Trapped Oil

Key Takeaways

• Capillary number is the dimensionless ratio that quantifies whether a particular displacement process can mobilize trapped oil — defined as Nc = mu_w × v / sigma where mu_w is the displacing fluid viscosity, v is the Darcy velocity, and sigma is the oil-water interfacial tension; in conventional waterflooding with capillary numbers in the range of 10^-7 to 10^-6 (limited by the low water viscosity, modest flow velocities, and 20-30 mN/m IFT), trapped oil saturations of 25 to 40 percent are typical; to mobilize trapped oil and reduce residual saturation toward 5 to 10 percent, capillary numbers of 10^-3 or higher must be achieved, requiring either ultralow IFT (surfactant flooding reducing IFT to 10^-3 mN/m yields Nc increase of 4 to 5 orders of magnitude) or much higher viscosity (polymer flooding with viscosity 10 to 30 cP gives 10x to 30x increase) or higher velocity (achievable only locally near production wells); the capillary desaturation curve plotting residual oil saturation versus capillary number shows a critical Nc threshold (typically 10^-4 to 10^-3) above which residual saturation drops sharply, providing the design target for any chemical EOR project.
• Reservoir wettability strongly affects the trapped oil saturation and the EOR mechanisms applicable to a given reservoir — water-wet rocks (where water preferentially coats the mineral surfaces and oil exists as central pore-filling globules) typically have lower trapped oil saturations after waterflood (15 to 30 percent) because the water film provides continuous flow paths through the pore network; oil-wet rocks (where oil coats the mineral surfaces and water exists as separate phase pockets) have much higher trapped oil saturations (35 to 50 percent) because water cannot effectively displace oil from the pore wall surfaces; mixed-wet rocks (different surfaces wet by different fluids) show intermediate behavior; carbonate reservoirs are predominantly oil-wet to mixed-wet and have higher trapped oil saturations than the typically water-wet sandstone reservoirs, making carbonate EOR more challenging and creating the need for wettability-altering surfactants that change the rock surface from oil-wet toward water-wet to release trapped oil; Amott or USBM wettability tests on core samples quantify the wettability index (-1 for completely oil-wet, +1 for completely water-wet) used in EOR project screening.
• Pore-scale trapping mechanisms include snap-off (where displacing water pinches off oil at narrow pore throats, leaving disconnected oil ganglia in larger pore bodies) and bypassing (where injected water flows preferentially through high-permeability flow paths, leaving low-permeability lower-velocity zones with oil in place); X-ray micro-CT imaging of consolidated rock samples during multiphase displacement experiments (performed at synchrotron facilities and in major oil company labs) has revealed the detailed pore-scale geometry of trapped oil ganglia, showing that trapped oil exists as both isolated ganglia (single oil masses isolated within a few pores) and clusters (larger interconnected oil structures spanning hundreds to thousands of pores in the rock); the size distribution of trapped oil ganglia is critical for EOR design because surfactant flooding mobilizes ganglia by reducing the capillary trapping force, but the mobilized ganglia must coalesce into a continuous oil bank to flow to a producing well — and the coalescence efficiency depends on the ganglia size distribution, the surfactant chemistry, and the rock pore connectivity.
• Sor (residual oil saturation to waterflood) is the standard reservoir engineering parameter that quantifies trapped oil and is determined by core flooding experiments where a water-saturated core sample is flooded with oil to establish initial water saturation Swi, then water-flooded to determine the residual oil saturation Sor at the end of the waterflood; Sor values from core flood tests typically range from 0.20 to 0.45 (20 to 45 percent of pore volume) for sandstone reservoirs and 0.30 to 0.55 for carbonate reservoirs, with the variability driven by wettability, pore structure heterogeneity, and the IFT and viscosity of the test fluids; reservoir engineering simulation of EOR processes uses the experimentally measured Sor as the baseline above which any EOR-mobilized oil represents potential incremental recovery, with the residual oil saturation under the EOR process (Sor_EOR) representing the new trapped saturation that the EOR fluid system can achieve; the difference between Sor (waterflood) and Sor_EOR is the mobilizable saturation that becomes the recovery factor improvement target for the EOR project.
• Mobilized trapped oil bank formation and propagation through the reservoir is the critical operational step that distinguishes successful from unsuccessful EOR projects — even if the surfactant or other EOR fluid effectively mobilizes trapped oil at the pore scale, the mobilized oil must coalesce into a continuous oil bank that can flow toward producing wells without being re-trapped by capillary forces along the way; oil bank propagation requires that the mobilized oil saturation reach a threshold (typically 30 to 40 percent of pore volume) at which oil-phase relative permeability becomes high enough to support continuous flow, that the chemical EOR slug behind the oil bank maintain interfacial tension low enough to prevent re-trapping, and that the polymer or other mobility control agent maintain effective mobility ratio between the displacing fluid and the oil bank; failure of any of these conditions causes the mobilized oil to be re-trapped before it reaches the producing well, resulting in a chemical EOR slug that flows through to the producer with little incremental oil production — the worst possible economic outcome for an expensive chemical injection project.