Characterization of immiscible fluid displacement processes with various capillary numbers and viscosity ratios in 3D natural sandstone

Tsuji, Takeshi; Jiang, Fei; Christensen, Kenneth T.

doi:10.1016/j.advwatres.2016.03.005

Title: Characterization of immiscible fluid displacement processes with various capillary numbers and viscosity ratios in 3D natural sandstone

Journal Article · Fri Mar 11 00:00:00 EST 2016 · Advances in Water Resources

DOI:https://doi.org/10.1016/j.advwatres.2016.03.005· OSTI ID:1388385

^[1]; Jiang, Fei ^[1]; Christensen, Kenneth T. ^[2]

Kyushu Univ. (Japan)
Kyushu Univ. (Japan) ; Univ. of Notre Dame, IN (United States)

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).

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Research Organization:: Energy Frontier Research Centers (EFRC) (United States). Center for Geologic Storage of CO2 (GSCO2)

Sponsoring Organization:: USDOE Office of Science (SC), Basic Energy Sciences (BES)

Grant/Contract Number:: SC0012504; 15H01143; 24246148; SC0C12504

OSTI ID:: 1388385

Alternate ID(s):: OSTI ID: 1344939

Journal Information:: Advances in Water Resources, Vol. 95, 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; ISSN 0309-1708

Publisher:: ElsevierCopyright Statement

Country of Publication:: United States

Language:: English

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Cited by: 87 works

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