|Research Areas & Activities Renewables Hydrogen Carbon-Based Energy Systems Advanced Combustion Advanced Coal CO2 Capture CO2 Storage Electrochemistry and Electric Grid Other Research Analysis Activities Technical Reports||
Carbon-Based Energy Systems > CO2 StorageExperimental Investigations of Multiphase Flow and Trapping of CO2 in Saline Aquifers
Start Date: September 2007
Sally M. Benson, Professor (Research); Jean-Christophe Perrin, Post-doctoral Researcher; Ljuba Miljkovic, Research Associate; Chia-Wei Kuo, Michael Krause, Ethan Chabora, Graduate Researchers, Department of Energy Resources Engineering, Stanford University
The objective is to study fundamental aspects of geologic carbon dioxide storage in saline aquifers. A particular focus is on the methods by which CO2 is immobilized in rock and the parameters that affect immobilization. Relative permeability is such a parameter, and is an essential factor in reservoir dynamics: storage capacity, distribution in injected CO2, number of wells needed, and monitoring plume expansion. Currently, the focus of this work is to investigate the sensitivity of relative permeability to injection flow-rate and various fluid properties such as viscosity, pressure, temperature, and interfacial tension.
This research focuses on the fundamental science underpinning sequestration in saline aquifers. Saline aquifers have the largest sequestration capacity, as compared to oil and gas reservoirs or deep unminable coal beds. Saline aquifers are also more broadly distributed and thus, closer to more emission sources. However, unlike oil and gas reservoirs with proven seals that have withstood the test of time, saline aquifers must be carefully characterized to assure that CO2 will achieve high retention rates. Improved fundamental understanding of multi-phase flow and trapping in CO2-brine systems will be needed to take advantage of this large storage capacity of saline aquifers. Important questions remain to be answered, such as, what fraction of the pore space will be filled with CO2, what will be the spatial extent of the plume of injected CO2, how much and how quickly will CO2 dissolve in brine, and how much CO2 will be trapped by capillary forces when water imbibes back into the plume and to what extent is capillary trapping permanent? To date, these questions have largely been addressed through the use of numerical simulators. Here new experimental data is being developed to improve our ability to answer these questions.
Core-scale multi-phase flow experiments are being carried out to investigate the fundamental processes that underpin these questions. Figure 1 illustrates the four interrelated components of this comprehensive approach. Transient and steady state core-flood experiments at representative reservoir pressure and temperatures are being performed. Each set of experiments involves co-injecting CO2 and brine at a range of fractional flows and a number of different total flow rates. The experimental apparatus can replicate reservoir salinity, temperature, and pressure conditions in the cores. X-ray CT scanning is used to map the spatial distribution of CO2 and brine. Detailed petrophysical analysis of the core is used to obtain three-dimensional maps of porosity, permeability and capillary pressure. Rock properties are used to provide insight into the influence of spatial heterogeneity on the distribution of CO2 and brine in the cores. Rock properties are also used as input to carry out high resolution numerical simulations of the core flood experiments. In addition, traditional steady-state relative permeability measurements have been made during drainage and imbibition.
Figure 1: Illustration of the four interrelated components of the approach to study multiphase flow and trapping in saline aquifer.
To complement the laboratory experiments, numerical simulations are vital for understanding some of the effects observed in the lab that are either too sensitive or time-consuming to investigate experimentally. Using the TOUGH2 MP numerical simulator, the researchers are able to replicate laboratory experiments and model fluid injection and propagation through the rock core. Various parameters such as relative permeability, capillary pressure curves, flow-rate, and rock heterogeneity can be modified to test hypotheses and fine-tune our predictions and understanding of laboratory results. As the research progresses, the researchers will assess which, if any, modifications to multiphase flow theory are needed to replicate the experiments and develop approaches for up-scaling laboratory measured relative permeability curves for use in reservoir-scale simulations.
Restricted Use of Materials from GCEP Site: User may download materials from GCEP site only for User's own personal, non-commercial use. User may not otherwise copy, reproduce, retransmit, distribute, publish, commercially exploit or otherwise transfer any material without obtaining prior GCEP or author approval.