Abstract

Surfactants are among the most common additives utilized in the oil industry. One focus of industry investigations in unconventional liquid-rich reservoirs is surfactant-mediated wettability alteration to enhance hydrocarbon recovery. Previous experimental studies and published field trials have shown that injected surfactants can be an effective means of improving recovery. Most experiments, however, have been conducted at ambient rather than reservoir conditions. This study presents a novel approach to screen thermally stable surfactants at high pressures and high temperatures for the explicit purpose of wettability alteration in ConocoPhillips’ Eagle Ford acreage. We designed a systematic workflow that reduced costs and avoided potentially ambiguous field trial results to evaluate surfactant stability and efficacy. The behaviors of different surfactants were first investigated through contact angle (CA) and interfacial tension (IFT) measurements at ∼350°F and ∼5000 psi on crude-oil-saturated Eagle Ford formation core plugs. A subset of surfactants with favorable wettability alteration potential were tested for completions compatibility and further evaluated by spontaneous imbibition and flow-through experiments. An integrated modeling workflow combining molecular dynamics, the Lattice-Boltzmann method, and reservoir simulations provided a model-based assessment of production uplift due to the wettability changes associated with injected surfactants. Initial testing with synthetic porous media at reservoir conditions demonstrated that some ‘off-the-shelf’ surfactants were prone to pore clogging or thermally unstable. CA and IFT revealed that most surfactants and blends would be relatively ineffective at favorably altering wettability at ConocoPhillips’ Eagle Ford reservoir conditions. A thermal stability breakthrough to overcome temperature limitations was achieved by blending co-surfactants. However, imbibition and flow-through experiments with the few promising co-surfactant blends indicated that recovery factor uplifts via wettability alteration were minimal. Furthermore, flow simulation modeling suggested that altered wettability due to usage of surfactants would encourage imbibition and retention of injected water in the rock matrix but not improve oil recovery. This paper presents a systematic multi-year, multi-disciplinary approach to screen thermally stable surfactants at reservoir conditions using CA and IFT measurements, completions compatibility testing, spontaneous imbibition, flow-through experiments, and reservoir simulations. The goal was to establish a rigorous screening workflow and identify potential surfactant application from laboratory and simulation modeling with the explicit purpose of wettability alteration before conducting expensive and possibly ambiguous field trials.

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