Linking Pore-Scale Wettability to CO2 Huff-and-Puff Efficiency: Insights from Facies-Controlled Experiments on Tight Reservoir Cores

Abstract

Hydrocarbon recovery from tight formations and unconventional reservoirs remains limited despite advances in drilling and fracturing, primarily due to their micro- to nano-scale pore structure. Wettability in these systems acts as a primary control on multiphase fluid distribution and therefore on the efficiency of miscible CO2 huff-and-puff (HnP) used to increase recovery factors. This thesis investigates how mineralogy, pore structure, and saturation history jointly govern cycle-by-cycle oil and brine mobilization during CO2 HnP in tight cores under well-controlled laboratory conditions.Two systematic programs form the basis of this study. Program I characterized forty-eight 1″×1″ plugs from twelve facies for connected and isolated porosity, mineralogy, pore-throat structure, surface area, and microstructure using helium pycnometry, NMR, FTIR, mercury-injection capillary pressure, BET analysis, and SEM, and used phase-resolved NMR under four saturation histories (brine-only, oil-only, brine-oil, oil-brine) to partition pore volume into water-wet, mixed-wet, and oil-wet fractions for each facies. Program II applied seven multi-cycle CO2 HnP tests at 35 °C and 2,030 psi to plugs from three contrasting facies, preserving their initial wetting states and using fixed pressurization, 24-hour soak, and 12-hour production per cycle while NMR and gravimetry tracked phase saturations, recovery factors, and associated uncertainties. Across the twelve facies, mixed-wet pores dominated, comprising roughly 54-84% of total pore volume, and dual-fluid experiments showed that these pores preferentially hosted brine rather than dodecane when both fluids were present. Mixed-wet fractions increased with silicate and clay content, whereas carbonate-rich rocks displayed more strongly oil-wet behavior and higher residual oil, consistent with mineralogy-dependent wettability trends reported in tight and shale reservoirs. Above the minimum miscibility pressure, CO2 HnP responses were facies-dependent: silicate-rich and mixed-mineral facies achieved 90-100% oil recovery within three to five cycles, largely independent of initial saturation, while carbonate-dominated plugs reached 95-100% only under dual-fluid conditions and plateaued at 50-60% from oil-only states. Brine recovery was slower and incomplete (22-84%), especially in the tight carbonate facies. Pore geometry metrics such as throat size and BET surface area exhibited only weak, non-systematic relationships with recovery, suggesting that geometry primarily modulates access rather than controlling the recovery process itself. This study establishes a structured, laboratory-based framework for understanding fluid mobilization during CO2 HnP. NMR-derived wettability and mineralogy emerge as first-order controls, while pore geometry acts as a secondary modifier. Practically, these findings identify silicate- and clay-rich, mixed-wet facies as favorable targets for CO2 HnP, whereas carbonate-dominated, oil-wet facies remain prone to higher residual oil and water blockage. The framework provides transferable guidance for optimizing recovery strategies in tight and unconventional reservoirs by linking rock wettability and fluid pathways to HnP performance.