Characterization of immiscible fluid displacement processes with various capillary numbers and viscosity ratios in 3D natural sandstone
Abstract
We characterize the influence of reservoir conditions upon multiphase flow, we calculated fluid displacements (drainage processes) in 3D pore spaces of Berea sandstone using two-phase lattice Boltzmann (LB) simulations. The results of simulations under various conditions were used to classify the resulting two-phase flow behavior into three typical fluid displacement patterns on the diagram of capillary number (Ca) and viscosity ratio of the two fluids (M). In addition, the saturation of the nonwetting phase was calculated and mapped on the Ca–M diagram. We then characterized dynamic pore-filling events (i.e., Haines jumps) from the pressure variation of the nonwetting phase, and linked this behavior to the occurrence of capillary fingering. The results revealed the onset of capillary fingering in 3D natural rock at a higher Ca than in 2D homogeneous granular models, with the crossover region between typical displacement patterns broader than in the homogeneous granular model. Furthermore, saturation of the nonwetting phase mapped on the Ca–M diagram significantly depends on the rock models. These important differences between two-phase flow in 3D natural rock and in 2D homogeneous models could be due to the heterogeneity of pore geometry in the natural rock and differences in pore connectivity. By quantifying two-phase fluidmore »
- Publication Date:
- Research Org.:
- Energy Frontier Research Centers (EFRC) (United States). Center for Geologic Storage of CO2 (GSCO2)
- Sponsoring Org.:
- USDOE Office of Science (SC), Basic Energy Sciences (BES)
- OSTI Identifier:
- 1388385
- Alternate Identifier(s):
- OSTI ID: 1344939
- Grant/Contract Number:
- SC0012504; 15H01143; 24246148; SC0C12504
- Resource Type:
- Accepted Manuscript
- Journal Name:
- Advances in Water Resources
- Additional Journal Information:
- Journal Volume: 95; Journal Issue: C; Related Information: GSCO2 partners with University of Illinois Urbana-Champaign (lead); National Energy Technology Laboratory; Schlumberger; SINTEF; Stiftelsen Norsar; Texas Tech University; University of Notre Dame; University of Southern California; University of Texas at Austin; Wright State University; Journal ID: ISSN 0309-1708
- Publisher:
- Elsevier
- Country of Publication:
- United States
- Language:
- English
- Subject:
- 58 GEOSCIENCES; defects; mechanical behavior; carbon sequestration; mesostructured materials
Citation Formats
Tsuji, Takeshi, Jiang, Fei, and Christensen, Kenneth T. Characterization of immiscible fluid displacement processes with various capillary numbers and viscosity ratios in 3D natural sandstone. United States: N. p., 2016.
Web. doi:10.1016/j.advwatres.2016.03.005.
Tsuji, Takeshi, Jiang, Fei, & Christensen, Kenneth T. Characterization of immiscible fluid displacement processes with various capillary numbers and viscosity ratios in 3D natural sandstone. United States. https://doi.org/10.1016/j.advwatres.2016.03.005
Tsuji, Takeshi, Jiang, Fei, and Christensen, Kenneth T. Fri .
"Characterization of immiscible fluid displacement processes with various capillary numbers and viscosity ratios in 3D natural sandstone". United States. https://doi.org/10.1016/j.advwatres.2016.03.005. https://www.osti.gov/servlets/purl/1388385.
@article{osti_1388385,
title = {Characterization of immiscible fluid displacement processes with various capillary numbers and viscosity ratios in 3D natural sandstone},
author = {Tsuji, Takeshi and Jiang, Fei and Christensen, Kenneth T.},
abstractNote = {We characterize the influence of reservoir conditions upon multiphase flow, we calculated fluid displacements (drainage processes) in 3D pore spaces of Berea sandstone using two-phase lattice Boltzmann (LB) simulations. The results of simulations under various conditions were used to classify the resulting two-phase flow behavior into three typical fluid displacement patterns on the diagram of capillary number (Ca) and viscosity ratio of the two fluids (M). In addition, the saturation of the nonwetting phase was calculated and mapped on the Ca–M diagram. We then characterized dynamic pore-filling events (i.e., Haines jumps) from the pressure variation of the nonwetting phase, and linked this behavior to the occurrence of capillary fingering. The results revealed the onset of capillary fingering in 3D natural rock at a higher Ca than in 2D homogeneous granular models, with the crossover region between typical displacement patterns broader than in the homogeneous granular model. Furthermore, saturation of the nonwetting phase mapped on the Ca–M diagram significantly depends on the rock models. These important differences between two-phase flow in 3D natural rock and in 2D homogeneous models could be due to the heterogeneity of pore geometry in the natural rock and differences in pore connectivity. By quantifying two-phase fluid behavior in the target reservoir rock under various conditions (e.g., saturation mapping on the Ca–M diagram), our approach could provide useful information for investigating suitable reservoir conditions for geo-fluid management (e.g., high CO2 saturation in CO2 storage).},
doi = {10.1016/j.advwatres.2016.03.005},
journal = {Advances in Water Resources},
number = C,
volume = 95,
place = {United States},
year = {Fri Mar 11 00:00:00 EST 2016},
month = {Fri Mar 11 00:00:00 EST 2016}
}
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