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Evaluation of Wettability and EOR Potential of Shale and Tight Formations
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- Author / Creator
- Mahmood Reza Yassin
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During the last decade, low-permeability unconventional reservoirs have been rapidly developed using horizontal drilling and multistage hydraulic fracturing. Despite the high extent of unconventional resources, typically less than 10% of the initial oil in place (IOIP) can be recovered. This shows that complementary technologies are needed to increase the recovery percentage of IOIP. An example is enhanced oil recovery (EOR) technology. Field and laboratory results suggest that rock/fluid interactions in unconventional rocks can significantly influence well performance. The extent of this influence depends on rock wettability, reservoir conditions, and fracturing fluid formulation. Evaluation of wettability provides valuable information about 1) the low oil recovery factor of unconventional wells, 2) the location of the residual trapped oil, and 3) the potential EOR technique to produce the residual trapped oil.This study first aims at investigating wettability of organic-rich shales of the Duvernay Formation. We recognize the key parameters controlling the wettability of shale samples and identify the location of the residual trapped oil. Using the concept of dual-wet pore network, we develop new experimental approaches for the pore size distribution of unconventional rocks as well as mathematical models for gas/water relative permeability. We use tight samples of the Montney Formation to develop relative permeability curves. Then, this study presents the experimental results of CO2-EOR tests using a custom-designed visual cell and explains the principal mechanisms controlling oil recovery from dual-wet shales.Investigating wettability of the Duvernay shale plugs shows higher oil uptake than brine uptake. The higher oil uptake suggests that there are abundant water-repellant pores with strong affinity to oil. Scanning electron microscopy (SEM) images show two different pore networks in shale sample. We observe 1) large micropores bordered by inorganic minerals such as quartz, calcite, and clays and 2) abundant small nanopores within the organic matter; forming a dual-wet medium. Abundant organic pores with hydrophobic characteristics explain strong oil-wetness of the shale samples, confirmed by the positive correlation of porosity with total organic carbon (TOC) content.Exploring wettability of dual-wet shales from different hydrocarbon windows indicates that besides TOC content, wettability has a functional dependency on kerogen maturity. SEM images of highly mature samples (gas window) show a higher number of organic pores compared with less mature samples (oil window). It is expected to see higher oil uptake in the samples with higher TOC content. However, we observe the opposite trend in less mature shales which is explained by the poorly-developed organic pores that hinder oil uptake.Based on the concept of dual-wet pore network, brine is the wetting and non-wetting phases in inorganic and organic pores, respectively. We use this concept and estimate inorganic and organic pore size distributions by conducting spontaneous and forced imbibition, respectively. The results indicate that pore space filled by brine is three times higher than that in mercury injection capillary pressure (MICP). Furthermore, minimum pore-throat diameter in MICP test is 3.8 nm. This parameter is 1.2 nm in a forced brine-imbibition test, indicating the capability of brine for characterizing smaller pore-throat sizes.The concept of gas/water relative permeability is proposed to account for the organic nanopores inaccessible for water. By increasing the fraction of organic pore space (Sorg), gas relative permeability decreases, for a fixed water saturation. Because by increasing Sorg, the average size of pores for gas mobility and gas relative permeability are reduced.The results of wettability tests demonstrate that a significant volume of oil is mainly trapped in organic nanopores. Imbibition oil recovery by brine is less than 7%, indicating the weak affinity of oil-saturated plugs for brine imbibition. However, supercritical CO2 (at 2000 psig and 122oF) can diffuse into the oil-saturated dual-wet plugs and produce about 80% of oil, indicating the significantly high potential of supercritical CO2 for recovering trapped oil in organic nanopores.Supercritical CO2 recovers the oil in a three-step process including 1) CO2 dissolution into the oil, 2) oil expansion, and 3) extraction (vaporization) of the oil expelled from the shale plug. The results of CO2/oil bulk-phase tests indicate that supercritical CO2 can rapidly dissolve into and expand the oil due to 1) extracting and condensing flows at the CO2/oil interface and 2) density-driven convection.
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- Graduation date
- Spring 2019
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- Type of Item
- Thesis
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- Degree
- Doctor of Philosophy
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- License
- Permission is hereby granted to the University of Alberta Libraries to reproduce single copies of this thesis and to lend or sell such copies for private, scholarly or scientific research purposes only. Where the thesis is converted to, or otherwise made available in digital form, the University of Alberta will advise potential users of the thesis of these terms. The author reserves all other publication and other rights in association with the copyright in the thesis and, except as herein before provided, neither the thesis nor any substantial portion thereof may be printed or otherwise reproduced in any material form whatsoever without the author's prior written permission.