Numerical Study of Fluid Loss Impact on Long-Term Performance of Enhanced Geothermal Systems under Varying Operational Parameters
Yongwei Li1, Kaituo Jiao2,*, Dongxu Han3, Bo Yu2, Xiaoze Du1
1 Key Laboratory of Power Station Energy Transfer Conversion and System (North China Electric Power University), Ministry of Education, Beijing, 102206, China
2 School of Petroleum Engineering, Yangtze University, Wuhan, 430100, China
3 School of Mechanical Engineering, Beijing Institute of Petrochemical Technology, Beijing, 102617, China
* Corresponding Author: Kaituo Jiao. Email: 
(This article belongs to the Special Issue: Computer Modeling of Fluid Seepage in Porous Media with Ultra-low Permeabilities)
Computer Modeling in Engineering & Sciences https://doi.org/10.32604/cmes.2025.073239
Received 13 September 2025; Accepted 13 November 2025; Published online 03 December 2025
Abstract
The permeability contrast between the Hot Dry Rock (HDR) reservoir and the surrounding formations is a key factor governing fluid loss in Enhanced Geothermal Systems (EGS). This study thus aims to investigate its impact on system performance under varying operating conditions, and a three-dimensional thermo–hydro–mechanical (THM) coupled EGS model is developed based on the geological parameters of the GR1 well in the Qiabuqia region. The coupled processes of fluid flow, heat transfer, and geomechanics within the reservoir under varying reservoir–surrounding rock permeability contrasts, as well as the flow and heat exchange along the wellbores from the reservoir to the surface are simulated. Then, the influence of permeability contrast, production pressure, injection rate, and injection temperature on fluid loss and heat extraction performance over a 35-year operation period is quantitatively assessed. The results show that increasing the permeability contrast effectively suppresses fluid loss and enhances early-stage heat production, but also accelerates thermal breakthrough and shortens the stable operation period. When the contrast rises from 1 × 10³ to 1 × 10
5, the cumulative fluid loss rate drops from 54.34% to 0.23%, and the total heat production increases by 132%, although the breakthrough occurs 5 years earlier. Meanwhile, higher production pressure delays thermal breakthrough and slows transient temperature decline, but exacerbates fluid loss and reduces heat production power. For instance, raising the pressure from 17 to 21 MPa increases the fluid loss rate from 33.17% to 54.34% and reduces average annual heat production power from 25.43 to 14.59 MW
th. In addition, increasing the injection rate (46 to 66 kg/s) lowers fluid loss rate but brings forward thermal breakthrough by 9 years and causes a 41 K temperature drop at the end of operation. Notably, under high fluid loss, the dynamic response pattern of heat production power shifts from a temperature-dominated “stable–breakthrough–decline” mode to a novel “rising–breakthrough–decline” mode jointly governed by both production temperature and flow rates. These findings provide theoretical support and engineering guidance for improving EGS performance.
Keywords
Enhanced geothermal systems; THM coupling model; fluid loss; heat extraction
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