Geological storage of CO 2 (GCS), also referred to as carbon sequestration, is a critical component for decreasing anthropogenic CO 2 atmospheric emissions. Stored CO 2 will exist as a supercritical phase, most likely in deep, saline, sedimentary reservoirs. Research at the Center for Frontiers of Subsurface Energy Security (CFSES), a Department of Energy, Energy Frontier Research Center, provides insights into the storage process. The integration of pore-scale experiments, molecular dynamics simulations, and study of natural analogue sites has enabled understanding of the efficacy of capillary, solubility, and dissolution trapping of CO 2 for GCS. Molecular dynamics simulations provide insight on relative wetting of supercritical CO 2 and brine hydrophilic and hydrophobic basal surfaces of kaolinite. Column experiments of successive supercritical CO 2 /brine flooding with highresolution X-ray computed tomography imaging show a greater than 10% difference of residual trapping of CO 2 in hydrophobic media compared to hydrophilic media that trapped only 2% of the CO 2 . Simulation results suggest that injecting a slug of nanoparticle dispersion into the storage reservoir before starting CO 2 injection could increase the overall efficiency of large-scale storage. We estimate that approximately 22% ± 17% of the initial CO 2 emplaced into the Bravo Dome field site of New Mexico has dissolved into the underlying brine. The rate of CO 2 dissolution may be considered limited over geological timescales. Field observations at the Little Grand Wash fault in Utah suggest that calcite precipitation results in shifts in preferential flow paths of the upward migrating CO 2 -saturated-brine. Results of hybrid pore-scale and pore network modeling based on Little Grand Wash fault observations demonstrate that inclusion of realistic pore configurations, flow and transport physics, and geochemistry are needed to enhance our fundamental mechanistic explanations of how calcite precipitation alters flow paths by pore plugging to match the Little Grand Wash fault observations.
We measure the three-phase oil relative permeability kro by conducting unsteady-state drainage experiments in a 0.8m water-wet sandpack. We find that when starting from capillary-trapped oil, kro shows a strong dependence on both the flow of water and the water saturation and a weak dependence on oil saturation, contrary to most models. The observed flow coupling between water and oil is stronger in three-phase flow than two-phase flow, and cannot be observed in steadystate measurements. The results suggest that the oil is transported through moving gas/oil/water interfaces (form drag) or momentum transport across stationary interfaces (friction drag). We present a simple model of friction drag which compares favorably to the experimental data.When the single-phase Darcy equation is generalized to multi-phase flow in porous media, it is assumed that each phase flows due to the pressure gradient within that phase, albeit with a reduced permeability [1,2]. Conceptually, each phase flows in a capillary-stable reduced network compared to single phase flow. The change in permeability is parameterized by the relative permeability, k ri , that is assumed to be a function of the saturation of the phase, S i (the local volume fraction of the pore space filled by the phase i). Mathematically this is expressed through the Darcy-Buckingham equation [1].Here, q i , µ i , ρ i and P i are flux, viscosity, density and pressure of phase i flowing through porous media of permeability k. While this multi-phase flow equation is widely used due to its simplicity, it is known to break down at high capillary numbers (the network is fluid) [3], unstable flow [4], high viscosity ratio (due to viscous coupling between the mobile phases) [5], and three-phase flow (the network for the intermediate phase depends on the other two phases) [6].Here we concentrate on the combined effects of threephase flow and viscous coupling. Three-phase flow occurs when three mobile fluid phases co-exist in a porous media; typically water is the most wetting phase and oil the intermediate wetting phase. Three-phase relative permeability has been measured using steady state experiments [6], and many empirical models of the oil relative permeability k ro have been introduced [7]. These models have a dependence on both saturations, k ro (S o , S w ), based on the idea that the connected oil network depends on the amount of water. From observations in micromodels [8,9] and capillary stability arguments based on geometry [10] and thermodynamics [11] various three-phase pore level fluid configurations and flow mechanisms have been recognized. These mechanisms have been incorporated into network models to predict three-phase relative permeability and saturations path [12][13][14], under the ansatz of each phase flowing independently in its own network. * dicarlo@mail.utexas.edu Viscous coupling, where the pressure gradient of a particular phase affects the flow of the other phase, has been investigated for two-phase flow through experiments [15][16][17], analytical...
