[1] We report the results of an experimental investigation into the multiphase flow properties of CO2 and water in four distinct sandstone rocks: a Berea sandstone and three reservoir rocks from formations into which CO2 injection is either currently taking place or is planned. Drainage relative permeability and residual gas saturations were measured at 50 � C and 9 MPa pore pressure using the steady state method in a horizontal core flooding apparatus with fluid distributions observed using x-ray computed tomography. Absolute permeability, capillary pressure curves, and petrological studies were performed on each sample. Relative permeability in the four samples is consistent with general characteristics of drainage in strongly water-wet rocks. Measurements in the Berea sample are also consistent with past measurements in Berea sandstones using both CO2/brine and oil/water fluid systems. Maximum observed saturations and permeabilities are limited by the capillary pressure that can be achieved in the experiment and do not represent endpoint values. It is likely that maximum saturations observed in other studies are limited in the same way and there is no indication that low endpoint relative permeabilities are a characteristic of the CO2/water system. Residual trapping in three of the rocks is consistent with trapping in strongly water-wet systems, and the results from the Berea sample are again consistent with observations in past studies. This confirms that residual trapping can play a major role in the immobilization of CO2 injected into the subsurface. In the Mt. Simon sandstone, a nonmonotonic relationship between initial and residual CO2 saturations is indicative of a rock that is mixed or intermediate wet, and further investigations should be performed to establish the wetting properties of illite-rich rocks. The combined results suggest that the petrophysical properties of the multiphase flow of CO2/water through siliciclastic rocks is for the most part typical of a strongly water-wet system and that analog fluids and conditions may be used to characterize these properties. Further investigation is required to identify the wetting properties of illite-rich rocks during imbibition processes.

https://agupubs.onlinelibrary.wiley.com/doi/pdf/10.1029/2011WR010859

Relative permeability and trapping of CO2 and water in sandstone rocks at reservoir conditions

A review of developments in carbon dioxide storage

Hydrocarbon production, gas recovery from shale, CO2 storage and water management have a common scientific underpinning: multiphase flow in porous media. This book provides a fundamental description of multiphase flow through porous rock, with emphasis on the understanding of displacement processes at the pore, or micron, scale. Fundamental equations and principal concepts using energy, momentum, and mass balance are developed, and the latest developments in high-resolution three-dimensional imaging and associated modelling are explored. The treatment is pedagogical, developing sound physical principles to predict flow and recovery through complex rock structures, while providing a review of the recent literature. This systematic approach makes it an excellent reference for those who are new to the field. Inspired by recent research, and based on courses taught to thousands of students and professionals from around the world, it provides the scientific background necessary for a quantitative assessment of multiphase subsurface flow processes, and is ideal for hydrology and environmental engineering students, as well as professionals in the hydrocarbon, water and carbon storage industries.

Multiphase Flow in Permeable Media: A Pore-Scale Perspective

We review the literature data published on the topic of CO2 wettability of storage and seal rocks. We first introduce the concept of wettability and explain why it is important in the context of carbon geo-sequestration (CGS) projects, and review how it is measured. This is done to raise awareness of this parameter in the CGS community, which, as we show later on in this text, may have a dramatic impact on structural and residual trapping of CO2. These two trapping mechanisms would be severely and negatively affected in case of CO2-wet storage and/or seal rock. Overall, at the current state of the art, a substantial amount of work has been completed, and we find that: 

Sandstone and limestone, plus pure minerals such as quartz, calcite, feldspar, and mica are strongly water wet in a CO2-water system.
Oil-wet limestone, oil-wet quartz, or coal is intermediate wet or CO2 wet in a CO2-water system.
The contact angle alone is insufficient for predicting capillary pressures in reservoir or seal rocks.
The current contact angle data have a large uncertainty.
Solid theoretical understanding on a molecular level of rock-CO2-brine interactions is currently limited.
In an ideal scenario, all seal and storage rocks in CGS formations are tested for their CO2 wettability.
Achieving representative subsurface conditions (especially in terms of the rock surface) in the laboratory is of key importance but also very challenging.

/pdf/co2-wettability-of-seal-and-reservoir-rocks-and-the-35f14mfo2e.pdf

CO2 wettability of seal and reservoir rocks and the implications for carbon geo-sequestration

Capillary trapping for geologic carbon dioxide storage - From pore scale physics to field scale implications

Drainage and Imbibition Relative Permeability Relationships for Supercritical CO2/Brine and H2S/Brine Systems in Intergranular Sandstone, Carbonate, Shale, and Anhydrite Rocks

Carbon dioxide capture and geological storage (CCGS) is an emerging technology that is increasingly being considered for reducing greenhouse gas emissions to the atmosphere. Deep saline aquifers provide a very large capacity for CO2 storage and, unlike hydrocarbon reservoirs and coal beds, are immediately accessible and are found in all sedimentary basins. Proper understanding of the displacement character of CO2-brine systems at in-situ conditions is essential in ascertaining CO2 injectivity, migration and trapping in the pore space as a residual gas or supercritical fluid, and in assessing the suitability and safety of prospective CO2 storage sites. Because of lack of published data, the authors conducted a program of measuring the relative permeability and other displacement characteristics of CO2-brine systems for sandstone, carbonate and shale formations in central Alberta in western Canada. The tested formations are representative of the in-situ characteristics of deep saline aquifers in compacted on-shore North American sedimentary basins. The results show that the capillary pressure, interfacial tension, relative permeability and other displacements characteristics of CO2-brine systems depend on the in-situ conditions of pressure, temperature and water salinity, and on the pore size distribution of the sedimentary rock. This paper presents a synthesis and interpretation of the results.

Effects of in-situ conditions on relative permeability characteristics of CO 2 -brine systems

Relative Permeability Characteristics for Supercritical CO2 Displacing Water in a Variety of Potential Sequestration Zones

Relative Permeability Characteristics for Supercritical CO2 Displacing Water in a Variety of Potential Sequestration Zones in the Western Canada Sedimentary Basin

Brant Bennion

Papers

Drainage and Imbibition Relative Permeability Relationships for Supercritical CO2/Brine and H2S/Brine Systems in Intergranular Sandstone, Carbonate, Shale, and Anhydrite Rocks

Effects of in-situ conditions on relative permeability characteristics of CO 2 -brine systems

Relative Permeability Characteristics for Supercritical CO2 Displacing Water in a Variety of Potential Sequestration Zones

Relative Permeability Characteristics for Supercritical CO2 Displacing Water in a Variety of Potential Sequestration Zones in the Western Canada Sedimentary Basin