CO2 Storage Potential Reconnaissance of the Newly Identified Red Beds of Hazlehurst in the Southeastern United States

The states of Georgia and South Carolina emitted ∼100 million tons (Mt) of CO2 in 2019 from point sources. Integration and interpretation of subsurface data enabled identification of a previously unrecognized, regionally extensive, and thick (up to 450 m) sedimentary sequence—the Red beds of Hazlehurst (RbH)—as a potential saline reservoir for CO2 storage in the southeastern United States. Based on the renewed stratigraphic framework and structural interpretation of the RbH interval, we analyzed detailed well logs and the depositional environments to provide reconnaissance-level regional scale estimations of the storage resource. The volumetric results suggest the effective storage area (∼85,000 km2) has a maximum resource potential for 390 gigatons (Gt) of anthropogenic CO2. Petrophysical measurements suggest the permeability of RbH ranges from 0.001 to 48 mD, and the porosity ranges from 11.1 to 18.4%. Residual/capillary trapping and solubility trapping act as the main trapping mechanisms for long term storage and prevent vertical migration of CO2 into the shallow freshwater aquifers. Due to the heterogeneity observed in geophysical logs and the scarcity of well penetrations, future data collection is needed to characterize the storage aquifer and confining aquitards of a site-specific system at this stage.

Pore-Scale Imaging and Analysis of Wettability Order, Trapping and Displacement in Three-Phase Flow in Porous Media with Various Wettabilities

Three-phase flow in porous media is encountered in many applications including subsurface carbon dioxide storage, enhanced oil recovery, groundwater remediation and the design of microfluidic devices. However, the pore-scale physics that controls three-phase flow under capillary dominated conditions is still not fully understood. Recent advances in three-dimensional pore-scale imaging have provided new insights into three-phase flow. Based on these findings, this paper describes the key pore-scale processes that control flow and trapping in a three-phase system, namely wettability order, spreading and wetting layers, and double/multiple displacement events. We show that in a porous medium containing water, oil and gas, the behaviour is controlled by wettability, which can either be water-wet, weakly oil-wet or strongly oil-wet, and by gas–oil miscibility. We provide evidence that, for the same wettability state, the three-phase pore-scale events are different under near-miscible conditions—where the gas–oil interfacial tension is ≤ 1 mN/m—compared to immiscible conditions. In a water-wet system, at immiscible conditions, water is the most-wetting phase residing in the corners of the pore space, gas is the most non-wetting phase occupying the centres, while oil is the intermediate-wet phase spreading in layers sandwiched between water and gas. This fluid configuration allows for double capillary trapping, which can result in more gas trapping than for two-phase flow. At near-miscible conditions, oil and gas appear to become neutrally wetting to each other, preventing oil from spreading in layers; instead, gas and oil compete to occupy the centre of the larger pores, while water remains connected in wetting layers in the corners. This allows for the rapid production of oil since it is no longer confined to movement in thin layers. In a weakly oil-wet system, at immiscible conditions, the wettability order is oil–water–gas, from most to least wetting, promoting capillary trapping of gas in the pore centres by oil and water during water-alternating-gas injection. This wettability order is altered under near-miscible conditions as gas becomes the intermediate-wet phase, spreading in layers between water in the centres and oil in the corners. This fluid configuration allows for a high oil recovery factor while restricting gas flow in the reservoir. Moreover, we show evidence of the predicted, but hitherto not reported, wettability order in strongly oil-wet systems at immiscible conditions, oil–gas–water, from most to least wetting. At these conditions, gas progresses through the pore space in disconnected clusters by double and multiple displacements; therefore, the injection of large amounts of water to disconnect the gas phase is unnecessary. We place the analysis in a practical context by discussing implications for carbon dioxide storage combined with enhanced oil recovery before suggesting topics for future work.

A New Approach To Improve The Assessments of CO2 Geo-Sequestration Capacity of Clay Minerals

CO2 geological storage (CCS)isconsidered as the most promising technique to reduce atmospheric CO2emissions. However, due to the density variation between the injected supercritical CO2 and the formation water,CO2 tends to move vertically toward the air. This vertical CO2 leakage can be prevented by four trapping mechanisms (i.e. structural trapping,capillary trapping, solubility trapping, and mineral trapping). The capacities of structural and residual trapping are highly affected by rock wettability. Clay wettability is one of the crucial parametersin evaluation of CO2 geo-sequestration. However, the literature data show that there are many uncertainties associated with experimental measurements. One of these uncertainties is the influenceof the effect of gas density on the clay mineral wettability. Thus, here, we compared the wettability of a clay mineral (i.e. illite) of three different gas densities scenarios (i.e. low (Helium), moderate (Nitrogen), and high (CO2) gas densities). To do so, we measured the advancing and receding contact angle (i.e. wettability) of illite for CO2/water, nitrogen/water, and Helium/water systems at a constant (333 K) and four different pressures (5, 10, 15, and 20 MPa). The brine composition used was 4 wt% NaCl, 4 wt% CaCl2, 1 wt% MgCl2 and 1 wt% KCl, for all gas density scenarios. The results indicate that gas density has a significant effect on the clay mineral wettability and that both advancing and receding contact angles increase with an increase in gas density. The results show that a higher density gas scenario has a higher contact angle of illite, measured at the same temperature and pressure. For instance, the advancing contact angle of illite at 333 K and 20 MPa was 65° for the CO2/water system, 53° for the nitrogen/water system, and 50° for Helium/water Helium/water system. Thus, we conclude that the gas density affects the Clay wettability measurement and that the higher gas density leads to a higher contact angle measurements (i.e. a more CO2-wet system) of the clay and thus reduces the estimated CO2 geo-sequestration capacity and containment security.

Dissolution Mass Transfer of Trapped Phase in Porous Media

Dissolution mass transfer of trapped phase (TP) to flowing phase (FP) in porous media plays significant roles in hydrogeology, e.g., groundwater contamination by non-aqueous phase liquids, groundwater in-situ bioremediation, and geological carbon sequestration. In this chapter, this phenomenon is described. First, the physical and mathematical models are given. Afterwards, various conditions affecting this process, i.e., porous media characteristics, capillary trapping characteristics, flow bypassing, TP characteristics, and FP velocity, are discussed. These various conditions are described based on three parameters affecting the dissolution mass transfer: TP interfacial area ( A ), TP dissolution ratio ( ξ ), and mass transfer coefficient ( k ). Eventually, models to predict the mass transfer are formulated based on non-dimensional model. All of the data in this chapter are based on the experiments obtained by using micro-tomography and a series of image processing techniques from our latest works.