Key Takeaways & Executive Findings
- •• Two nonlinear flow regimes (Forchheimer and low-velocity nonlinear) are identified in rough fractures under HTHM conditions. • Higher temperatures and lower roughness enhance fluid flow and nonlinearity at low confining pressures. • A modified Forchheimer equation incorporating contact area ratio and thermal expansion coefficient accurately predicts nonlinear flow. • Findings provide critical insights for deep oil/gas extraction and hydraulic fracturing design.
Abstract
Understanding the complex flow behavior along a rough rock fracture under high-temperature, high-stress, and high-seepage pressure (HTHM) coupling conditions is of great significance for optimizing deep resource extraction. This study investigates the complex flow behavior of a single rock fracture under coupled HTHM conditions using a self-developed multi-field coupling experimental system, considering real-time high temperatures (20–90 °C), confining pressures (30–120 MPa), and seepage pressures (5–60 MPa). Experimental results show that as confining pressure increases, two typical nonlinear flow behaviors are observed, which are Forchheimer flow and low-velocity nonlinear flow. The increase in temperature and decrease in roughness significantly promote the fluid flow and enhance the nonlinear relationship between the volumetric flow rate and the hydraulic gradient at lower confining pressures (30 MPa). However, the change in temperature and fracture surface roughness does not affect the nonlinear type of fluid flow. Under a given hydraulic gradient, the influence of temperature and fracture roughness on the volumetric flow rate varies with changes in confining pressure. Additionally, this study considers both the viscous and inertial terms, and a modified Forchheimer equation is proposed using two parameters: the contact area ratio and the thermal expansion coefficient of the rock. The proposed model can effectively predict the nonlinear flow behavior of fluid along rough fractured rocks under varying temperatures and surface roughness. The experimental results and the proposed model provide valuable data and theoretical guidance for deep oil and gas exploration as well as hydraulic fracturing design.
1. Introduction
With the rapid development of global oil and gas industries, petroleum exploration has progressively extended into deep (4500–6000 m) and ultra-deep (>6000 m) formations, which are regarded as critical frontiers for future energy development [1,2]. In China, substantial hydrocarbon resources have been continuously discovered in deep and ultra-deep carbonate reservoirs within the Tarim Basin, Sichuan Basin, and Ordos Basin [3]. According to the evaluation of China's oil and gas resources, the estimated deep and ultra-deep oil and gas resources amount to 67.1 billion tons of oil equivalent, accounting for 34% of China's total oil and gas resources [4]. The exploration and development of deep and ultra-deep oil and gas reservoirs play a crucial role in expanding reserves and ensuring energy security.
As shown in Fig. 1, deep reservoirs are characterized by high temperatures (>100 °C), high in-situ stresses (>100 MPa), and high pressures (>50 MPa), with well-developed fracture networks [5]. Fluid flow behavior in reservoir fractures exhibits significant nonlinearity, yet its underlying mechanisms remain unclear, significantly increasing the development difficulty and cost of deep and ultra-deep oil and gas reservoirs [6]. Compared to the rock matrix, fluid flow behavior in rock fractures is more sensitive to temperature variations, in-situ stress states, and seepage pressure changes [7]. Fractures exhibit higher hydraulic conductivity and serve as the primary pathways for oil and gas storage and migration, directly influencing oil production efficiency. Therefore, a thorough understanding of fluid flow behavior in rough rock fractures under HTHM conditions is of great theoretical and practical significance for the efficient development of deep and ultra-deep large-scale oil and gas fields.
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WANG Bingqi, YANG Wendong, ZHANG Xiang, YANG Yongfei, ZHANG Lei, YAO Jun (2025). Flow behavior of a rough single rock fracture under high-temperature, high-stress, and high-seepage pressure coupling conditions. SinoTechIntel Verified Research. https://doi.org/10.1016/j.ijmst.2025.09.001
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Frequently Asked Questions
What are the main nonlinear flow behaviors observed in rough rock fractures under HTHM conditions?
The study identified two typical nonlinear flow behaviors: Forchheimer flow and low-velocity nonlinear flow, which occur as confining pressure increases.
How do temperature and fracture roughness affect fluid flow in rough fractures?
Higher temperatures and lower roughness significantly promote fluid flow and enhance the nonlinear relationship between volumetric flow rate and hydraulic gradient, particularly at lower confining pressures (30 MPa). However, they do not change the type of nonlinear flow.
What is the modified Forchheimer equation proposed in this study?
The modified Forchheimer equation incorporates two parameters: the contact area ratio and the thermal expansion coefficient of the rock, to account for both viscous and inertial effects, and it effectively predicts nonlinear flow behavior under varying temperatures and surface roughness.
Why is understanding flow behavior in rough fractures important for deep resource extraction?
Fractures are primary pathways for oil and gas storage and migration. Understanding their flow behavior under extreme conditions (high temperature, stress, and seepage pressure) is crucial for optimizing extraction efficiency and hydraulic fracturing design in deep and ultra-deep reservoirs.
What experimental conditions were used in this study?
The study used a self-developed multi-field coupling experimental system with real-time high temperatures (20–90 °C), confining pressures (30–120 MPa), and seepage pressures (5–60 MPa).
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