Shale Oil and Gas – 地下能源与流体力学课题组

3. Shale Oil and Gas

Shale reservoirs are dominated by nanoscale pores and contain densely spaced microfractures, so their transport and recovery mechanisms cannot be described by conventional reservoir theories. This direction builds the pore-to-reservoir chain of mass-transport mechanisms for shale systems and distills the engineering bottlenecks of lacustrine shale development.

3.1 Multi-component transport and fluid occurrence in micro/nano pores

We proposed a geometric model that reproduces converging-diverging pore-throat features while remaining simple and general, and used molecular dynamics to study methane diffusion: throats narrower than 20 Å significantly affect the diffusion coefficient, and a critical throat width set by the energy barrier at the throat controls whether methane can diffuse through. Water and CO₂ locally accumulate in throats and reduce methane diffusion (20 mol% water lowers diffusion by about 26%); residual water can completely block throats and interrupt pressure-driven flow. Residual water widens the pore-size range over which diffusion dominates, explaining shale gas production under irreducible-water conditions (SPE Journal 2022, PDF).
Water-vapor sorption experiments on six shale organic-matter samples of different kerogen types and maturities, combined with gas physisorption, FTIR, and small-angle neutron scattering, show that capillary condensation contributes more than 50% of total sorption at RH = 0.95. Sorption strength is controlled mainly by pore-surface properties, with carboxyl-bearing type III organic matter sorbing most strongly; pore volume and specific surface area provide the spatial basis, while strongly hydrophilic functional groups and good pore connectivity widen the effective sorption pore-size range (Journal of Hydrology 2025, PDF).

3.2 Imbibition recovery and REV-scale modeling in densely microfractured reservoirs

For the densely spaced parallel microfractures of continental shale, fine-grid simulation and analytical derivation show that countercurrent imbibition proceeds in two stages: adjacent fractures are independent early on and become strongly coupled by capillarity later. Cumulative oil production follows t^1/2 in both stages but with very different pre-factors, and the late stage dominates recovery. Matrix permeability contributes little in the late stage — the matrix mainly stores fluid; the classical dual-porosity model substantially overestimates fracture-matrix exchange near the displacement front. REV-scale reservoir simulation of densely microfractured systems requires anisotropic relative permeability (SPE Journal 2024, PDF).

3.3 Trapping and startup dynamics of discrete fluid ganglia

Under a quasi-statically increasing external field, capillary-trapped ganglia first undergo irreversible discrete restructuring without moving; once the field reaches the criterion they start to migrate in sequential non-equilibrium jumps. The startup process markedly reduces capillary hysteresis: a static ganglion of fixed volume otherwise has multiple metastable configurations, yet before startup it normalizes to a unique "kick-off" state whose morphology and thermodynamic properties fall in a narrow range independent of volume. This makes the startup criterion analytically solvable and simplifies multiphase flow modeling for gas flooding, foam flooding, and other enhanced recovery techniques (Chemical Engineering Science 2024, PDF).

3.4 Fracturing bottlenecks of lacustrine shale and geology-engineering integration

For the Jurassic lacustrine shale of the Sichuan Basin (about 6×10¹² m³ gas equivalent), we distill three technical bottlenecks: mixed lithofacies and strong heterogeneity restrict fracture propagation and proppant transport, making it difficult to enlarge the stimulated volume; high clay content causes hydration swelling and undermines long-term fracture-network conductivity; and the dynamic evolution of the stress-seepage field in multi-scale, multi-medium, multi-phase reservoirs is insufficiently understood, so existing geology-engineering models are not well adapted. We propose to tackle fracture-network generation in strongly heterogeneous shale, liquid-rock coupled pore-fracture evolution, and multi-medium multiphase flow laws, building an integrated geology-engineering optimization framework (Oil & Gas Geology 2025, in Chinese).