Mechanisms for CO2 Sequestration in Geological Formations and Enhanced Gas Recovery

Abstract

The work described in this thesis deals with a variety of aspects related to the storage of carbon dioxide in geological formations. In particular we focus on the transfer between the gas phase to a fluid (liquid) or solid phase. This thesis limits its interest to study the sequestration capacity of CO2 in saline aquifers and more specifically on the mass transfer between CO2 and the brine, show the effect of salinity and visualize the fingering of CO2 rich brine in bulk phase outside a porous medium by applying Schlieren technique. Furthermore, we also illustrate the importance of shale formations in the world for storing carbon dioxide and our experimental methods to measure the sorption capacity for enhanced gas recovery- EGR. To achieve our goals we designed, constructed and improved three different setups. The main research objectives addressed in this thesis are: (1) to investigate, experimentally and numerically, the mass transfer rate of CO2 to water (brine), oil (2) visualization of natural convection flow of CO2 in aqueous and oleic systems, (3) to illustrate the effect of salinity on the transfer rate of CO2 in bulk and porous media, (4) to model natural convection instability of CO2 rich fluid flow in the bulk aqueous and oleic phase, (5) to determine the sorption capacity of shale experimentally by applying the manometric method and estimate errors based on a Monte-Carlo simulation, (6) to review shale gas formations and their potential for CO2 storage. Each chapter is summarized as follows: In chapter 2, we compare numerical model results with a set of high pressure visual experiments, based on the Schlieren technique, in which we observe the effect of gravity-induced fingers when sub- and super-critical CO2 at in situ pressures and temperatures is brought above the liquid, i.e., water, brine or oil. A short description of the Schlieren set-up and the transparent pressure cell is presented. The Schlieren set-up is capable of visualizing instabilities in natural convection flows in the absence of a porous medium. The experiments illustrate that natural convection currents are weakest in the highly concentrated brine and strongest in oil. Therefore, the set-up can rank aqueous salt solutions or oil in sequence of its relative importance of natural convection flows and the ensuing enhanced transfer. The experimental results are compared to numerical results. It is shown that natural convection effects are stronger in cases of high density differences. To our knowledge there are no visual data in the literature for natural convection flow of CO2 in the aqueous and oleic phase in equilibrium with supercritical CO2. Indeed, there is no available experiment for CO2-oil. There are no data in the literature that show the presence of a diffusive boundary layer and the continuous initiation of fingers. In chapter 3 we experimentally investigated the effect of salinity and pressure on the rate of mass transfer, for aquifer storage of carbon dioxide in porous media. There is a large body of literature that numerically and studies analytically the storage capacity and the rate of transfer between the overlying CO2-gas layer and the aquifer below. There is, however, a lack of experimental work that address the transfer rate into a water-saturated porous medium at in-situ conditions using carbon dioxide and brine at elevated pressures. We emphasize that the experiment uses a constant gas pressure and measures the dissolution rate using a high pressure ISCO pump. It is shown that the transfer rate is much faster than predicted by Fick’s law in the absence of natural convection currents. Chapter 4 investigates the sorption of CH4 and CO2 in Belgian Carboniferous Shale, using a manometric set-up. Only a few measurements have been reported in the literature for highpressure gas sorption on shales. Some recent studies illustrate that, in shale, five molecules of CO2 can be stored for every molecule of CH4 produced. The technical feasibility of Enhanced Gas Recovery (EGR) needs to be investigated in more detail. Globally, the amount of extracted natural gas from shale has increased rapidly over the past decade. A typical shale gas reservoir combines an organic-rich deposition with extremely low matrix permeability. One important parameter in assessing the technical viability of (enhanced) production of shale gas is the sorption capacity. Our focus is on the sorption of CH4 and CO2. Therefore we have chosen to use the manometric method to measure the excess sorption isotherms of CO2 at 318 K and of CH4 at 308, 318 and 336 K and at pressures up to 105 bar. We apply an error analysis based on Monte-Carlo simulation to establish the accuracy of our experimental data. Chapter 5 reviews the global shale gas resources and discusses both the opportunities and challenges for their development. It then provides a review of the literature on opportunities to store CO2 in shale, thus possibly helping to mitigate the impact of CO2 emissions from the power and industrial sectors. The studies reviewed indicate that the opportunity for geologic storage of CO2 in shales might be significant, but knowledge of the characteristics of the different types of gas shales found globally is required. The potential for CO2 sorption as part of geologic storage in depleted shale gas reservoirs must be assessed with respect to the individual geology of each formation. Likewise, the introduction of CO2 into shale for enhanced gas recovery (EGR) operations may significantly improve both reservoir performance and economics. In chapter 6 the main conclusions of the thesis are summarized.Geoscience & EngineeringCivil Engineering and Geoscience