Field-scale assessment of CO2 foam flooding in low-permeability carbonate reservoirs

Thesis Abstract

Field-scale CO2 foam flooding offers a potential pathway to enhance oil recovery in low-permeability carbonate reservoirs by improving sweep efficiency and mitigating near-wwell channeling. The study addresses the persistent challenge of limited injectivity and suboptimal conformance control in carbonate formations with heterogeneous pore structures, where conventional gas injection yields low ultimate recovery and significant CO2 breakthrough. The aim is to quantify field-scale performance of CO2 foam flooding and identify the key reservoir and operational factors that govern oil recovery, foam stability, and CO2 storage potential in low-permeability carbonates. Specific objectives include (i) evaluating foam generation and transport characteristics under field-like conditions, (ii) estimating incremental oil recovery and CO2 storage using history-mmatched reservoir simulations, (iii) assessing the sensitivity of flooding performance to brine salinity, temperature, gas–liquid ratio, and crossflow between high and low permeability zones, and (iv) developing operational guidelines for foam stability maintenance and injectionTiming optimization. The methodology integrates a mixed-methods research design combining field data analysis, laboratory coreflood experiments, and numerical modeling. The population comprises fractured and cemented carbonate reservoirs with average matrix permeability ranging from 0.1 to 1.0 mD, heterogeneity indices greater than 0.6, and historical CO2 usage in mature producing fields. A stratified random sample of 12 faulted carbonate blocks from a mature field is selected for coreflood campaigns and core–fluid characterization, with 48 core plugs tested to capture permeability distribution and porosity variation. Data collection instruments include high-resolution reservoir description logs, production histories, downhole pressure/temperature sensors, capillary pressure curves, and coreflood apparatus for measuring foam stability, apparent viscosity, snap-off pressure, and oil recovery under varying foam quality. Foam generation in the laboratory uses a spun foam device and crosslinked polymer solutions to mimic field-delivered foaming agents, with measurements of liquid holdup, gas mobility reduction, and surfactant retention. Analytical techniques employed comprise regression analysis to quantify relationships between foam stability, injection pressure, and oil rate; ANOVA to compare performance across reservoir heterogeneity classes; and multivariate surrogate modeling to integrate petrophysical, geochemical, and operational variables. Reservoir-scale interpretation relies on history-matched compositional and black-oil simulations implemented in a fully implicit, twophase–three-phase solver with foam rheology models calibrated against laboratory data. The model incorporates a dual-porosity representation to capture matrix–fracture interactions and uses a mechanistic foam transport module to simulate mobility reduction and gas channeling effects under field-scale boundary conditions. Expected findings include (i) quantification of incremental oil recovery attributed to CO2 foam under varying ambient conditions, with anticipated recovery uplift in the 6–14% Range for blocks with medium heterogeneity and favorable foaming properties; (ii) identification of critical foam quality and gas–liquid ratios that maximize sweep efficiency while minimizing gas breakthrough; (iii) demonstration of foam stability lifetimes exceeding 2–6 days under reservoir temperatures, enabling controllable injection strategies; (iv) estimation of CO2 storage potential constrained by dissolution, mineral trapping, and caprock integrity, with a projected storage efficiency of 40–70% of injected CO2 over a 5– to 10-year window. The study contributes to knowledge by bridging core-scale foam science with field-scale performance, validating a conceptual framework that links reservoir heterogeneity, foam rheology, and operational timing to recovery and sequestration outcomes. The theoretical underpinning integrates elements of the disjoining pressure theory for foam films, Darcy-based multiphase flow with mobility control, and a diffusion–dispersion framework for CO2 in carbonate matrices, complemented by the Theory of Foam Drainage in porous media. The main conclusion posits that field-scale CO2 foam flooding can significantly improve sweep efficiency and oil recovery in low-permeability carbonates when foam quality, injection scheduling, and reservoir heterogeneity are optimized in concert with reservoir fluid properties and temperature constraints. Recommendations emphasize implementing dynamic foam management practices, tailoring injection sequences to exploit high-permeability streaks, and adopting robust monitoring strategies (e.g., tracers and real-time downhole pressures) to ensure sustained performance. Further research should explore long-term CO2–oil–brine interactions, scale-up of laboratory-derived foam models to multidisciplinary field pilot programs, and economic feasibility analyses under fluctuating energy prices.