Abstract

The addition of surfactant to the completion fluid of a shale oil well has been widely believed to improve well performance. Previous laboratory studies showed that the method is based on enhanced capillary-driven spontaneous imbibition as a result of surfactant interaction with the oil/water/rock system. However, published work on this subject is highly limited on the result on laboratory-scale work. The purpose of this study is to fill this gap by providing a field-scale impact of Surfactant-Assisted Spontaneous Imbibition (SASI) as derived by numerical model-based upscaling workflow.

This study provides a complete workflow on assessing the effectivity of SASI which consists of three big parts: laboratory experiments, lab-scale modelling, and field-scale modelling. On the laboratory experiment, interfacial tension, contact angle, zeta potential, surfactant adsorption isotherm, and ultimately, spontaneous imbibition were done as part of data gathering process. Lab-scale modelling was done to model the spontaneous imbibition of the previous step to construct the relative permeability and capillary pressure data for upscaling purpose. In order to incorporate the heterogeneity commonly found on shale rock samples, a CT-based rock digitalization method was implemented to build the lab-scale model. Utilizing all data obtained from lab-scale model and laboratory experiments, the field-scale model was then constructed and the effect of SASI on the field-scale was calculated.

Four fluid systems were tested in this work consisting of one case of water without surfactant component as the base case and three cases with different surfactants. Reduction of IFT, alteration of wettability to water-wet region, and stable zeta potential were observed for the three surfactants tested. Adsorption isotherm measurement also showed a positive correlation between the wettability alteration performance and the amount of surfactant adsorbed. Oil production from spontaneous imbibition was increased seven-fold on the best surfactant tested when compared to the base case. Through numerical upscaling, field-scale effect of SASI was also approximated. With the result of 22.7% increase of initial oil production rate and 18.4% improvement of three years cumulative oil recovery from the best surfactant tested. In addition, a rigorous sensitivity analysis incorporating seven different reservoir properties was also done and the effectivity of SASI was found to be a function of some of the tested reservoir properties.

Introduction

Started during the early 2000s, oil production from shale oil has been increasing steadily and now accounts for 65% of the total onshore US oil production (EIA 2017). Different methods have been explored to improve the oil recovery from shale oil well from application of surfactant, low-salinity flooding (Valluri et al. 2016), as well as gas injection (Tovar et al. 2014). Specifically on the method of surfactant addition, numerous study on the application of this method on every prominent shale play in the US has been published with the limitation of the observation only done on laboratory-scale. Significant difference in properties between conventional and unconventional reservoir causes the surfactant application to be different as well. Instead of a flooding mechanism, surfactant is added into the hydraulic fracturing fluid and production enhancement occurs as the molecule of surfactant improve the oil transfer between matrix and fracture system.

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