Field observations and laboratory experiments have proven the possibility of production enhancement of shale oil wells through surfactant addition into completion fluid and perhaps, surfactant injection for EOR. This study numerically upscaled laboratory data for multi-stage hydraulic fracturing treatment and injection process proposed for the Wolfcamp formation. A combination of rock mechanic and reservoir numerical modeling was used to approximate the field-scale performance of both techniques. Novel completion fluid formulations and optimum surfactant injection schemes were designed, based on actual completion and production data.

Surfactant-Assisted Spontaneous Imbibition (SASI) experiments data for two surfactants investigated on the core-scale were upscaled to model production response of a hydraulically fractured well in Upton County, Texas, with realistic fracture geometry and conductivity. Core plugs were saturated and aged with their corresponding oil to restore the original oil saturation. Contact angle, interfacial tension (IFT), and zeta-potential were measured to investigate the role of capillary pressure for surfactant tests. We use a dual-porosity compositional model to determine the surfactant transport and adsorption.

With the proposed methodology, we show that lateral heterogeneity may limit both hydraulic fracture propagation and uniform distribution of EOR fluids, which cannot be ignored for the sake of simplicity. The primary production mechanism of aqueous phase surfactant EOR is wettability alteration and the reduction of IFT. Laboratory-scale SASI experimental results revealed that 2 gpt of surfactant solutions recovered up to 30% of the original oil in place (OOIP), whereas water alone recovered 10%. Capillary pressure and relative permeability curves were generated by scaling group analysis and history-matching the results of imbibition experiments on CT-generated core-scale model. On the next step, these curves were applied to surfactant completion and injection simulation models.

The field-scale model was achieved from history-matching actual well production data. We tested different soak times, injection pressure, and number of cycles in surfactant injection simulations to provide an optimum design for this scheme. Simulation results indicated that surfactant injection has further potential for higher recovery factor in addition to the incremental Estimated Ultimate Recovery (EUR) observed with application of surfactant as a completion fluid alone. Also, we investigated water-injection after primary depletion (water without surfactant) to provide another possible method for unconventional liquid reservoirs (ULR). Instead of referring to Huff-n-Puff which implies gas injection, in this manuscript we use the terminology Multi-Cycle Surfactant-Assisted Spontaneous Imbibition (MC-SASI) to describe surfactant Huff-n-Puff for EOR.

This paper provides a complete workflow on SASI-EOR that has been evaluated in laboratory experiments, during the completion phase, and after primary depletion. In addition, we assessed the potential of water-injection after primary depletion in enhancing EUR. The numerical models were developed by accounting for geomechanics based on actual data combined with surfactant EOR laboratory experiments, field data, and industry-accepted simulators. A new modeling workflow for SASI-EOR is proposed to unveil the actual potential of surfactant additives.

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