Evaluating Wettability and Imbibition Oil Recovery of the Core Plugs and Crushed Rock Samples from the Duvernay Formation

Abstract

Unconventional sources have become the leading sources of hydrocarbons in North America. These unconventional resources with low porosity and ultra-low permeability can produce hydrocarbon at profitable rates from a hydraulically fractured horizontal well. However, rock-fluid properties need to be characterized to obtain an efficient hydrocarbon recovery. Therefore, a detailed understanding of rock properties especially wettability is crucial as it has an effect on both waterflooding and enhanced oil recovery (EOR) techniques. The primary objective of this research is to determine the wettability characteristics of shale by conducting contact angle and imbibition experiments. We investigate the functional dependence of wettability on the mineralogy, petrophysical properties, and the geochemical properties that are associated with source rock. Moreover, we present the potential driving factor of imbibition by using the spontaneous imbibition and co-current imbibition data of shale samples. We also characterize the mechanisms controlling oil recovery from shales by soaking process. In this study, we evaluate the wettability of organic shale samples drilled in the Duvernay Formation, which is a source rock located in the Western Canadian Sedimentary Basin (WCSB). We characterize the shale samples by measuring pressure-decay permeability, effective porosity, initial oil and water saturation, mineralogy, total organic carbon (TOC) content. We also conduct thin section analysis and Scanning Electron Microscope (SEM) and energy-dispersive X-ray spectroscopy (EDS) analyses on shale samples to characterize the location, type, and size of pores. We use reservoir oil and brine to conduct air-liquid contact angle and air-liquid spontaneous imbibition tests for wettability measurements of both intact core plugs and crushed shale packs (CSP) prepared from drilling cuttings. We also conduct co-current imbibition to calculate the capillary pressure ratio. After evaluation of wettability, we conduct soaking experiments. First, we measure liquid-liquid contact angles of soaking fluids and reservoir oil equilibrated on the surface of the oil saturated core plugs. Then, we conduct the soaking test by immersing the oil-saturated plugs and CSP samples in soaking fluids with different compositions and physical properties and record 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 performed on core plugs and CSPs and investigating the controlling parameters affecting capillary pressure and imbibition oil recovery factor (RF). The results of wettability measurements demonstrate that the Duvernay samples have a stronger wetting affinity to oil compared to brine. The positive correlations of TOC content with both effective porosity and pressure-decay permeability suggest that the majority of connected pores are present within the organic matter which can also be supported by the SEM/EDS analysis. Organic porosity may explain the strong oil-wetness of the shale samples. The results of liquid-liquid contact angle tests show that the soaking fluid with lower IFT shows a stronger wetting affinity towards the shale samples. Similarly, the results of soaking tests conducted on the core plugs and CSPs show that oil RF is higher for the soaking fluids with lower IFT, which may be due to wettability alteration towards less oil-wet conditions. In addition, comparing the results of air-brine imbibition with those of the soaking tests indicates that adding the non-ionic surfactant to the soaking fluid may alter the wettability of organic pores towards less oil-wet conditions, leading to the displacement of oil from hydrophobic organic pores. The results also show that the presence of water film in shale samples may increase their wetting affinity towards the soaking fluids, leading to higher oil RF in the samples with higher initial water saturation.