to mitigate the global climate change. The CO2 invasion pattern is dependent on various factors such as fluid viscosity, interfacial tension, injection rate, and the ...
Effect of capillary and viscous force on CO2 saturation and invasion pattern in the microfluidic chip 1
Xianglei Zheng, 1Nariman Mahabadi, 2Tae Sup Yun, and 1Jaewon Jang 1
School of Sustainable Engineering and the Built Environment Arizona State University, Tempe, Arizona 85281, USA 2
Department of Civil and Environmental Engineering Yonsei University, Seoul, South Korea
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1 Submitted to Journal of Geophysical Research – Solid Earth
Keywords: CO2 sequestration, nanoparticle, CO2-air foam, viscosity, displacement
Abstract Carbon dioxide sequestration into geological formations has been identified as an alternative to mitigate the global climate change. The CO2 invasion pattern is dependent on various factors such as fluid viscosity, interfacial tension, injection rate, and the characteristics of porous media. Among these variables, we provide a systematic experimental study on the influence of the injection rate and the phase of CO2 invading into a brine-saturated microfluidic chip in order to quantitatively assess the displacement ratio. Interfacial tension and contact angle are accurately measured under the temperature and pressure conditions relevant to in-situ conditions. The injection rate varies three orders of magnitude for gaseous, liquid, supercritical CO2, and CO2-water foam invasion. The capillary number and the viscosity ratio are calculated for each experimental condition, and the displacement ratio (CO2 saturation) is obtained after CO2 invasion. The results show that the saturation of This article has been accepted for publication and undergone full peer review but has not been through the copyediting, typesetting, pagination and proofreading process which may lead to differences between this version and the Version of Record. Please cite this article as doi: 10.1002/2016JB013908 © 2017 American Geophysical Union. All rights reserved.
injected CO2 is controlled by manipulating the injection rate and the phase of invading fluid, which can be used to optimize the in-situ storage capacity. Especially, the CO2-water foam displaces almost all brine out of the microfluidic chip, but the increase in CO2 saturation is 23%~53% compared to pure gaseous CO2 injection due to the water initially mixed in the CO2-water foam. The potential advantages of using CO2-water foam in the geological CO2 sequestration were also discussed.
1. Introduction According to the EPA report (U.S. Inventory of Greenhouse Gas Emissions and Sinks: 19902014), carbon dioxide (CO2) occupies 80% of a total US greenhouse gas emission in 2014, and the fossil fuel power plants produce 30% of the greenhouse gas generated in the United States [EPA, 2016]. Carbon dioxide capture and sequestration (CCS) can reduce CO2 emissions significantly from fossil fuel burning power plants and large industrial sources such as cement production. The CO2 emission from a 500 MW coal-burning power plant is roughly 3 million tons per year [MIT, 2007]. CCS technology can reduce CO2 emissions from the power plants by 80~90%. The reduction of CO2 emission by CCS with a 90% efficiency is equivalent to planting more than 62 million trees and waiting at least 10 years for them to grow or avoiding annual electricity-related emissions from more than 300,000 homes [EPA, 2013].
The depleted oil and gas reservoirs, deep saline formations with very low permeability caprock, and unminable coal seams are potential candidates for geological CO2 storage. The phase of CO2 injected into the formations can be gas, liquid, or supercritical state depending on the in-situ temperature and pressure condition. For example, the CO2 was injected into coal seams at the gaseous or liquid state at the injection rate of 1.6~3.5ton/day in Hokkaido, Japan [Yamaguchi et al., 2009]. In Alberta basin, Canada, the supercritical CO2 is injected at the injection rate of 208~5000m3/h [Bachu et al., 2004]. In Iceland, the mixture of gaseous CO2 and water is injected at the injection rate of 6.03ton/day [Aradottir et al., 2012; Matter et al., 2011].
During the injection of CO2 into the porous rock, the CO2 displaces the existing pore fluid such as brine and oil that are more viscous than the CO2. Several pore-scale microfluidic chip experiments and numerical simulations have been performed to investigate the mechanism of immiscible fluid displacement in porous media [Chang et al., 2009; Cottin et al., 2010; Ferer © 2017 American Geophysical Union. All rights reserved.
et al., 2004; Zhang et al., 2011]. The displacement pattern of the immiscible fluids in porous media is affected by the capillary number C and viscosity ratio M [Lenormand et al., 1988]. (1) (2) where v is the velocity of invading fluid, Ts the interfacial tension between invading and defending fluids, θ is the contact angle of defending fluid on a substrate (for drainage condition), and μinv and μdef are the viscosity values of the invading fluid (e.g., CO2 in this study) and defending fluid (e.g., brine in this study). Depending on the combination of these viscous and capillary forces, the displacement pattern is classified as either (1) viscous fingering, (2) capillary fingering, or (3) stable displacement. The boundaries for the displacement pattern are shown on a logC-logM plot (Figure 1). This ―phase boundary‖ is also affected by spatial and statistical pore size distribution and domain size and dimension [Lenormand et al., 1988; Liu et al., 2013; Shi et al., 2011; Zhang et al., 2011]. And the values of logC and log M used for several experimental and numerical studies available in the literature are superimposed in Figure 1. Capillary fingering occurs under the low injection rate condition (logC
