CO2 foam for enhanced oil‐recovery applications has been traditionally used in order to address mobility‐control problems that occur during CO2 flooding. However, the supercritical CO2 foam generated by surfactant has a few shortcomings, such as loss of surfactant to the formation due to adsorption and lack of a stable front in the presence of crude oil. These problems arise because surfactants dynamically leave and enter the foam interface. We discuss the addition of polyelectrolytes and polyelectrolyte complex nanoparticles (PECNP) to the surfactant solution to stabilize the interface using electrostatic forces to generate stronger and longer‐lasting foams. An optimized ratio and pH of the polyelectrolytes was used to generate the nanoparticles. Thereafter we studied the interaction of the polyelectrolyte–surfactant CO2 foam and the polyelectrolyte complex nanoparticle–surfactant CO2 foam with crude oil in a high‐pressure, high‐temperature static view cell. The nanoparticle–surfactant CO2 foam system was found to be more durable in the presence of crude oil. Understanding the rheology of the foam becomes crucial in determining the effect of shear on the viscosity of the foam. A high‐pressure, high‐temperature rheometer setup was used to shear the CO2 foam for the three different systems, and the viscosity was measured with time. It was found that the viscosity of the CO2 foams generated by these new systems of polyelectrolytes was slightly better than the surfactant‐generated CO2 foams. Core‐flood experiments were conducted in the absence and presence of crude oil to understand the foam mobility and the oil recovered. The core‐flood experiments in the presence of crude oil show promising results for the CO2 foams generated by nanoparticle–surfactant and polyelectrolyte–surfactant systems. This paper also reviews the extent of damage, if any, that could be caused by the injection of nanoparticles. It was observed that the PECNP–surfactant system produced 58.33% of the residual oil, while the surfactant system itself produced 47.6% of the residual oil in place. Most importantly, the PECNP system produced 9.1% of the oil left after the core was flooded with the surfactant foam system. This proves that the PECNP system was able to extract more oil from the core when the surfactant foam system was already injected. © 2016 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2017, 134, 44491.
CO 2 foam for enhanced oil-recovery applications has been traditionally used in order to address mobility-control problems that occur during CO 2 flooding. However, the supercritical CO 2 foam generated by surfactant has a few shortcomings, such as loss of surfactant to the formation due to adsorption and lack of a stable front in the presence of crude oil. These problems arise because surfactants dynamically leave and enter the foam interface. We discuss the addition of polyelectrolytes and polyelectrolyte complex nanoparticles (PECNP) to the surfactant solution to stabilize the interface using electrostatic forces to generate stronger and longer-lasting foams. An optimized ratio and pH of the polyelectrolytes was used to generate the nanoparticles. Thereafter we studied the interaction of the polyelectrolyte-surfactant CO 2 foam and the polyelectrolyte complex nanoparticle-surfactant CO 2 foam with crude oil in a high-pressure, high-temperature static view cell. The nanoparticle-surfactant CO 2 foam system was found to be more durable in the presence of crude oil. Understanding the rheology of the foam becomes crucial in determining the effect of shear on the viscosity of the foam. A high-pressure, high-temperature rheometer setup was used to shear the CO 2 foam for the three different systems, and the viscosity was measured with time. It was found that the viscosity of the CO 2 foams generated by these new systems of polyelectrolytes was slightly better than the surfactant-generated CO 2 foams. Core-flood experiments were conducted in the absence and presence of crude oil to understand the foam mobility and the oil recovered. The core-flood experiments in the presence of crude oil show promising results for the CO 2 foams generated by nanoparticle-surfactant and polyelectrolyte-surfactant systems. This paper also reviews the extent of damage, if any, that could be caused by the injection of nanoparticles. It was observed that the PECNP-surfactant system produced 58.33% of the residual oil, while the surfactant system itself produced 47.6% of the residual oil in place. Most importantly, the PECNP system produced 9.1% of the oil left after the core was flooded with the surfactant foam system. This proves that the PECNP system was able to extract more oil from the core when the surfactant foam system was already injected.
A major outstanding challenge in developing unconventional wells is determining the optimal cluster spacing. The spacing between perforation clusters influences hydraulic fracture geometry, drainage volume, production rates, and the estimated ultimate recovery (EUR) of a well. This paper systematically examines the impact of cluster spacing in the Eagle Ford shale wells by calibrating fracture geometry and fracture/reservoir properties using field injection and production data and evaluating the optimal cluster spacing under different reservoir conditions. We explore a sequential technique to evaluate and optimize cluster spacing using a controlled field test at the Eagle Ford field. This study first identifies the fracture geometry by history matching the field injection treatment pressure. Using the rapid Fast Marching Method based flow simulation and Pareto-based multi-objective history matching, we match the well drainage volume and the cumulative production to calibrate the fracture and SRV properties. The impact of cluster spacing on the EUR are examined using the calibrated models. We run injection and production forecasts for various cluster spacing to investigate optimal completion under different reservoir conditions. The unique set of injection and production data used for this study includes two horizontal wells completed side by side. The well with tighter cluster spacing has larger drainage volume and better production performance. This is because of the increased fracture complexity in spite of the impact of stress shadow effects leading to shorter fractures. The calibrated models suggest that most of the fractures are planar in the Eagle Ford shale. The well with wider cluster spacing tends to develop longer fractures but the well with tighter cluster spacing has better stimulated reservoir volume with enhanced permeability, thus resulting in better drainage volume and production performance. From the optimization runs under different reservoir conditions, our results seem to indicate that when natural fractures are present or when stress anisotropy is high with no natural fractures, the wells with tighter cluster spacing tend to outperform the wells with wider cluster spacing. However, severe stress shadow effect is observed when stress anisotropy is low with no natural fractures, likely making tighter cluster spacing wells less favorable. The calibrated fracture geometries and properties with a unique set of Eagle Ford field data explain the performance variation for completions using different cluster spacing within the reservoir and provides insight into optimal cluster spacing under different reservoir conditions (low vs high stress anisotropy and with/without natural fractures).
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