Rock-Fluid Interactions in the Duvernay Formation: Measurement of Wettability and Imbibition Oil Recovery

Abstract

In this study, we evaluate the wettability of shale samples drilled in the Duvernay Formation, which is a source-rock reservoir located in the Western Canadian Sedimentary Basin (WCSB). We use reservoir oil and brine to conduct air-liquid contact angle and air-liquid spontaneous imbibition tests for wettability measurements. We characterize the shale samples by measuring pressure-decay permeability, effective porosity, initial oil and water saturations, mineralogy, total organic carbon (TOC) content, and conducting rock-eval pyrolysis tests. We also conduct Scanning Electron Microscope (SEM) and energy-dispersive x-ray spectroscopy (EDS) analyses on the shale samples to characterize the location and size of pores. After evaluation of wettability, we conduct soaking experiments. First, we measure liquid-liquid contact angles for the droplets of the soaking fluids and reservoir oil equilibrated on surface of the rock samples. Then, we immerse the oil-saturated samples in the soaking fluids with different compositions and physical properties. The we record the oil volume produced due to spontaneous imbibition of the soaking fluids. The soaking fluids are characterized by measuring surface tension, interfacial tension (IFT), viscosity, and pH. We analyze the results of soaking tests and investigate the controlling parameters affecting oil recover factor (RF). The results of wettability measurements demonstrate that the shale samples have stronger wetting affinity to oil compared with brine. The positive correlations of TOC content with effective porosity and pressure-decay permeability suggest that the majority of connected pores are present within the organic matter. Organic porosity may explain the strong oil-wetness of the shale samples. The SEM/EDS analyses also show the abundance of organic nanopores within organic matter. The results of liquid-liquid contact angle tests show that a reduction in IFT of the soaking fluid leads to an increase in wetting affinity of rock to soaking fluid. The results also show that oil RF is higher for soaking fluids with lower IFT, which can be explained by wettability alteration. The shale samples have higher wetting affinity to soaking fluids with lower IFT, leading to an increase in the driving capillary pressure and, consequently to higher oil recovery by spontaneous imbibition. In addition, comparing the results of air-brine imbibition with soaking tests suggests that adding surfactant to the soaking fluid may alter the wettability of organic pores towards more water-wetness, leading to the displacement of oil from hydrophobic organic pores.

Complexities Driving Wettability Evaluation of Shales toward Unconventional Approaches: A Comprehensive Review

“…Hence, kerogen may be hydrocarbon-wetting at high maturity, neutral-wetting at intermediate maturities, or even hydrophilic for organic surfaces of very low maturities. It was also found that the samples with high thermal maturity imbibe more oil and have more affinity to oil and vice versa. ,, …”

“…However, this includes a wide range of the clay content that is not conclusive for rough evaluation of the wettability of the shale. Begum et al 54 also expressed that the clay content may be a significant factor in controlling fluid imbibition, i.e., less oil imbibition with an increasing clay content.…”

“…It was also found that the samples with high thermal maturity imbibe more oil and have more affinity to oil and vice versa. 54,64,65 In another study, Jagadisan and Heidari 41 performed air− liquid contact angle measurements on a kerogen sample with low thermal maturity (air−water, 44°; air−oil, 110°). Heating at 650 °C resulted in the air−water contact angle of 122°and oil spreading significantly.…”

Mechanisms and capacity of high-pressure soaking after hydraulic fracturing in tight/shale oil reservoirs

“…Generally, some of tight oil reservoirs are water-wet, so imbibition can happen even if there is no surfactant in the fracturing fluid. However, in some mixed-wet or oil-wet reservoirs, surfactant is usually added into water or the fracturing fluid to promote imbibition by changing the wettability (Begum et al 2017;Alvarez et al 2017;Meng et al 2018;Huang et al 2020). In order to reflect this effect, the capillary force ratio of water to surfactant can be approximated using the Young-Laplace equation assuming constant pore diameter for water and surfactant imbibition,…”

Modelling shale spontaneous water intake using semi‐analytical and numerical approaches

“…And where are the major hydrocarbon flow pathways? Rock small‐scale features such as mineral complexity and microfractures can remarkably change the multi‐phase flow pattern in near‐fracture zones and throughout the formation, causing unexpected and sophisticated fluid flow behaviour in shales . To illustrate this, Figure demonstrates two SEM images of the Eagle Ford and Barnett shales.…”