Once injected, CO₂ does not stay in one place. CO₂ storage depends on a variety of trapping mechanisms to ensure long-term storage. Once in the reservoir, CO₂ interacts with the resident brine water, minerals, and other chemicals in the subsurface, determining its ultimate destination. Predicting the movement of CO₂ is a crucial step in the monitoring of carbon capture and storage projects which the Gulf Coast Carbon Center (GCCC) specializes in.

The primary trapping mechanism for a CO₂ storage project is the overlying nonporous caprock that restricts the vertical, buoyant flow of CO₂. A secondary trapping mechanism called residual trapping is a major contributor to the volumes of CO₂ that can be stored.

Residual trapping can occur when two immiscible fluids flow together in porous media. The porous media is usually “wetting” to one fluid and “nonwetting” to another. Wetting is the ability of water to spread out and cover a substrate, often in water-loving or “hydrophilic” settings. Typically, water is the wetting medium and CO₂ is the nonwetting. When both flow through the porous media, water surrounds the nonwetting fluid (CO₂) and restricts its movement. This causes trapping at the individual rock grain level, so that CO₂ does not have enough driving force to get out of the microscopic spaces between grains.

GCCC’s newest post-doctoral student, Hailun Ni, studies two different types of residual trapping: pore-scale and mesoscale capillary heterogeneity trapping at carbon storage sites. Mesoscale captures rock at the millimeter scale and pore scale looks at rock within the micron range and smaller. At the mesoscale, rock heterogeneities such as lamination can act like tiny caprocks, restricting the flow of CO₂ and trapping it securely underneath.  

Ni’s research, under the guidance of Tip Meckel, is a unique addition to our research consortium because we have scientists working on the pore-scale and reservoir trapping, but not in between. By constraining the movement of CO₂ at these different scales, we have a more accurate prediction of CO₂ movement in the subsurface, therefore decreasing risk.

Before joining GCCC, Ni earned her Ph.D. from Stanford University where she studied Energy Resources Engineering under Sally Benson. On Tuesday, Ni gave a talk during the weekly GCCC staff meeting regarding her Ph.D. research.

Read more about her results and study design in her publication, “Predicting CO₂ residual trapping ability based on experimental petrophysical properties for different sandstone types.”

 

As part of her Ph.D. research, Ni conducted coreflooding experiments and CT imaging to characterize and quantify the impact of small-scale heterogeneity on CO₂-water capillary flow and residual trapping with sandstone cores. During her talk titled, “Coreflooding experiments and prediction of CO₂ residual trapping,” Ni covered the first half of her Ph.D. thesis.

Many studies have been conducted using microCT scans which do not capture the mesoscale heterogeneity of rocks, which can have a significant influence on flow. No previous studies have used real rocks to quantify the relative contribution of the two different CO₂ residual trapping mechanisms for different sandstone types.

In order to find residual trapping rates, she used an experimental apparatus that injects CO₂ in nine representative sandstone cores with varying petrophysical properties. For most of the cores, the flow rates of CO₂ remained the same during injection throughout the experiment. The core was initially soaked with water, and the injection fluid was initially composed of half CO₂ and half water. Gradually, the ratio of CO₂ was increased in the injectate until it was 100 percent CO₂ which was plotted as the initial CO₂ saturation value. Then, the CO₂ ration was decreased until the injectate was 100 percent water, which was the final value for residual saturation.

The results of the experiment help distinguish the relative importance of the two residual trapping mechanisms. Experimental results demonstrate that CO₂ residual trapping ability decreases with porosity and increases with the degree of heterogeneity. In order to quantify the level of heterogeneity in a sample, Ni and colleagues also evaluated a number of metrics that act as proxies for heterogeneity. Ni found that the two best predictors for a sandstone core’s CO₂ residual trapping ability are porosity and the maximum standard deviation in the drainage CO₂ saturation field. As stated in the paper, additional results indicate that “pore-scale trapping mechanisms account for 46–97% of the residually trapped CO₂ and the mesoscale capillary heterogeneity trapping mechanism accounts for 3–54% of the residually trapped CO₂ for the nine sandstone samples tested.”

Ni’s next steps are to ask geological questions: What simple parameters can be used to infer more difficult parameters in order to characterize the regional-scale geology? During the preliminary discussion, one of our researchers suggested that cementation, minerology, and depositional facies can derive other parameters, and could be a launching point for Ni’s future work with the GCCC.

As for her work with the GCCC, Ni will continue to build on the work of previous Ph.D. student Prasanna Krishnamurthy to build sand tanks with realistic sedimentary structures and conduct capillary-dominated, gravity-driven multiphase flow experiments with the light transmission visualization method to study how different types of heterogeneity affect CO₂ migration and capillary heterogeneity trapping (local capillary trapping) at a larger scale. 

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