Evaluation of Imbibition Oil Recovery in the Duvernay Formation
- Mahmood Reza Yassin (University of Alberta) | Hassan Dehghanpour (University of Alberta) | Momotaj Begum (University of Alberta) | Lindsay Dunn (Athabasca Oil Corporation)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- May 2018
- Document Type
- Journal Paper
- 257 - 272
- 2018.Society of Petroleum Engineers
- Fracturing Fluid Formulation, Wettability, Imbibition Oil Recovery, Shale Oil
- 13 in the last 30 days
- 560 since 2007
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In this study, we evaluate the wettability of shale plugs from the Duvernay Formation, which is a self-sourced reservoir in the Western Canadian Sedimentary Basin. We use reservoir oil and flowback water (brine) to conduct air/liquid contact-angle and air/liquid spontaneous-imbibition tests for wettability evaluation. We characterize the shale samples by measuring pressure-decay permeability, effective porosity, initial oil and water saturations, mineralogy, and total-organic-carbon (TOC) content, and by 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 tests. First, we measure liquid/liquid contact angles for the droplets of the soaking fluids and reservoir oil equilibrated on the surface of the oil-saturated plugs. Then, we conduct soaking tests by immersing the oil-saturated plugs in different soaking fluids, and record the oil volume produced from spontaneous imbibition of the soaking fluids. The soaking fluids are characterized by measuring surface tension (ST), interfacial tension (IFT), viscosity, and pH. We analyze the results of soaking tests and investigate the controlling parameters affecting oil recovery factor (RF).
The results demonstrate that the shale samples have stronger wetting affinity toward 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 within the organic matter. The strong oil-wetness of the shale samples can be explained by the abundance of organic porosity, verified by the SEM/EDS images. The results of liquid/liquid contact-angle tests show that the soaking fluid with lower IFT exhibits a stronger wetting affinity toward the shale. The results also show that oil RF is higher for the soaking fluids with lower IFT, which may be caused by wettability alteration. In addition, comparing the results of air/brine imbibition with those of the soaking tests indicates that adding nonionic surfactant to the soaking fluid may alter the wettability of hydrophobic organic pores toward less-oil-wet conditions, leading to the displacement of oil from organic pores.
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