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Middle Cambrian sediments in the southern Georgina Basin contain multiple organic-rich source rocks and have been suggested to be prospective for both conventional and unconventional hydrocarbons. We present new geomechanical data collected from the middle Cambrian Arthur Creek Formation and Thorntonia Limestone in four wells (Baldwin 1, MacIntyre 1, Owen 2, Todd 1) in the southern Georgia Basin, and compare the data to mineralogical and geochemical datasets. Geomechanical test intervals were selected to allow geomechanical test results to be directly compared with the mineralogical and geochemical datasets (X-Ray Diffraction, HyLogger and organic geochemistry). Approximately 25 m of core was tested for unconfined compressive strength (UCS) using the scratch-testing technique, and results indicate values in the range of 60–150 MPa. Triaxial testing was also conducted to measure the poroelastic properties of core, and results indicated that Young's modulus is generally in the range of 45–67 GPa. UCS and Young's modulus are positively correlated and increase with depth through the prospective Arthur Creek Formation. The mechanical properties of the tested core are relatively indurated and stiff compared with young sedimentary rocks and broadly similar to proven shale gas plays in Australia and internationally. Mineralogically, the Georgina Basin rocks tested have lower clay contents than rocks from other Australian and international basins but no clear correlation was observed between geomechanical properties and mineralogy, suggesting that multiple factors contribute to the poroelastic and strength parameters. For example, parameters such as sonic velocity and porosity are weakly correlated to rock strength. Geomechanical data can be used alongside other datasets (e.g. sedimentological, geophysical and structural data) to better inform predictions of hydrocarbon prospectivity. Middle Cambrian rocks from the Georgina Basin, Australia are prospective for conventional and unconventional hydrocarbons. Rock mechanical tests are conducted to determine how the organic-rich sediments might respond to stimulation. Mechanical analyses are evaluated alongside mineralogical, geochemical and well-log data to assess controls on rock strength properties. Geomechanical behaviour is complex and appears to be driven by multiple factors. [ABSTRACT FROM AUTHOR]

The onshore Georgina Basin in northern Australia is prospective for unconventional hydrocarbons; however, like many frontier basins, it is underexplored. A well-connected hydraulic fracture network has been shown to be essential for the extraction of resources from the tight reservoirs that categorise unconventional plays, as they allow for economic flows of fluid from the reservoir to the well. One of the fundamental scientific questions regarding hydraulic stimulation within the sub-surface of sedimentary basins is the degree to which local and regional tectonic stresses act as a primary control on fracture propagation. As such, an understanding of present-day stresses has become increasingly important to modern petroleum exploration and production, particularly when considering unconventional hydrocarbon reservoirs. This study characterises the regional stress regime in the Georgina Basin using existing well data. Wellbore geophysical logs, including electrical resistivity image logs, and well tests from 31 petroleum and stratigraphic wells have been used to derive stress magnitudes and constrain horizontal stress orientations. Borehole failure features interpreted from wellbore image and caliper logs yield a maximum horizontal stress orientation of 044°N. Integration of density log data results in a vertical stress gradient of 24.6 MPa km–1. Leak-off and mini-fracture tests suggest that this is the minimum principal stress, as leak-off values are generally shown to be at or above the magnitude of vertical stress. The maximum horizontal stress gradient is calculated to be in the range of 31.3–53.9 MPa km–1. As such, a compressional stress regime favouring reverse/reverse–strike-slip faulting is interpreted for the Georgina Basin. [ABSTRACT FROM AUTHOR]

The Georgina Basin is a Neoproterozoic–Paleozoic basin that spans parts of the Northern Territory and Queensland in northern Australia. The basin is prospective for petroleum, phosphate and base metals (copper, lead and zinc). The Dulcie and Toko synclines in the southern part of the basin are prospective for petroleum, where a thick Cambro-Ordovician succession of marine carbonates hosts several source rocks and associated oil and gas shows. The key source rock units occur within the middle Cambrian Narpa Group, including both the Thorntonia Limestone (Series 2 and 3) and the Arthur Creek Formation (Series 3). The base of the Arthur Creek Formation is characterised by organic-rich ‘hot’ shales (associated with a prominent gamma spike in well logs) that have been targeted by petroleum explorers for both conventional and unconventional oil and gas. For this study, hyperspectral logging data collected by HyLogger™ instruments were evaluated from 13 wells in the southern Georgina Basin, including petroleum, mineral and stratigraphic wells. Formation boundaries are commonly (but not always) characterised by distinctive changes in mineralogy, as determined by spectral and X-ray diffraction data. Key source rock units in the southern Georgina Basin were characterised and mapped in terms of their mineralogy, and other spectral properties (e.g. Short-Wave Infrared (SWIR) reflectance and spectral contrast). Interpretation of the hyperspectral data alongside wireline log data supports the differentiation of two successions within the Arthur Creek Formation that are each characterised by basal organic-rich shales, previously distinguished on the basis of biostratigraphic and well-log data. The older succession in the Dulcie Syncline is spectrally characterised as being quartz and carbonate dominated. The younger succession, distributed across the eastern part of the Dulcie Syncline and fully across the Toko Syncline, is spectrally characterised as quartz and carbonate dominated, with variable white-mica contributions. Key associations are observed between the HyLogger mineralogy and geophysical-log data. Peaks in the gamma log intensity in the middle Cambrian sediments commonly correspond to elevated measured total organic carbon contents, decreased carbonate contribution, SWIR reflectance and spectral contrast, and relatively increased proportions of white micas and quartz. This study demonstrates that HyLogging data can provide an improved understanding of the sedimentological, mineralogical and diagenetic characteristics, as well as associated spatial heterogeneity, of prospective hydrocarbon formations in sedimentary basins. [ABSTRACT FROM PUBLISHER]