Micro/Nanofluidic Insights on Fluid Deliverability Controls in Tight Rocks
- Ayaz Mehmani (The University of Texas at Austin) | Shaina Kelly (ConocoPhillips) | Carlos Torres-Verdín (The University of Texas at Austin)
- Document ID
- Society of Petrophysicists and Well-Log Analysts
- SPWLA 60th Annual Logging Symposium, 15-19 June, The Woodlands, Texas, USA
- Publication Date
- Document Type
- Conference Paper
- 2019. held jointly by the Society of Petrophysicists and Well Log Analysts (SPWLA) and the submitting authors
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Microfluidics and nanofluidics have been used in the oil and gas industry pore-scale research experiments and as application-specific tools (such as lab-on-a-chip PVT analyzers). The former technology constructs pore and/or pore network proxies on compact lab-on-a-chip devices and investigates the impact of specifically tuned geometric and or material variable(s) on fluid transport via direct observation with microscopy. This paper reviews micro/nanofluidics findings by the authors and other geoscience and general porous media researchers related to the impacts of pore size, surface chemistry (wettability), fluid type and composition, and surface texture (roughness) on fluid transport variables such as effective viscosity, imbibition, capillary trapping, adsorption, and diffusive processes. For example, the authors’ microfluidic findings include the presence of a critical surface roughness value beyond which capillary trapping during imbibition increases drastically due to changes in subpore-scale flow regimes. The authors’ nanofluidic findings in silica nanochannels include that the polarity of a fluid and the surface chemistry of a nanoconfinement can lead to an additional contact line friction that causes significant deviations from the continuum Washburn equation for imbibition; these effects can potentially be incorporated through an increased effective viscosity. Finally, this review highlights practical approaches for utilizing lab-on-a-chip devices and their associated pore-scale findings as diagnostic tools to augment petrophysical lab measurements and guide field-scale pilot operations.
Predicting multiphase flow dynamics in subsurface formations requires understanding fluid behavior in length scales spanning from subpore1 to field. The formation of tight rocks is preceded by a myriad of mechanical and chemical reactions from weathering during sediment deposition, to bioturbation, pressure dissolution at high temperature and pressures, and authigenic clay growth after burial. The resultant pore space morphological and topological complexities as well as nontrivial surface chemistry properties can cause many of the traditional petrophysical flow models, which are typically described in core-scale, such as Carman-Kozeny for absolute permeability or Brooks-Corey for relative permeability, to be erroneous (Byrnes et al., 2008; Mousavi and Bryant, 2012).
|File Size||8 MB||Number of Pages||20|