Comparative Study of Enhanced Oil Recovery Across Reservoir Types and Technologies

Thesis Abstract

This study addresses the variability in enhanced oil recovery (EOR) performance across diverse reservoir types and technologies, highlighting the persistent knowledge gap in cross-application effectiveness and economic viability. The problem centers on how reservoir heterogeneity, rock-fluid properties, and technology-specific mechanisms constrain EOR efficacy, complicating technology selection and project budgeting for operators. The aim is to compare EOR performance across carbonate, sandstone, and tight shale reservoirs using chemical, thermal, gas, and hybrid EOR methods to identify performance differentials, risk factors, and optimal technology–reservoir pairings. Specific objectives are (i) to quantify responsiveness of different reservoir types to varied EOR methods in terms of incremental oil recovery, energy intensity, and CO2 or solvent utilization; (ii) to assess economic viability via net present value (NPV), levelized costs of oil produced (LCOP), and break-even oil price under varying geological and operational scenarios; (iii) to examine technology-specific mechanisms—surfactant–polymer synergy, thermal conductivity, gas?drive efficiency, and polymer mobility control—through comparative analysis; (iv) to evaluate environmental implications, including greenhouse gas intensity and produced water management; and (v) to develop a decision-support framework for cross-technology reservoir selection. The methodology adopts a comparative cross-sectional research design integrating both retrospective field data and simulated scenarios. The population comprises published field pilots and field-scale projects totaling 28 case studies across three reservoir types (carbonate, sandstone, and tight formations) and four EOR technologies (chemically enhanced polymer flooding, surfactant-polymer flooding, thermal recovery, and CO2/associated gas injection) supplemented by hybrid approaches. A stratified purposive sampling strategy yields 9 carbonate, 9 sandstone, and 10 tight-reservoir cases with complete performance records over production periods of 2–5 years. Data collection instruments include standardized case-study coding sheets, production performance databases, geological and petrophysical property logs, chemical formulation records, energy and emissions sheets, and economic evaluation templates. Validity and reliability are ensured through triangulation of field data with peer-reviewed publications and vendor technical datasheets, cross-checking with audited project reports, and inter-rater reliability checks (Cohen’s kappa > 0.75) for qualitative coding. Data analysis proceeds in three interlinked streams. Quantitative analysis uses multivariate regression models to quantify incremental oil recovery as a function of reservoir type, EOR technology, and interactions, with ANOVA to test differences across reservoir-technology groups. Economic analyses compute NPV, LCOP, and internal rate of return (IRR) under three macroeconomic oil-price paths, incorporating stochastic reserves uncertainty via Monte Carlo simulations (5,000 iterations). Mechanistic interpretation draws on the theoretical frameworks of the end-point recovery efficiency and the phase behavior of displacing fluids, with regression-based mediation analysis to identify pathways through which reservoir properties mediate EOR performance. The study also applies a comparative environmental assessment using life cycle assessment (LCA) boundaries to estimate greenhouse gas intensity and water usage intensity per barrel produced. A conceptual model links reservoir type, EOR mechanism, process inefficiencies, and economic-environmental outcomes, enabling cross-technology recommendations. Expected findings indicate that sandstone reservoirs exhibit higher incremental recoveries with chemical EOR due to favorable rock-fluid interactions, while carbonate reservoirs respond better to CO2 and enhanced gas injection under specific pressure regimes; tight formations show limited thermal effectiveness but may benefit modestly from hybrid chemical–gas approaches when pore-throat distributions are favorable. The cross-technology comparison will reveal significant differences in LCOP and NPV across reservoir types, with certain technologies offering superior environmental performance in specific settings. The study will contribute to knowledge by providing a robust, data-driven cross-reservoir, cross-technology framework for EOR decision-making, clarifying the economic and environmental trade-offs of each method, and offering a practical decision-support tool for operators. It is anticipated that findings will inform policy on carbon-intensity targets and guide future research toward optimized hybrid EOR strategies tailored to reservoir heterogeneity. Recommendations emphasize targeted pilot testing, improved data-sharing protocols, and the development of reservoir-specific screening criteria to enhance the efficiency and sustainability of EOR deployment.