Methodology for assessing original gas in place and estimated ultimate recovery from a tight marine formation using hydraulic fracture stimulation modelling

Abstract

Operators in Australia are currently exploring similar geological settings to the tight marine unconventional petroleum systems of the United States, in the hope of emulating the North American success. This study sets out the methodology and models required to undertake an analysis of a tight marine source and reservoir rock to estimate its production potential, with particular attention given to modelling the required hydraulic fracture stimulation. The project target formation is the tight marine Log Creek Formation, which forms the source rock to the overlying proved Gilmore Gas Field in the Adavale Basin in Central Queensland. The Marcellus Formation in the Appalachian Basin in the Northeastern United States is an assumed analogue to the Adavale Basin; data from the Marcellus Formation was used when unavailable for the Adavale Basin. Initially, formation evaluation was undertaken to determine key parameters such as total organic carbon (TOC), mineralogy and stress regime. Once the formation had been characterised, a fracture stimulation model was built to determine the hydraulic fracture stimulation treatment design, which optimised the lateral landing depth, hydraulic fracture spacing, conductivity and half‐length. In particular, it is important to determine the lateral landing depth and fracture half‐length with confidence, as they will define the stimulated reservoir volume (SRV), which sets the upper boundary on original gas in place (OGIP) and estimated ultimate recovery (EUR) of gas. OGIP was estimated using a probabilistic model incorporating an adjustment for absorbed gas volume. Finally, a reservoir simulation was undertaken using a single well composite multi‐fracture model to obtain EUR.