this technology is the first and oldest one, mechanisms behind its success/failure are not yet well understood. Recently, a successful application of this treatment to the East Texas Cotton Valley sand was reported.2 This treatment with large fluid volumes without proppant agents was also found to be successful in the naturally fractured Austin Chalk reservoir. In explaining the success of this stimulation, two hypotheses were made. The first hypothesis is based on the role of shear and normal stresses on natural fractures. The hypothesis assumes that natural mismatches, and the creation of asperities, could occur when shear forces displace the fracture walls out of their original position. Also when it propagates, a hydraulic fracture can open pre-existing natural fractures, faults and planes of weakness by shear slippage.3 This can happen both ahead of fracture tip and around the fracture because of fluid leakoff. The process may induce fracture offset and branching, thus enhancing the permeability of the reservoir. The second hypothesis assumes that the conventional treatments do not clean up efficiently. The waterfrac treatments create a "propped" fracture length that is comparable to the portion, which cleans up during conventional jobs. However, the second hypothesis is beyond the scope of investigation, at least, of the present study.

The shear dilation mechanism is effectively the engineering derivation of the first hypothesis. The physical process of shear slippage and dilation is illustrated in Fig. 1. During fluid injection, the pressure is elevated inside a natural fracture, and thus the stress distribution around the fracture changes. Beyond a threshold pressure, rock material around the fracture fails by "sliding" (Mode-II), instead of "opening" (Mode-I) as considered in conventional hydraulic fracturing. The sliding of two rough fracture surfaces (shear slippage) dilates an aperture normal to the fracture surface. After pumping stops, asperities of the rough fracture surfaces resist their sliding back to the original position, and thus the permeability of a shear dilated fracture is retained. Because of its nature, the shear dilation minimizes the requirement of proppant pumped with the fracturing fluid to keep fractures open after the injection is ceased. The pumping is usually performed at a slow rate so that the opening process of natural fracture networks is not hindered by the creation of a massive single fracture. The overall reservoir permeability is the combined effect of numerous dilated fractures; however, all the fractures are not necessarily dilated.

The success of this stimulation process depends on the existence of favorable natural fracture systems and their favorable response to the stimulation pressure and prevailing in-situ stresses. Generally, strong rocks have rough joints (large), high shear strength, and strong coupling between shearing and hydraulic conductivity, whereas smooth joints in weak rocks have a weak relationship between shearing and conductivity.4 Weak rocks such as shaly sandstones are thus less favorable for the proposed stimulation. Whatever the rock properties, some natural fractures may propagate and change their initial shapes before shear dilation takes place. Also, the fracture network and fluid-flow process have to be considered to evaluate the potential performance of the stimulated reservoir. Therefore, a computationally efficient model has been developed that takes all the above-mentioned complex factors into account to evaluate the response of naturally fractured reservoirs to the proposed hydraulic stimulation. This paper presents the model with its applications to the Cooper Basin in central Australia to study its potential as an alternative stimulation technology for troublesome oil and gas reservoirs.

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