Integrated Surfactant-Polymer Flooding Design for Low-Permeability Reservoirs: Implementation and Evaluation

Thesis Abstract

This study investigates the design, implementation, and evaluation of an integrated surfactant-polymer (SP) flooding strategy for low-permeability reservoirs, addressing the persistent challenge of achieving economically viable oil recovery in tight formations where conventional waterfloods are inefficient and enhanced oil recovery (EOR) schemes often suffer from unfavorable transport and adsorption behaviors. The aim is to develop a robust SP protocol that optimizes chemical formulation, injection strategy, and reservoir management to maximize incremental oil recovery while maintaining injectivity and favorable flow assurance. Specific objectives are (1) to characterize rock-fluid interactions in representative low-permeability cores (pore throat diameters 0.1–0.5 ?m) and quantify adsorption, wettability alteration, and interfacial tension reduction under reservoir-relevant conditions; (2) to design a tailored SP formulation with optimized surfactant and polymer concentrations, salinity, and slug sizing using a design-of-experiments (DoE) framework; (3) to evaluate core-scale sweep efficiency, fractional-flow behavior, and end-point recovery through high-pressure coreflood experiments; (4) to develop a numerically implementable reservoir model incorporating SP transport, adsorption, and rheological effects for scale-up; and (5) to perform a field-credible techno-economic assessment of the proposed design under uncertainty.Under a positivist research paradigm, the methodology integrates experimental and numerical approaches. The population comprises core samples from tight sandstone and carbonate analogues with porosities of 8–14% and permeabilities in the millidarcy range. A stratified sampling approach will select 12 core plugs per lithology, with replicate measurements to ensure statistical rigor. Laboratory data will be collected from (a) static rock/fluid interaction tests, (b) dynamic coreflood experiments at reservoir-relevant temperatures (60–90°C) and downhole pressures, and (c) rheological characterization of SP slugs using a rotational viscometer across shear rates (0.1–1000 s-1). Data collection instruments include contact angle goniometry, zeta potential measurement, high-resolution CT scanning for pore-scale visualization, high-pressure decanting methods, and LC-MS/IC for chemical characterization of injected formulations. The SP formulations will be designed via a DoE matrix to identify optimal combinations of anionic/nonionic surfactants, partial hydrolyzed polyacrylamide or hydrolyzed polyacrylate polymers, salinity, and surfactant-to-polymer ratios, with slug sizes ranging from 0.2 to 0.6 pore volumes. Validity and reliability will be ensured through calibration runs, standard operating procedures, and replication. Data analysis will employ (i) multivariate regression and response-surface methodology to map performance surfaces, (ii) non-Newtonian rheology modeling to capture polymer solution behavior under reservoir temperatures, and (iii) a three-dimensional compositional reservoir simulator augmented with adsorption isotherms, interfacial tension reduction curves, and SP transport equations. Model validation will compare simulated production profiles with coreflood results and pressure transient analyses. Theoretical underpinnings will draw on capillary number optimization, wettability alteration theory, and adsorption-desorption kinetics, with references to the Theory of Phase Equilibria and the Surfactant-Polymer EOR framework. Expected findings include (a) quantitative relationships between SP formulation parameters and incremental oil recovery in tight rocks, (b) identification of slug sequences and injection schedules that maximize sweep efficiency while preserving injectivity, and (c) a validated upscaling methodology for translating core-scale results to field-scale performance. The study anticipates incremental recoveries between 8% and 20% of original oil in place (OOIP) for targeted low-permeability reservoirs, contingent on reservoir temperature and salinity constraints. The contribution to knowledge comprises a rigorously developed SP design protocol tailored to tight formations, an integrated coreflood-digital-twin workflow for rapid screening and optimization, and a transparent uncertainty quantification framework for field deployment. The main conclusion posits that a carefully engineered SP system, coupled with an optimized injection strategy and a validated reservoir model, can achieve meaningful recovery gains in low-permeability reservoirs without compromising injectivity. Recommendations include adopting adaptive DoE-guided SP formulation updates during field pilots, implementing real-time monitoring of surfactant and polymer concentrations in produced fluids, and further research into polymer aging and surfactant-polymer synergistic interactions under varying mineralogical conditions.