We report on measurements of the flow pattern and in‐situ saturations whenn‐octane displaces a brine in which surface treated silica nanoparticles are dispersed. The nanoparticles are known to stabilize octane‐in‐water emulsions. We find that the displacement front is more spatially uniform, and with a later breakthrough when compared to a control displacement with no in‐situ nanoparticles. Pressure measurements during the displacement are consistent with generation of a viscous phase such as an emulsion. These observations suggest that a nanoparticle stabilized emulsion is formed during the displacement which acts to suppress the viscous instability. We argue that generation of droplets of nonwetting phase occurs at the leading edge of all drainage displacements. The droplets rejoin the bulk phase in the absence of stabilizing agents, but are preserved when nanoparticles adhere to the fluid/fluid interface.
The efficiency of one fluid displacing another in a permeable medium depends on the pore-scale dynamics at the main wetting front. Experiments have shown that the frontal dynamics can result in two different flow regimes: a sharp and a diffuse front. In the sharp front regime, the displacing fluid occupies nearly all the pores and throats behind the main wetting front and the saturation changes abruptly. In contrast, in the diffuse front regime, pores are filled gradually at the main wetting front, and the saturation change is gradual in space. The different fronts can greatly alter the relative permeability curves, the trapping mechanisms, and the displacement efficiency.Directly measuring the sharpness of the front is difficult. Instead, here we correlate the front sharpness to saturation overshoot, which occurs for moderate to high flux vertical displacements of low density fluid by a higher density fluid in 1-D homogeneous permeable media. viiWe hypothesize the sharpness of wetting front can be explained by competition between two different pore -filling mechanisms (called snap-off and piston-like) with the competition controlled by the velocity of the front and thus the injected flux. We conduct series of infiltration experiments to determine the saturation profile as a function of flux for seven different fluids. We find that for each fluid there is a flux (called overshoot flux) below which saturation overshoot ceases and the front is diffuse. We find that the overshoot flux depends inversely on the invading fluid's viscosity, and shows little or no dependence on the invading fluid's surface tension, vapor pressure, and its miscibility with water.
Three-phase relative permeability is one of the main parameters in flow predictions of tertiary recovery processes in petroleum reservoirs. In particular, an understanding of the hysteresis in three phase relative permeability is essential to describe cyclic processes such as water alternating gas (WAG) injection. Several studies measured three-phase relative permeabilities through steady-state and unsteady-state indirect methods, with their own advantage and disadvantages. Among these, unsteady-state direct measurements are preferred since they mimic the natural reservoir processes while no assumptions are made for relative permeability calculations. But, previous unsteady-state direct measurements of three-phase relative permeability obtained relative permeabilities only during drainage processes. In this work, we extend this method to directly obtain oil and water relative permeabilities during three-phase flow through different flow cycles. The method involves in-situ measurements of phase saturation, and a combination of applied gas and water flow to overcome the limitations of previous direct relative permeability measurements. This method is used to directly measure the three-phase hysteresis effects in relative permeability. Specifically, we perform flow experiments in a 3ft long, vertically oriented sand pack; the sand pack is initialized at a specific oil saturation using two-phase flow. As opposed to previous unsteady-state direct measurements of three-phase permeabilities, gas and water are injected separately as different cycles and, the saturation along the sand pack is measured at different times using computerized tomography scanning. The relative permeability of each phase is then obtained directly from the measured in-situ saturations using Darcy's law. The results show that, we should pick only the middle 40cm of the saturation data to avoid the effect of capillary entry and capillary end effects on saturation data. Experimentally, we find that, the oil relative permeability rises at the beginning of each WAG cycle and then decreases almost as abruptly, with very little dependence on the phase saturations. On the other hand, the water relative permeability remains almost constant. The results also show that, the residual oil saturation decreases during the WAG process at different cycles. The results are discussed in terms of local flow processes, and potential implications for reservoir flooding are given.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
hi@scite.ai
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.