How CO2 Rewrites the Wetting Rules of Shale: A New Review Maps the Science of Carbon Storage

Buried deep beneath the surface, in the nanometer-scale pores of shale formations, a quiet chemical drama unfolds every time carbon dioxide is injected into the ground. The way CO2, brine, and rock interact at those invisible interfaces—whether water clings to mineral surfaces or retreats from them—may ultimately decide whether carbon capture and storage succeeds or fails. A comprehensive new review published in Environmental Earth Sciences by Chao Luo of Chongqing University of Science & Technology and colleagues synthesizes the state of the art in wettability alteration of the CO2-water-shale system, offering both a technical roadmap and a candid list of what science still does not know.

Wettability, in essence, describes how fluids spread over and adhere to rock surfaces. It is quantified through the contact angle, the angle formed where a droplet meets a solid at a three-phase junction, governed thermodynamically by the Young-Laplace equation. For CO2-brine-rock systems, researchers classify wettability into five regimes based on the brine contact angle: strong water-wetness from 0 to 50 degrees, weak water-wetting from 50 to 70 degrees, neutral wetting between 70 and 110 degrees, mild CO2 or oleic wetting from 110 to 130 degrees, and strong CO2 or oil-wetting from 130 to 180 degrees. These angular thresholds are far from academic trivia. When a shale surface shifts from water-wet toward weakly water-wet, residual water becomes trapped and crude oil movement is restricted. Conversely, if a caprock turns CO2-wet, its sealing performance deteriorates and the risk of CO2 leakage rises sharply.

The review highlights how the field has moved beyond the limitations of conventional bulk contact-angle testing. Researchers now deploy integrated multi-scale schemes: nanoscale in-situ atomic force microscopy, microscale visualization using shale-based microfluidic chips, and macroscale joint measurements via nuclear magnetic resonance and mercury injection capillary pressure. Molecular dynamics simulations fill in the extreme conditions that laboratory experiments cannot reach, modeling fluid behavior in nanoslits under reservoir temperatures and pressures. On the bulk scale, NMR-based methods built on spontaneous imbibition trials yield a Normalized Wettability Index ranging from −1, indicating complete oil-wettability, to +1, indicating complete water-wettability, with values between −0.5 and 0.5 signifying the mixed-wettability states common in organic-rich shales.

Yet the measurement landscape remains fragmented. Contact angles measured at different locations, or with different techniques, can yield contradictory results, with deviations between macroscopic contact angle measurements, microscopic NMR, and nanoscale molecular simulation reaching 15 to 20 percent. The sessile drop method works only on ideal smooth surfaces; the captive bubble technique reduces brine diffusion errors but suffers from alignment issues; the Wilhelmy plate and tilted plate methods each carry their own constraints. Because real CO2 injection involves penetration into pore spaces rather than spreading across flat surfaces, discrepancies between pore-scale and core-scale data persist, and no unified correction system yet exists.

The controlling factors of wettability alteration form the mechanistic heart of the review. Temperature effects remain controversial: some experiments show contact angles dropping as temperature rises, consistent with increasing CO2-brine interfacial tension, while others report the opposite or negligible trends. Molecular dynamics studies generally agree that above the critical temperature of 304.41 K, water droplets flatten and their contact angles decrease progressively, but the smooth, single-mineral substrates assumed in most simulations diverge from real reservoir conditions. Pressure, by contrast, more consistently pushes shale toward CO2-wettability: rising pressure increases CO2 density and strengthens intermolecular adhesion between rock and CO2 molecules, while reducing CO2-brine interfacial tension. Under extreme supercritical conditions of 30 MPa and 343 K, the review notes, system wettability may even undergo complete reversal to a fully CO2-wet state.

Salinity and ion type add another layer of complexity. Higher salinity increases advancing and receding contact angles and drives shale from hydrophilic toward mixed and CO2-wet states, a mechanism explained by electrical double layer screening: dissolved ions adsorb onto oppositely charged rock surfaces, forming hydrophobic layers that reduce surface polarity. Divalent ions outperform monovalent ones in this regard. Experimental data show contact angles rising from 26 to 31 degrees for NaCl and from 29 to 43 degrees for MgCl2 as concentration increases from 0.1 to 1.0 molar, with the hydrophobic effect ordered MgCl2 greater than CaCl2 greater than NaCl. High-salinity environments enhance CO2 permeation tendencies, which the authors flag as unfavorable for both shale gas exploitation and geological storage.

