Modelling Geothermal Energy Extraction from Low-Enthalpy Oil and Gas Fields Using Pump-Assisted Production: A Case Study of the Waihapa Oilfield

Rohit Duggal, John Burnell, Jim Hinkley, Simon Ward, Christoph Wieland, Tobias Massier () and Ramesh Rayudu
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Rohit Duggal: School of Engineering and Computer Science, Victoria University of Wellington, Wellington 6011, New Zealand
John Burnell: GNS Science Ltd., Lower Hutt 5011, New Zealand
Jim Hinkley: School of Engineering and Computer Science, Victoria University of Wellington, Wellington 6011, New Zealand
Simon Ward: Ian R Brown Associates Ltd., Lower Hutt 5010, New Zealand
Christoph Wieland: Faculty of Engineering Sciences, University of Duisburg-Essen, 45141 Essen, Germany
Tobias Massier: TUMCREATE Ltd., Singapore 138602, Singapore
Ramesh Rayudu: School of Engineering and Computer Science, Victoria University of Wellington, Wellington 6011, New Zealand

Sustainability, 2025, vol. 17, issue 10, 1-33

Abstract: As the energy sector transitions toward decarbonisation, low-to-intermediate temperature geothermal resources in sedimentary basins—particularly repurposed oil and gas fields—have emerged as promising candidates for sustainable heat and power generation. Despite their widespread availability, the development of these systems is hindered by gaps in methodology, oversimplified modelling assumptions, and a lack of integrated analyses accounting for long-term reservoir and wellbore dynamics. This study presents a detailed, simulation-based framework to evaluate geothermal energy extraction from depleted petroleum reservoirs, with a focus on low-enthalpy resources (<150 °C). By examining coupling reservoir behaviour, wellbore heat loss, reinjection cooling, and surface energy conversion, the framework provides dynamic insights into system sustainability and net energy output. Through a series of parametric analyses—including production rate, doublet spacing, reservoir temperature, and field configuration—key performance indicators such as gross power, pumping requirements, and thermal breakthrough are quantified. The findings reveal that: (1) net energy output is maximised at optimal flow rate (~70 kg/s for a 90 °C reservoir), beyond which increased pumping offsets thermal gains; (2) doublet spacing has a non-linear impact on reinjection cooling, with larger distances reducing thermal interference and pumping energy; (3) reservoirs with higher temperatures (<120°C) offer significantly better thermodynamic and hydraulic performance, enabling pump-free or low-duty operations at higher flow rates; and (4) wellbore thermal losses and reinjection effects are critical in determining long-term viability, especially in low-permeability or shallow fields. This work demonstrates the importance of a coupled, site-specific modelling in assessing the geothermal viability of petroleum fields and provides a foundation for future techno-economic and sustainability assessments. The results inform optimal design strategies and highlight scenarios where the geothermal development of oil and gas fields can be both technically and energetically viable.

Keywords: pump-assisted production; energy extraction; depleted oil and gas fields; geothermal energy; wellbore–reservoir model (search for similar items in EconPapers)
JEL-codes: O13 Q Q0 Q2 Q3 Q5 Q56 (search for similar items in EconPapers)
Date: 2025
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