Key Takeaways & Executive Findings
- •• Centrifugal hypergravity experiments successfully reproduce stress and fluid pressure gradients, revealing that higher g-levels cause increasingly asymmetric hydraulic fracture propagation. • A theoretical fracture mechanics model shows that when the fluid pressure gradient exceeds the stress gradient, a positive net gradient increases net pressure at the lower fracture tip, promoting downward growth. • The study provides the first experimental verification that the net gradient (difference between fluid pressure and stress gradients) significantly alters hydraulic fracture propagation. • Findings offer practical guidance for optimizing wellbore placement in reservoirs with stress gradients to enhance fracture height growth and stimulated reservoir volume.
Abstract
Hydraulic fracture growth is significantly influenced by the minimum horizontal principal stress gradient and the fracturing fluid pressure gradient. However, these gradients are often neglected in scaled physical modeling experiments due to difficulties in reproducing them. This study uses centrifugal hypergravity to simulate both gradients and investigate their effects on fracture propagation. Artificial mortar specimens (φ200 mm × 400 mm) are fractured under 1g (normal gravity), 50g, and 100g. Results show that compared to 1g, fractures under 50g and 100g exhibit increasingly uneven propagation, with higher g-values leading to greater asymmetry. To interpret this, a theoretical analysis based on fracture mechanics is conducted. When the fluid pressure gradient exceeds the stress gradient, a positive net gradient is generated, increasing net pressure at the lower fracture tip. This raises the stress intensity factor at the lower tip, promoting downward growth. As g increases, the disparity becomes more significant, resulting in greater fracture deviation. In conclusion, this study, for the first time, has verified and explained that the net gradient can change the propagation of hydraulic fractures, providing important guidance for wellbore placement under stress gradients.
1. Introduction
Hydraulic fracturing, recognized as a highly effective reservoir stimulation technique, has been extensively utilized in enhancing the recovery of diverse oil and gas fields, yielding significant outcomes. During hydraulic fracturing operations, developing a complex fracture system in the horizontal direction is crucial, but achieving extensive vertical propagation is equally important, as it increases fracture height, which subsequently enhances pay zone coverage and ultimately maximizes the stimulated reservoir volume [1–3]. Numerous studies have demonstrated that fracture height growth is influenced by multiple factors, including operational parameters, the geomechanical properties of the reservoir, discontinuous interfaces within the formation, and in-situ stress conditions [1,4–7]. Among these, the minimum horizontal principal stress significantly influences the growth and extension of hydraulic fractures [8].
In coal and shale oil reservoirs, this stress is non-uniform and varies with depth in a gradient manner. Stress measurements from coal seams in different regions of China, obtained through hydraulic fracturing or injection/fall-off well tests, indicate that the gradient of the minimum horizontal stress in coal reservoirs ranges from 10 to 36 kPa/m (0.442 to 1.591 psi/ft) [9–11]. Miller et al. [12] conduct cased-hole stress tests in the Canyon Sands formation of the Sonora and Sawyer oilfields, finding that the minimum horizontal in-situ stress gradient in sandstone ranges from 13.80 to 14.59 kPa/m (0.610 to 0.645 psi/ft), with variations depending on depth and lithology.
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Junchi Liu, Yuping Sun, Pingping Liang, Yintong Guo, Yuting He, Wenjie Xu, Duanyang Zhuang, Jinlong Li, Liangtong Zhan, Jianfu Shao, Yunmin Chen (2025). An experimental and theoretical study on the influence of stress gradients on the propagation of hydraulic fractures. SinoTechIntel Verified Research. https://doi.org/10.1016/j.ijmst.2025.08.014
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Frequently Asked Questions
What is the main objective of this study?
The study aims to experimentally and theoretically investigate how stress gradients and fluid pressure gradients influence hydraulic fracture propagation, using centrifugal hypergravity to simulate these gradients.
How were stress gradients simulated in the experiments?
Stress gradients were simulated using centrifugal hypergravity, which generates elevated gravity levels (50g and 100g) to reproduce the in-situ stress and fluid pressure gradients that are difficult to replicate in conventional 1g experiments.
What are the key findings regarding fracture propagation under different g-levels?
Compared to 1g, fractures under 50g and 100g exhibit increasingly uneven propagation, with higher g-values leading to greater asymmetry. This is attributed to a positive net gradient when the fluid pressure gradient exceeds the stress gradient, increasing net pressure at the lower fracture tip and promoting downward growth.
How does the theoretical analysis explain the observed fracture behavior?
The theoretical analysis, based on fracture mechanics, shows that when the fluid pressure gradient exceeds the stress gradient, a positive net gradient is generated, increasing net pressure at the lower tip. This raises the stress intensity factor at the lower tip, promoting downward growth and causing fracture deviation.
What practical implications does this study have for hydraulic fracturing operations?
The study provides important guidance for wellbore placement under stress gradients, helping engineers optimize fracture height growth and stimulated reservoir volume by accounting for the net gradient effects.
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