Organic matter introduces perhaps the most consequential variable. Total organic carbon content generally correlates with increasing CO2-wettability: shales with high TOC tend to be CO2-wet, while low-TOC shales remain strongly water-wet and are better suited as caprocks. But the relationship is not universal. In the Silurian Longmaxi marine shale of the Sichuan Basin, contact angle varies parabolically with TOC, first decreasing and then increasing, a pattern attributed to how mobile organic components distribute within the matrix. In Permian and Triassic transitional and terrestrial shales, the correlation inverts, likely governed by organic maceral composition—vitrinite being more water-wet, liptinite more oil-wet. Even shales with TOC as high as 7.9 percent can remain hydrophilic overall when the mineral assemblage, which constitutes 80 to 90 percent of sample volume, dominates the wetting behavior.

Chemical reactions compound these effects over time. Dissolved CO2 forms carbonic acid, whose hydrogen ions attack feldspar, carbonate, and clay minerals, reshaping pore-throat structures and mineral compositions. X-ray diffraction studies after supercritical CO2 exposure show elevated quartz proportions alongside reduced carbonate and clay abundances. Mineral dissolution enlarges pores and reduces water-wettability, while secondary precipitation of newly formed minerals can block throats and, in the long run, enable the most stable form of carbon trapping: mineral trapping. Surface chemistry shifts in parallel, as acidic conditions catalyze the condensation of hydrophilic silanol groups into Si-O-Si linkages, reducing hydrogen bonding with water and raising contact angles.

The review is unflinching about the field’s gaps. Most experiments run for less than 168 hours, far too short to capture the slow extraction of organic matter and continuous mineral dissolution that unfold over years or decades in actual reservoirs, processes that could trigger a secondary wettability reversal. Laboratory cores measuring 25 by 50 millimeters cannot account for fracture distribution and lithofacies heterogeneity at kilometer-scale reservoirs, and no scale-conversion verification has yet been performed. Machine learning models trained on simple mineral systems—using algorithms from support vector machines to random forests and adaptive neuro-fuzzy inference systems—struggle to capture the complexity of real shale, though emerging approaches embed physical constraints such as interfacial tension thermodynamics directly into loss functions.

The practical stakes are considerable. The authors identify a favorable lithological assemblage for storage site selection: high-TOC shale in the lower interval, suited to adsorption trapping—which accounts for nearly 98 percent of trapped gas in shale—capped by low-TOC, water-wet shale above for structural trapping. Wettability regulation technologies, including anionic surfactants such as alpha-olefin sulfonates, nanoparticle treatments with SiO2 and Al2O3, and surfactant foams, have achieved 18 to 25 percent recovery improvements at laboratory scale, though engineering applicability remains unproven. Even microbial effects, mediated through biosurfactants and biofilm-induced changes to pore geometry, remain nearly unstudied in shale-CO2 systems. As the world pursues dual goals of shale hydrocarbon development and industrial carbon reduction, the review makes clear that mastering the invisible chemistry of wetting—at scales from single molecules to entire basins—is the prerequisite for storing CO2 safely beneath our feet.

Subject of Research: Wettability alteration of the CO2-water-shale system and its implications for geological carbon storage and enhanced shale hydrocarbon recovery

Article Title: Wettability alteration of CO2-water-shale system: state of the art and future directions

Article References: Luo, C., Yin, X., Zeng, B., Yuan, J., Huo, X., Lin, H., & Yin, N. (2026). Wettability alteration of CO2-water-shale system: state of the art and future directions. Environmental Earth Sciences, 85(16), Article 428. https://doi.org/10.1007/s12665-026-13163-1

Image Credits: AI Generated

DOI: 10.1007/s12665-026-13163-1

Keywords: wettability alteration, CO2 geological storage, shale reservoirs, contact angle, carbon sequestration, total organic carbon, molecular dynamics simulation, nuclear magnetic resonance, caprock integrity, brine salinity, supercritical CO2, enhanced oil recovery