| Citation: | GUO Yunxuan，XU Shang，YANG Dong，et al. Analysis and application of rock breakthrough pressure and fracture pressure[J]. Bulletin of Geological Science and Technology，2026，45（5）：1-10 doi: 10.19509/j.cnki.dzkq.tb20250353
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Rock breakthrough pressure and fracture pressure are two fundamental petrophysical and geomechanical parameters that govern hydrocarbon migration and accumulation, and they also provide important references for evaluating the sealing integrity and safety of caprocks in CO2 geological storage. At present, most existing studies focus on either breakthrough pressure or fracture pressure separately through laboratory experiments and reservoir evaluation. Few publications systematically compare the discrepancies between these two parameters across diverse lithologies or investigate the underlying mechanisms by which they jointly control hydrocarbon migration and accumulation.
From multidisciplinary perspectives including geology, petrophysics, and rock mechanics, this study integrated laboratory core experimental observations and real-world geological cases from sedimentary basins. It systematically analyzed the available testing techniques for breakthrough pressure and fracture pressure, and compared the distribution characteristics of the two parameters among different rock types. Additionally, this study discussed how the configuration of source-reservoir residual pressure relative to the two critical pressures modulates hydrocarbon transport and accumulation processes.
Experimental datasets showed that ① the relationship between breakthrough pressure and fracture pressure differed significantly among different lithologies. For conventional sandstone reservoirs, breakthrough pressure was far lower than fracture pressure. For tight siltstone reservoirs, no fixed magnitude relationship could be generalized between the two parameters. Controlled by nanoscale pore-throat systems and mechanical anisotropy, mudstone and shale commonly exhibited higher breakthrough pressure than fracture pressure. For instance, measured breakthrough pressure ranges of mudstone and shale were 1.22-30.72 MPa and 12.00-68.00 MPa, respectively, while their corresponding fracture pressures fell within 9.83-13.27 MPa and 24.63-39.54 MPa. ② The relative magnitudes of source–reservoir residual pressure, breakthrough pressure, and fracture pressure determined hydrocarbon migration patterns. Hydrocarbon migration could hardly occur when residual pressure was below both thresholds. Hydrocarbons migrated through steady pore-dominated seepage if residual pressure was between breakthrough pressure and fracture pressure. Once residual pressure exceeded fracture pressure but remained below breakthrough pressure, hydrocarbons migrated rapidly along newly generated hydraulic fractures. When residual pressure surpassed both values, pores and fractures jointly constituted the hydrocarbon migration pathways. ③ Basin-scale hydrocarbon migration and accumulation could be divided into two modes: steady-state continuous migration and non-steady-state episodic migration. Under the steady-state mode, hydrocarbons underwent persistent percolation via interconnected pore-fracture networks, which was prevalent in conventional reservoirs and the early-charging stage of tight reservoirs. By contrast, episodic migration occurred within overpressured systems, where hydrocarbons were rapidly charged and accumulated through periodically activated hydraulic fractures.
This study provides theoretical support for understanding hydrocarbon migration patterns and accumulation-enrichment mechanisms in conventional and unconventional reservoirs and for evaluating caprock risks in CO2 geological storage.
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