Impermeable

Key Takeaways

• Capillary entry pressure as the mechanism of seal integrity in impermeable rocks explains how a low-permeability formation can maintain a hydrocarbon column beneath it even though the formation technically has some small but finite permeability, because the capillary pressure required to displace the water that saturates the seal pore throats with a non-wetting hydrocarbon phase may exceed the buoyancy pressure of the hydrocarbon column even for the largest feasible structural trap: the capillary entry pressure of a seal is related to the pore throat radius r, the interfacial tension sigma between oil (or gas) and brine, and the contact angle theta by the Young-Laplace equation: Pc = 2 x sigma x cos(theta) / r; a shale seal with pore throat radii of 10-100 nanometers (100-1,000 times smaller than the pore throats of a typical reservoir sandstone) has a capillary entry pressure of 500-5,000 psi for oil-brine at standard conditions, corresponding to the buoyancy pressure of an oil column of 1,000-10,000 feet, far larger than most structural traps; the seal integrity assessment for a prospective trap therefore compares the maximum hydrocarbon column height that the buoyancy pressure drives (determined by the trap geometry and the density difference between hydrocarbons and brine) against the seal's capillary entry pressure (measured on core samples by mercury injection capillary pressure tests that simulate the oil-water displacement at reservoir stress conditions); if the buoyancy pressure at the crest of the structure exceeds the capillary entry pressure of the weakest part of the seal, the trap is at its maximum column height (a "full" or "just-full" trap), and additional charge would leak out through the seal rather than increasing the column height.
• Hydraulic fracturing of impermeable shales (the foundation of the unconventional oil and gas revolution) exploits the inherent impermeability of shale formations by creating high-permeability fracture pathways that allow the hydrocarbons stored in the nanopore network of the shale matrix to flow to the wellbore at commercial rates: without hydraulic fracturing, the matrix permeability of productive shale reservoirs (Barnett, Marcellus, Permian Basin Wolfcamp, Haynesville, Eagle Ford) typically ranges from 10 to 1,000 nanodarcies (10^-8 to 10^-5 millidarcies), giving a skin-free production rate of micro-barrels per day per well from the matrix alone; hydraulic fractures create conductive fractures with widths of 0.1-3 millimeters and propped permeabilities of 10,000-100,000 millidarcies (using ceramic or resin-coated proppant), effectively converting the well from accessing only the matrix permeability near the wellbore to accessing the matrix permeability everywhere within the drainage area of the fracture network (drainage distances of 100-500 feet from each fracture); the impermeable nature of the shale matrix also defines the production decline behavior of shale wells, because once the fractures drain the oil and gas stored in the connected pore space near the fractures, continued production depends on the extremely slow diffusion of hydrocarbons through the low-permeability matrix from the unstimulated interwell rock toward the fractures, producing the characteristic steep initial decline followed by the long, low-decline tail that characterizes shale well production profiles.
• Impermeable cap rock seal failure mechanisms determine the risks of hydrocarbon column breaching and spillage from petroleum traps, with seal failure occurring through one of several distinct physical processes depending on the seal rock type and the stress history of the trap: hydraulic fracturing of the seal (when the buoyancy pressure at the crest of the structure equals the minimum horizontal stress in the seal rock plus the tensile strength of the seal, creating a fracture that allows hydrocarbons to migrate upward through the seal) is the ultimate failure mode for hard, brittle seal rocks including tight carbonates and cemented sandstones; capillary invasion (when the hydrocarbon column height grows to the point where the buoyancy pressure exceeds the seal's capillary entry pressure, allowing gas or oil to displace the water from the largest pore throats and migrate through them into the overlying formation) is the dominant failure mode for ductile shale seals that deform before fracturing; fault reactivation and seal bypass (when tectonic stress changes or reservoir pressure drawdown from production reactivates a pre-existing fault that intersects the seal, creating a permeable pathway that bypasses the intact seal and allows hydrocarbons to migrate laterally along the fault plane) is the dominant concern for structurally complex traps in tectonically active basins; understanding these failure mechanisms is critical for both exploration risk assessment (evaluating the probability that a mapped trap retains a commercial hydrocarbon column) and for CO2 storage site selection (evaluating whether the impermeable cap rock above a saline aquifer CO2 storage reservoir will maintain integrity over the 1,000-year time frame relevant to climate mitigation).
• Relative impermeability in drilling and completion operations describes the practical impermeability of certain formations to specific fluid systems under the conditions encountered in the wellbore, as distinct from the absolute permeability concept in reservoir engineering: a formation that is effectively impermeable to water-based drilling fluid (WBM) because its pore throats are smaller than the colloidal particles in the mud and the capillary entry pressure for water into the oil-wet pore system exceeds the overbalance drilling pressure may be readily invaded by oil-based mud filtrate (OBM) because the lipophilic OBM is the wetting phase for the oil-wet rock and capillary forces assist rather than resist its invasion; conversely, a formation that appears impermeable to mud filtrate invasion on a wireline resistivity log may be producing gas at commercial rates because the gas (in a gas-wet formation) enters the pore system at pressures far below the capillary entry pressure for the aqueous phase; the "apparent impermeability" of a formation to a specific fluid at a specific pressure and wettability condition is therefore a system property (fluid-rock-pressure combination) rather than an absolute property of the rock alone, requiring that the permeability description specify the fluid and conditions under which the measurement was made; in completion engineering, this relative impermeability concept governs the selection of fracturing fluid (water-based versus oil-based versus energized with CO2 or N2) to minimize fracturing fluid invasion damage into the productive matrix of an impermeable shale reservoir.
• Permeability measurement and characterization of tight and impermeable formations requires specialized laboratory techniques that differ fundamentally from the standard Darcy flow permeameter used for conventional reservoir samples: pulse decay permeometry (also called transient pressure decay or pressure pulse method) is the standard laboratory technique for measuring permeability in the range of 0.001-100 microdarcies, using the decay rate of a small pressure pulse applied to one end of a sealed core plug as the fluid slowly equilibrates through the sample; gas expansion permeometry measures the permeability of ultra-tight samples in the nanodarcy range by recording the pressure-volume relationship as gas from a high-pressure reservoir expands through the sample and equalizes with a low-pressure reservoir, with the expansion rate being proportional to the sample permeability; crushed rock (GRI) method permeability measurement grinds a core sample to small particles to measure the matrix permeability of a shale that may contain natural fractures in core plug scale that would give a misleadingly high permeability if the intact core plug were measured; nuclear magnetic resonance (NMR) permeability estimation from the T2 relaxation time distribution provides a non-destructive permeability estimate for tight formations using empirical correlations (Timur-Coates or SDR models) between pore size distribution (reflected in T2) and permeability, without requiring fluid flow through the sample; these specialized measurement techniques are necessary because the standard core analysis method (flowing gas through a core plug under a pressure gradient and calculating permeability from Darcy's law) is impractically slow for samples with permeabilities below 0.01 millidarcies due to the very long equilibration times required.