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. 2021 Dec 20;7(1):85-100.
doi: 10.1021/acsomega.1c03940. eCollection 2022 Jan 11.

The Influence of Oil Composition, Rock Mineralogy, Aging Time, and Brine Pre-soak on Shale Wettability

I Wayan Rakananda Saputra  1 , Oluwatobiloba Adebisi  1 , Elsie B Ladan  1 , Aashrit Bagareddy  1 , Abhishek Sarmah  1 , David S Schechter  1
Affiliations

The Influence of Oil Composition, Rock Mineralogy, Aging Time, and Brine Pre-soak on Shale Wettability

I Wayan Rakananda Saputra et al. ACS Omega. .

Abstract

Experimental and field studies have indicated that surfactants enhance oil recovery (EOR) in unconventional reservoirs. Rock surface wettability plays an important role in determining the efficacy of this EOR method. In these reservoirs, the initial wettability of the rock surface is especially important due to the extremely low porosity, permeability, and resulting proximity of fluids to the solid surface. This study is designed to investigate the effect of oil components, rock mineralogy, and brine salinity on rock surface wettability in unconventional shale oil/brine/rock systems. Six crude oils, seven reservoir rocks, and seven reservoir brine samples were studied. These oil samples were obtained from various shale reservoirs (light Eagle Ford, heavy Eagle Ford, Wolfcamp, Middle Bakken, and Three Forks) in the US. SARA (saturates, aromatics, resins and asphaltenes) analysis was conducted for each of the crude oil samples. Additionally, this study also aims to provide a guideline to standardize the rock sample aging protocol for surfactant-related laboratory experiments on shale reservoir samples. The included shale reservoir systems were all found to be oil-wet. Oil composition and brine salinity showed a greater effect on wettability as compared to rock mineralogy. Oil with a greater amount of aromatic and resin components and higher salinity rendered the surface more oil-wet. Rock samples with a higher quartz content were also observed to increase the oil-wetness. The combination of aromatic/resin and the quartz interaction resulted in an even more oil-wet system. These observations are explained by a mutual solubility/polarity concept. The minimum aging time required to achieve a statistically stable wettability state was 35 days according to Tukey's analysis performed on more than 1100 contact angle measurements. Pre-wetting the surface with its corresponding brine was observed to render the rock surface more oil-wet.

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Conflict of interest statement

The authors declare no competing financial interest.

Figures

Figure 1
Figure 1
Distribution of aging time from 44 publications of shale EOR involving an aging procedure.
Figure 2
Figure 2
Schematic of the captive bubble method (left) (the picture is not to scale). Examples of a water-wet system (middle) and an oil-wet system (right).
Figure 3
Figure 3
Wettability evaluation throughout 0–56 days of aging for all six crude oil samples and seven rock samples.
Figure 4
Figure 4
Effect of quartz, calcite, dolomite, and clay contents on the surface wettability after a duration of aging for samples measured in brine T (DI water). Colors represent the length of the aging duration, green-to-red: zero to 120 days of aging.
Figure 5
Figure 5
Effect of quartz, calcite, dolomite, and clay contents on the surface wettability after a duration of aging. Colors represent the length of the aging duration, green-to-red: zero to 120 days of aging.
Figure 6
Figure 6
Aging time required to establish stable and consistent wettability for the six reservoir rock samples (left). Values were obtained from Tukey’s analysis with contact angle data grouped by rocks. The stable aging time is plotted against the calcite, dolomite, and quartz content (right).
Figure 7
Figure 7
Effect of saturate, aromatic, resin, and asphaltene contents on the surface wettability after a duration of aging for samples measured in brine T (DI water). Colors represent the length of the aging duration, green-to-red: zero to 120 days of aging.
Figure 8
Figure 8
Effect of saturate, aromatic, resin, and asphaltene contents on the surface wettability after a duration of aging. Colors represent the length of the aging duration, green-to-red: zero to 120 days of aging.
Figure 9
Figure 9
Aging time required to establish stable and consistent wettability for the six crude oil samples (left). Values were obtained from Tukey’s analysis with contact angle data grouped by crude oil. The stable aging time is plotted against the saturate, aromatic, and resin content (right).
Figure 10
Figure 10
Effect of saturate, aromatic, and resin composition at various quartz contents on the contact angle. This figure was constructed to investigate the interaction between the oil composition and the rock mineralogy to the rock surface wettability.
Figure 11
Figure 11
Effect of brine salinity on the surface wettability. Colors represent the length of the aging duration, green-to-red: zero to 120 days of aging.
Figure 12
Figure 12
Aging time required to establish stable and consistent wettability for the four brines (left). Values were obtained from Tukey’s analysis with contact angle data grouped by brine. The stable aging time is plotted against the TDS (right).
Figure 13
Figure 13
Evolution of the wettability throughout the aging duration for samples with (blue) and without (red) pre-soak.
Figure 14
Figure 14
Comparisons of aging time required to reach stable wettability for samples without and with pre-soak. The left graph was generated by averaging on the reservoir rock samples. The middle graph was generated by averaging on the crude oil samples. The right graph was generated by averaging on the brine.
Figure 15
Figure 15
Oil-wetting mechanism for shale oil reservoir oil/brine/rock systems.
See this image and copyright information in PMC

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