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The Witch Ground Graben is a product of Mid-and Late Cimmerian extensional tectonism. The principal orientation of normal faulting was NNE-SSW during the MidCimmerian (Bajocian to Early Kimmeridgian) and a combination of NW-SE and E-W during the Late Cimmerian (Late Kimmeridgian to Barremian). Block rotation on the dominant Late Cimmerian trends, combined with reactivation of older structural grains formed the fault block traps in the area.Two major depositional systems form the reservoirs of the late Jurassic and early Cretaceous of the Witch Ground Graben, namely, the deltaic and shallow marine systems of the Sgiath and Piper Formations and the deeper water turbiditic sands of the Kimmeridge Clay and Valhall Formations. The transition between the systems is highly diachronous. The turbiditic sandstones are often enclosed within or onlap sealing strata, thus providing a stratigraphic element to many of the traps in the area.A chronostratigraphic framework was established and used as the basis for understanding firstly, the timing of the tectonic episodes responsible for moulding the Witch Ground Graben and secondly, the importance of these events in determining rcscrk, oir sandstone distribution and trap development.

The characterisation of fractured reservoirs and fractured geothermal resources requires a thorough understanding of the geological processes that are involved during fracturing and the host rock rheological properties. The presence or absence of mechanical layering within the rock and the mode of failure substantially control the organization and scaling of the fracture system; subsequent chemical alteration and mineralization can both increase or decrease porosity and permeability. An integration of this understanding using information from outcrop analogues, together with static and dynamic subsurface data,can improve our ability to predict the behaviour of fractured reservoirs across a range of scales.Thematic collection: This article is part of the The Geology of Fractured Reservoirs collection available at: https://www.lyellcollection.org/cc/the-geology-of-fractured-reservoirs

SUMMARYCore supported study of the heterogeneous Ungani dolomite reservoir architecture is driving development drilling and upgrades to field resource estimates. Vuggy connected and macro non-connected pore space was directly measured over a 70m continuous core using 3D structural analysis of CT-scans. Plug density measurements indicate non-connected or sub-140 micron resolution contribution of around 1% to 2.5% (pu) for the tight matrix, but all remaining porosity potentially contributes to oil production. The high resolution core porosity data is vertically repositioned and upscaled to calibrate neutron-density and sonic petrophysically derived porosities which are inadequate to resolve productive zones using conventional reservoir cut-offs. Conditioned resistivity image data correlated exceptionally with directly measured connected porosities. Reservoir properties were extrapolated to all wells across the Ungani field giving field net/gross estimates of up to 63% and porosities over 30% pu in some vuggy and brecciaed zones. The heterogeneity and prolific nature of the uppermost 17m of reservoir had not been previously recognised due to poor log data coverage and access at the casing points. Recent re-analysis of this section at Ungani-3 with Chemostrat ICP-OES-MS analysis of ditch cuttings was instrumental in proposing additional drilling to re-target this zone. Mineralogy analysis is used to calculate rock grain densities and help calibrate neutron-density derived porosity logs over the Ungani field. Up-scaled core porosity correlates well with density and sonic porosity logs. Resistivity logs adjusted for minerology can also be used to predict porosity and support the use of resistivity image logs to identify vuggy zones and estimate porosity at a higher resolution than conventional logging tools. A field static model was populated with three facies distributed over vertical zones according to the distribution encountered in the core porosity analysis and well logs, and iteratively matched to the dynamic pressure data and field production history which exhibits field scale multi-Darcy horizontal permeability and protection from vertical water cut. Further drilling and downhole artificial lift is planned to extend field production rates to 3000 bbls/day. Increased confidence in this regionally developed reservoir is supporting further exploration of undrilled prospects in this immature and under-explored trend

New high resolution geochemical information was acquired for fluids from recent Canning Basin wells and interpreted in context with previous work on fluid typing and correlation by Geoscience Australia (GA). Ungani field oils are interpreted to be derived from the same/very similar clastic source rock, comprising bacterial and marine algal matter deposited under anoxic to sub-oxic conditions, and generated within the peak oil window for a high quality marine source rock. Observed low GOR's are the consequence of both source rock type and gas removal. Liquids from the Yulleroo field are derived from a similar source to the Ungani oils, with the addition of dry gas from a higher maturity and/or more gas prone source, and generated and expelled at slightly higher maturity. The current lean gas condensate phase is the result of the addition of dry gas combined with minimal water washing. In nearly all aspects the Ungani and Yulleroo liquids resemble the L4 family previously attributed by GA to a probable Carboniferous age source. Gas-condensate from the Valhalla North-1 field was derived from a more mature source rock deposited in an oxic environment and containing more gas prone (terrigenous) organic matter. Map based modelling incorporated eleven 1D models in the Ungani-Yulleroo and Valhalla-Asgard region, and a map based burial history and maturity model. The source rock model was derived from the liquid geochemistry results rather than the poor quality source rock potential data gathered to date. Burial history modelling and maturity modelling at the top of the Lower Laurel Carbonate shows maturity for gas expulsion in the main trough and oil to light oil expulsion on the flanks of the basin. Maximum burial in the basin took place immediately prior to the Fitzroy Uplift, resulting in the main phase of oil generation and expulsion taking place around 200Ma.