Maximising gas production from late-life assets: a case study from the Snapper Field, Gippsland Basin

Abstract

Discovered in 1968 and developed in 1981, the Snapper Field has supplied oil and gas to Australia’s eastern seaboard for over 40 years. The field consists of a broad northeast–southwest trending faulted anticline within the Eocene and Paleocene sands of the Latrobe Group. Reserves in 2023 are within the shallowest reservoir interval – the N-1 – which had an original gas in place of approximately 3.8 Tcf. Pressure and wireline log data acquired during exploration and development suggested that the Snapper Field was horizontally and vertically well connected, and it was expected that individual intervals within the N-1 reservoir would water-out sequentially from the bottom to the top of the reservoir during production. As a result, the risk of water over-running gas, and bypassed gas was considered to be low. Production and logging results in 2017 proved otherwise, prompting a period of renewed study from 2019 to 2022. This paper focusses on the culmination of this work effort: construction of a new static geological model and dynamic simulation model, which was built upon and expanded previous models completed prior to 2019. The insights from this study have demonstrated the importance of ongoing and regular reservoir surveillance and the significant value that the construction of new static and dynamic models can add to late-life oil and gas fields. This study showed a later end of field life than previous estimates and an increase in reserves by up to ~20% through the optimisation of future work-over programs. The Snapper Field is owned by ExxonMobil (50%) and Woodside Energy (50%) and is operated by ExxonMobil.