The Irish Rockall Trough is a frontier area recently opened for hydrocarbon exploration. The Trough, a NE-SW trending Mesozoic-Cenozoic basin, lies in water depths ranging between 500 m and 3000 m. Basin development began as early as the Late Carboniferous and a series of rift episodes continued sporadically throughout the Mesozoic and Tertiary. The most important of these occurred between the Late Jurassic and Early Cretaceous. The post-rift thermal sag phase followed in the Late Cretaceous and Tertiary. The resultant basin is characterized by thinned continental crust, a series of tilted fault blocks and a number of smaller 'perched' basins adjacent to the main basin-bounding faults.This paper presents an assessment of the petroleum prospectivity of the Rockall Trough by focusing on its stratigraphic and structural development, integrating the results from modelling work and providing concise play models. A suite of regional palaeogeographic maps are used to develop a full understanding of the stratigraphic history of the Trough. A structural modelling study is then discussed in which two regional seismic lines are interpreted and flexurally back-stripped. Finally, a source-rock modelling study is presented whereby the timing and extent of oil and gas explusion within the potential kitchen areas are examined. The conclusions of this work are illustrated on a series of play concept diagrams. a frontier challenge.

Exploration within a mature basin poses many challenges, not least how to best utilise resources and time to maximise success and reduce cost. Play-based exploration (PBE) provides a team-based approach to combine key aspects of the petroleum system into an integrated and wholistic view of basin prospectivity. While the PBE methodology is well established, it is not often applied to its full extent on a basin scale. After a period of declining exploration success in parts of the South Australia Cooper-Eromanga Basin, this study was undertaken by a dedicated regional geoscience team with the aim of rebuilding an understanding of the basin, based on first principles and stripping away exploration paradigms. The study area comprises an acreage position in the South Australian and Queensland Cooper-Eromanga Basins covering 70 000 km2 in which Senex Energy has 14 oil fields, has drilled more than 80 exploration wells and has acquired 2D and 3D seismic material. A plethora of proven and emerging plays exist within the acreage ranging from high productivity light sweet oil (Birkhead and Namur Reservoirs) to tight oil (Murta Formation), conventional gas (Toolachee/Epsilon and Patchawarra Formation), tight gas (Patchawarra Formation) and the emerging deep coal play (Toolachee and Patchawarra Coals). Play-based exploration methodologies incorporating the integration of seismic data, log and palynological data, structural analysis, geochemistry, 3D basin modelling, consistent well failure analysis and gross depositional environment maps have allowed the systematic creation of common risk segment maps at all play levels. This information is now actively utilised for permit management, business development, work program creation and portfolio management. This paper will present an example of the work focussing on the southern section of the South Australian Cooper-Eromanga Basin.

Unconventional gas exploration in the Cooper Basin, Australia, has historically concentrated on fracture stimulation of tight gas sandstones within mapped structural closures. In drilling these sandstones, and other clastic reservoir targets, it has been recognised for many years that the Permian coal measures of the Toolachee, Epsilon and Patchawarra Formations record high levels of gas, often in excess of 4000 units, encountered at depths between 2500 and 3500m. Unlike shallower Coal-Seam-Gas reservoirs, which rely on de-pressuristion through de-watering to liberate adsorbed gas from the kerogen surface, deep coals are a "dry" system in which the free gas component is produced via kerogen and fracture permeability. However maintaining a consistent and commercial flow rate from deep coals alone remained enigmatic until the first dedicated fracture stimulation program of deep Permian coals was commenced in the Moomba Field in 2007. Understandings of Permian source-rock reservoirs, the roles of the coal type and rank on sorption capacity and porosity, the influence of effective pressure and depth on coal permeability and the interrelation of coal fracture permeability with in-situ stress and mechanical stratigraphy has now advanced. The deep Permian coal fairway in the Patchawarra and Nappamerri Trough of the Cooper Basin has been defined and mapped using a generative potential approach within a comprehensive 3D basin model. Net coal thicknesses from log electro-facies for 879 wells has been combined with available well maturity, TOC, HI and kerogen kinetic data, and calibrated against corrected temperatures in a basin-wide Trinity retention model which incorporates 14 mapped regional horizons. Play fairways have been overlain with observations of in-situ stress direction and fracture orientations from 3D seismic curvature volumes, FMI data and stress states from Mechanical Earth Models (MEM). Within the basin, this approach has defined a P50 in-place resource of 14.6 TCF of gas and a P10 of 20.7 TCF of gas within the deep coals of the Permian Toolachee, Epsilon and Patchawarra Formations in Senex permits, of which 8-11 TCF is within the North Patchawarra Trough. MEM's have also demonstrated that deep coal seams are consistently in a normal stress state and therefore provide excellent scope for both propagating and constraining vertical fracture growth. Work is now underway to define further those areas, within the mapped resource parameters, which provide the best opportunity to site pilot lateral wells for multi-stage fracture stimulation within deep coals.