The potential economic benefits offered by CO₂‐enhanced oil recovery (CO₂‐EOR) and storage, including increasing oil production and mitigating CO₂ storage cost, make it an attractive approach for reducing CO₂ emissions. Sealing formation (caprock) integrity is considered a key risk factor, because of the potential for leaked CO₂ or brine migrating into shallow groundwater formations. The primary purpose of this research is to evaluate general caprock sealing efficiency and integrity under typical CO₂‐EOR conditions, by assessing the influence of hydrological and mineralogical heterogeneity, possible mineralogical alteration, and potential failure of rock due to hydrological and mineralogical changes. An active CO₂‐EOR project at the Farnsworth Unit (FWU) in the northern Texas is selected as a case study. A coupled reactive‐transport‐geomechanics model of the FWU caprock (the Morrow Shale and the Thirteen Fingers Limestone) was developed based on site‐specific geological data. Key results suggest that the Thirteen Fingers Limestone is an effective caprock. After 5,000 years, effectively no supercritical CO₂ penetrates this formation, and the penetration depth of dissolved CO₂ in aqueous phase does not exceed 10 m. Because of mineral precipitation in the Morrow Shale, maximum porosity decreases ~25% at the reservoir‐caprock interface, suggesting increased caprock sealing efficiency. Geomechanical response of the caprock due to CO₂ intrusion and mineral alteration suggests low risk of induced fractures. This study provides a refined evaluation of long‐term caprock integrity as a function of coupled hydrological, chemical, and geomechanical processes and is intended to support future assessment of feasibility and safety of geologic CO₂ sequestration.

Geological CO₂sequestration in conjunction with enhanced oil recovery (CO₂‐EOR) includes complex multiphase flow processes compared to CO₂storage in deep saline aquifers. Two of the most important factors affecting multiphase flow in CO₂‐EOR are three‐phase relative permeability and associated hysteresis, both of which are difficult to measure and are usually represented by numerical interpolation models. The purpose of this study is to improve understanding of (1) the relative impacts of different three‐phase relative permeability models and hysteresis models on CO₂trapping mechanisms, and (2) uncertainty associated with these two factors. Four different three‐phase relative permeability models and three hysteresis models were applied to simulations of an active CO₂‐EOR site, the SACROC unit located in western Texas. To eliminate possible bias of deterministic parameters, we utilized a sequential Gaussian simulation technique to generate 50 realizations to describe heterogeneity of porosity and permeability, based on data obtained from well logs and seismic survey. Simulation results of forecasted CO₂storage suggested that (1) the choice of three‐phase relative permeability model and hysteresis model led to noticeable impacts on forecasted CO₂sequestration capacity; (2) impacts of three‐phase relative permeability models and hysteresis models on CO₂trapping are small during the CO₂‐EOR injection period, and increase during the post‐EOR CO₂injection period; (3) the specific choice of hysteresis model is more important relative to the choice of three‐phase relative permeability model; and (4) using the recommended three‐phase WAG (Water‐Alternating‐Gas) hysteresis model may increase the impact of three‐phase relative permeability models and uncertainty due to heterogeneity.

Mineral reactive surface area (RSA) is one of the key factors that control mineral reactions, as it describes how much mineral is accessible and can participate in reactions. This work aims to evaluate the impact of mineral RSA on numerical simulations for CO₂ storage at depleted oil fields. The Farnsworth Unit (FWU) in northern Texas was chosen as a case study. A simplified model was used to screen representative cases from 87 RSA combinations to reduce the computational cost. Three selected cases with low, mid, and high RSA values were used for the FWU model. Results suggest that the impact of RSA values on CO₂ mineral trapping is more complex than it is on individual reactions. While the low RSA case predicted negligible porosity change and an insignificant amount of CO₂ mineral trapping for the FWU model, the mid and high RSA cases forecasted up to 1.19% and 5.04% of porosity reduction due to mineral reactions, and 2.46% and 9.44% of total CO₂ trapped in minerals by the end of the 600-year simulation, respectively. The presence of hydrocarbons affects geochemical reactions and can lead to net CO₂ mineral trapping, whereas mineral dissolution is forecasted when hydrocarbons are removed from the system.

Potential leakage of reservoir fluids is considered a key risk factor for geologic CO₂ sequestration (GCS), with concerns of their chemical impacts on the quality of overlying underground sources of drinking water (USDWs). Effective risk assessment provides useful information to guide GCS activities for protecting USDWs. In this study, we present a quantified risk assessment case study of an active commercial-scale CO₂-enhanced oil recovery (CO₂-EOR) and sequestration field, the Farnsworth Unit (FWU). Specific objectives of this study include: (1) to quantify potential risks of CO₂ and brine leakage to the overlying USDW quality with response surface methodology (RSM); and (2) to identify water chemistry indicators for early detection criteria. Results suggest that trace metals (e.g., arsenic and selenium) are less likely to become a risk due to their adsorption onto clay minerals; no-impact thresholds based on site monitoring data could be a preferable reference for early groundwater quality evaluation; and pH is suggested as an indicator for early detection of a leakage. This study may provide quantitative insight for monitoring strategies on GCS sites to enhance the safety of long-term CO₂ sequestration.

Natural gas hydrates in marine sediments undergo phase transitions under non-equilibrium conditions, making it challenging to accurately measure the permeability characteristics of hydrate-bearing sediments using experimental methods. In this study, pore network modeling is utilized to simulate the hydrate formation process and investigate the singlephase and two-phase permeability of hydrate-bearing sediments, and a comparative analysis was performed on consolidated and unconsolidated sediment samples. The results revealed the evolution of effective permeability as a function of hydrate saturation, and quantitative relationships were observed for the water retention curves and gas-water relative permeability, emphasizing the influence of pore structure and hydrate distribution on flow behavior. On the basis of the simulation results, predictive methods for irreducible water saturation, maximum water saturation, and key parameters in the van Genuchten and Brooks-Corey models for hydrate-bearing sediments are proposed. The findings provide deeper insights into gas-water flow dynamics in hydrate-bearing sediments and offer valuable guidance for hydrate resource exploitation, the assessment of environmental risks associated with hydrate dissociation, and the evaluation of carbon sequestration potential. Document Type: Original article Cited as: Zhang, Y., Liu, L., Luo, L., Ma, J., Ji, Y., Xiao, T., Wu, N. Permeability prediction in hydrate-bearing sediments via pore network modeling. Advances in Geo-Energy Research, 2025, 16(2): 158-170. https://doi.org/10.46690/ager.2025.05.07