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Why are the only commercial hydrocarbon discoveries in Lower Triassic and Permian sediments of the western margin of Australia restricted to the Perth Basin and the Petrel Sub-basin? Recent regional analysis by Carnarvon Petroleum has sought to address some key questions about the Lower Triassic Locker Shale and Upper Permian Chinty and Kennedy formations petroleum systems along the shallow water margin of the Carnarvon and offshore Canning (Roebuck/Bedout) basins. This paper aims to address the following questions:Source: Is there evidence in the wells drilled to date of a working petroleum system tied to the Locker Shale or other pre-Jurassic source rocks? Reservoir: What is the palaeogeography and sedimentology of the stratigraphic units and what are the implications for the petroleum systems?The authors believed that a fresh look at the Lower Triassic to Upper Permian petroleum prospectivity of the North West Shelf would be beneficial, and key observations arising from the regional study undertaken are highlighted:Few wells along a 2,000 km area have drilled into Lower Triassic Locker Shale or older stratigraphy. Several of these wells have been geochemically and isotopically typed to potentially non Jurassic source rocks. The basal Triassic Hovea Member of the Kockatea Shale in the Perth Basin is a proven commercial oil source rock and a Hovea Member Equivalent has been identified through palynology and a distinctive sapropelic/algal kerogen facies in nearly 16 wells that penetrate the full Lower Triassic interval on the North West Shelf. Samples from the Upper Permian, the Hovea Member Equivalent and the Locker Shale have been analysed isotopically indicating –28, –34 and –30 delta C13 averages, respectively. Lower Triassic and Upper Permian reservoirs are often high net to gross sands with up to 1,000 mD permeability and around 20% porosity. Depositional processes are varied, from Locker Shale submarine canyon systems to a mixed carbonate clastic marine coastline/shelf of the Upper Permian Chinty and Kennedy formations.

The Lower to Middle Triassic mixed carbonate–clastic system in the Northern Carnarvon Basin is poorly understood relative to the stratigraphically younger Jurassic play systems. Few well penetrations and a lack of quality seismic data have deterred exploration of this interval for many years. In recent times, the Lower to Middle Triassic source potential has been comprehensively de-risked within the Roebuck Basin, with subsequent implications across the entire North West Shelf of Australia, opening up the possibility of an entirely new regional play fairway. This paper focuses on the Candace Terrace, on the southern flank of the Carnarvon Basin, where seismic observations and interpretations of Lower to Middle Triassic submarine canyon systems have been made. The stratigraphic elements of this play interval can now be more clearly observed with the aid of 3D seismic data. Amplitude extractions show the internal geometries of these highly erosive systems are sinuous, compensating flows. The aims of this paper are to postulate the stratigraphy of the Lower to Middle Triassic on the Candace Terrace, highlight the tectonic cause of the canyon systems and discuss the prospectivity of the observed turbidite features.

The share of global hydrocarbon production from ‘aging’ assets is increasing, whereas global demand for energy continues to increase at 1–2% per year (IEA 2019). In 2018, the International Energy Agency estimated the global average production decline at 4% per annum (Gould and McGlade 2018). Production from many of Australia’s established basins, such as the Cooper–Eromanga basin and the North West Shelf, is dominated by aging assets. To arrest this decline, actions must be taken to meet global demand for oil and gas, sustain production and underpin shareholder expectations of a return on their investment. Arresting field decline is a multifaceted problem. A single fix, whether technological or operational, will not maximise production or asset value. Any project to arrest field decline, grow production or (re)develop a field must be considered in its entirety, as an integrated system, by a multidisciplinary team. In addition, and critical to success, the required outcome must be clearly established and committed to by field owners, consultants and staff assigned to the project. This paper demonstrates how using a committed, outcome-focused approach, an integrated project team identified field redevelopment opportunities that significantly increased estimated ultimate recovery in an aging oilfield (that had already produced more than 70–80% of the developed resource) in the Cooper–Eromanga basin, South Australia. Factors critical to success were: (1) a commitment to look at all aspects of the field, from geology and geophysics, through the completion, well and field performance and operational infrastructure to identify development opportunities; (2) an ability to be agile, cycling quickly through the workflow as new information became available; (3) dedicated resources, clear communication and a commitment to integrated work across consultant and staff resources; and (4) management support.

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