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The success story of a shale-gas reserve development in the United States is triggering a strong industry focus towards similar plays in Australia. The Cooper Basin (located at the border of South Australia and Queensland) and the Otway Basin (extending both onshore and offshore South Australia and Victoria) could be prime targets to develop shale-gas projects. The Cooper Basin, a late-Carboniferous to mid-Triassic basin, is the largest onshore sedimentary basin producing oil and gas from tight conventional reservoirs with low permeability. Fracture stimulation programs are used extensively to produce the oil and gas. Furthermore, new exploration strategies are now targeting possible commercial gas hosted in low-permeability Permian shale units. To maximise production, the development of shale-gas prospects requires a good understanding of the: 1. structure of the reservoirs; 2. mechanical properties of the stratigraphy; 3. fracture geometry and density; 4. in-situ stress field; and, 5. fracture stimulation strategies. In this study, we use a combination of seismic mapping techniques–including horizon and attribute mapping, and an analysis of wellbore geophysical logs–to best constrain the existing fracture network in the basins. This study is based on the processing and analysis of a 3D seismic cube–the Moomba Big Lake survey–which is located in the southwestern part of the Cooper Basin. This dataset covers an area encompassing both a structurally complex setting in the vicinity of a major fault to the SE of the survey, and an area of more subtle deformation corresponding to the southernmost part of the Nappamerri Trough. Structural fabrics trending ˜NW–SE and NE–SW, which are not visible on the amplitude seismic data, are revealed by the analysis of the seismic attributes–namely a similarity (equivalent to a coherency cube), dip steering and maximum curvature attributes. These orientations are similar to those of natural fractures mapped from borehole images logs, and can therefore be interpreted as imaging natural fractures across the Moomba-Big Lake area. This study is the first of its kind able to detect possible fractures from seismic data in the Cooper Basin. The methodology developed here can offer new insights into the structure of sedimentary basins and provide crucial parameters for the development of tight reservoirs. In parallel, a tentative forward model of the generation of a fracture network following a restoration of the Top Roseneath horizon was carried out. The relatively good correlation between the fracture orientations generated by the model and the fractures mapped from geophysical data shows that fractures in the Moomba-Big Lake area may have formed during either a N–S compressive principal horizontal stress, or an E–W compressive principal horizontal tectonic stress regime. In addition, the orientations of the fracture interpreted through this study are also compatible with a generation under the present day stress regime described in this part of the basin, with an maximal horizontal stress trending E–W.

The Montney Formation of the Western Canadian Sedimentary Basin has emerged as one of the most prolific unconventional resource plays in the North American unconventional space. The authors propose a novel method to better understand the failure mechanics associated with hydraulic fracturing through laboratory testing under true triaxial conditions. This adds essential fundamentals with respect to upscaled field hydraulic fracturing operations in the formation. A representative source rock block recovered from outcrop was prepared into a cube and hydraulically fractured in the laboratory under true triaxial stress conditions. Field outcrop mapping of this quarry has confirmed that samples collected are of the same geological time and spatially equivalent to the source rock (Zelazny et al. 2018). This novel laboratory experiment mimics a single stage open hole hydraulic fracturing using a slickwater system, composed of surfactant, friction reducer, and biocide as the injection fluid. Micro-computed tomography (μCT) scans were used to identify the presence of preexisting fractures and bedding planes. A mini-well was drilled to the center of the cube, parallel to the direction of the minimum principal stress (σ3) and along the strike of the bedding planes, such that there is a 5 mm long down-hole open cavity. The existing true triaxial test system at the University of Toronto was retrofitted to accommodate a custom designed mini-packer system. Stresses were applied hydrostatically, and then differentially until the stress regime, replicating the field observed reservoir depth at about 2 km depth, was reached. The bottom hole was subsequently pressurized by pumping the injection fluid through the mini-packer. The test was numerically modeled in three-dimensions using the hybrid finite-discrete element method (FDEM) with the mechanical properties input determined through a series of standard laboratory rock mechanics tests discussed within. Post-test μCT of the tested cube revealed a fracture trace, and scan contrast was enhanced by injecting the cube with 5% wt potassium iodide solution. Interestingly, the highest fluid pressure recorded is slightly higher than σ3 whilst the plane of failure is normal to the intermediate principal stress (σ2) direction, which is parallel to the bedding planes. The results of the mechanical tests and hydraulic fracturing under true triaxial stress conditions reveal the significance and dominance of the macroscopic features and material anisotropy in dictating the overall strength and fracture plane orientation. Features which were unaccounted for in classical reservoir mechanics and the numerical model simulation, resulted in higher than predicted fracture initiation and propagation pressures than the laboratory experiment. This laboratory test approach allows a convenient and flexible method to capture the influence of the reservoir stress regime and its interaction with the sample anisotropy. Coupled with numerical simulations that encompass such features, this framework can benefit the industry by reproducing typical behavior observed in the field; thus, enhancing, improving, and increasing the efficiency of hydrocarbon recovery.

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