Mechanisms for CO2 Sequestration in Geological Formations and Enhanced Gas Recovery

The growing concern about global warming has increased interest in the geological storage of carbon dioxide (CO₂).

Optimal storage of carbon dioxide (CO₂) in aquifers requires dissolution in the aqueous phase. Nevertheless, transfer of CO₂ from the gas phase to the aqueous phase would be slow if it were only driven by diffusion. Dissolution of CO₂ in water forms a mixture that is denser than the original water or brine. This causes a local density increase, which induces natural convection currents accelerating the rate of CO₂ dissolution. The same mechanism also applies to carbon dioxide enhanced oil recovery. This study compares numerical models 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 but comprehensive 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; a drawback is that it can only be practically applied in bulk flow, i.e., in the absence of a porous medium. All the same many features that occur in a porous medium also occur in bulk, e.g., unstable gravity fingering. The experiments show that natural convection currents are weakest in highly concentrated brine and strongest in oil, due to the higher and lower density contrasts respectively. Therefore, the set-up can screen aqueous salt solutions or oil for the relative importance of natural convection flows. The Schlieren pattern consists of a dark region near the equator and a lighter region below it. The dark region indicates a region where the refractive index increases downward, either due to the presence of a gas liquid interface, or due to the thin diffusion layer, which also appears in numerical simulations. The experiments demonstrate the initiation and development of the gravity induced fingers. The experimental results are compared to numerical results. It is shown that natural convection effects are stronger in cases of high density differences. However, due to numerical limitations, the simulations are characterized by much larger fingers.

The growing concern about global warming has increased interest in improving the technology for the geological storage of carbon dioxide (CO₂) in aquifers. One issue is the limited storage space for carbon dioxide. Part of the storage space is in a gas tongue overlaying the aquifer. However, more storage space is available in aquifer. Storage in the aquifer has the advantage that the partial molar volume of dissolved carbon dioxide is about twice as small as the partial molar volume of the gas phase under optimal conditions. One important aspect for aquifer storage is the rate of transfer between the overlying gas layer and the aquifer below. It is generally accepted that density driven natural convection is an important mechanism that enhances the mass transfer rate. The density effects occur because water with dissolved carbon dioxide has a higher density than fresh water or brine. There is a lack of experimental work that study the transfer rate into water saturated porous medium at in situ conditions, i.e., above critical temperatures and at pressures above 60 bar. Representative natural convection experiments require relatively large volumes (e.g., a diameter 8.5 cm and a length of 23 cm). We studied the transfer rate experimentally for both fresh water and brine (2.5, 5 and 10 w/w %). The experiment uses a high pressure ISCO pump to keep the pressure constant and allows determining the corresponding injection rate and cumulative injected volume. To our knowledge this is the first transfer experiments at constant pressure. A log-log plot reveals that the mass transfer rate is proportional to t^0.8, and thus much faster than the predicted by Fick’s law in the absence of natural convection currents. Moreover, the experiments show that natural convection currents are weakest in highly concentrated brine and strongest in pure water.

Shale gas resources are globally abundant and the development of these resources can increase CH₄ production. It is of interest to study the possibility of enhancing CH₄ production by CO₂ injection (Enhanced Gas Recovery—EGR). Some studies indicate 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. 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 on Belgium dry black shale from a depth of 745 m. The shale was obtained from a former coal mine in Zolder in the Campina Basin (North Belgium), which contains Westphalian coal and coal associated sediments of Northwest European origin. We derive the equations for excess sorption in the manometric set-up. Only a few measurements have been reported in the literature for high-pressure gas sorption on shales, and interest is largely focused on shales occurring outside Europe. The excess sorption isotherm shows an initial increase to a maximum value of 0.175 ± 0.004 mmol/g for CO₂ and then starts to decrease until it becomes zero at 82 bar and subsequently the excess sorption becomes negative. Similar behaviour was also observed for other shales and coal reported in the literature. The experiments on CH₄ show, as expected, decreasing sorption for increasing temperature. We apply an error analysis based on Monte-Carlo simulation. It shows that the error is increasing with increasing pressure, but that the manometric set-up can be used to determine the sorption capacity of CO₂ and CH₄ on the black shale with sufficient accuracy.

Shale gas resources are proving to be globally abundant and the development of these resources can support the geologic storage of CO₂ (carbon dioxide) to mitigate the climate impacts of global carbon emissions from power and industrial sectors. This chapter reviews global shale gas resources and considers 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 is significant, but knowledge of the characteristics of the different types of shale gas 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. Based on this review, we conclude that there is a very good opportunity globally regarding the future of geologic storage of CO₂ in depleted shale gas formations and as part of EGR operations.

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 or solid phase. It is asserted that the transfer considerably enhances the storage capacity in geological formations. The main conclusions are first summarized before the chapter wise conclusions are repeated for the ease of reference.