The influence of temperature on wettability alteration during CO2 storage in saline aquifers

A Numerical Study of Fault Reactivation Mechanisms in CO2 Storage

Due to extensive industrialization and ongoing fossil fuel consumption, CO2 emissions have significantly contributed to climate change and rising greenhouse gas levels. The collection and storage of CO2 in subsurface geological formations have been proposed as a feasible alternative. The well-documented In Salah storage site is the subject of the chosen case study. For the numerical analysis, a two-dimensional finite element simulation of fault reactivation processes was conducted in the context of the CO2 storage. The goal of this research is to conduct a mechanistic numerical analysis of a typical CO2 storage condition. The selected analysis domain is 4 km (width) × 2 km (depth) and includes all important domains and formations (overburden, main caprock, lower caprock, and underburden) of the In Salah site. The simulation results indicate that the influence of fault reactivation under 32 MPa of base injection pressure results in peak vertical deformation of 0.044 m in the caprock and a vertical displacement magnitude of 0.015-0.020 m at the surface level (Z = 0 m). The derived vertical deformation findings at the surface level are in agreement with the data obtained from the in situ InSAR monitoring system in 2009. The effects of the changes in the fault dip angle, key caprock mechanical parameters, and in situ stress ratio on the displacement profile are evaluated within the parametric study. In comparison to the benchmark numerical run, the scenario ratio of k = 0.5 led to a significant reduction in the displacement. The simulation in which the fault dip angle was 30° produced a more pessimistic result with a larger displacement field. This could be an indication of heightened fault reactivation risks associated with low-angle faults in storage sites with strong horizontal stress regimes due to the combined effect of increased shear stress and reduced inherent frictional resistance on the fault plane. Considering that a vertical fault dip angle (90°) and an additional three 20 m long vertical fractures above the reservoir produced similar vertical displacement observed with the fault dipping at a 60° angle, this indicated that the vertical faults in the vicinity of the storage site pose limited safety risks to the integrity of the sealing rock.

A Guide for Selection of Aging Time and Temperature for Wettability Alteration in Various Rock-Oil Systems

Wettability alteration has been identified to be one of the important mechanisms to improve the microscopic recovery in many of the enhanced oil recovery (EOR) methods including polymer flood, surfactant flood, low salinity flood, microbial flood, alkaline flood, etc. Ensuring the oil-wet nature of the formation before flooding in the laboratory is necessary to study the efficiency of the EOR process, which targets microscopic recovery through wettability alteration. Nevertheless, altering the wettability depends on several parameters, such as aging time, aging temperature, core nature, oil properties, etc. Although several researchers investigated the effect of individual parameters on wettability alteration, the literature is scarce, and the question of what is the shortest and yet the most reliable aging time for ensuring wettability alteration for the specific rock-oil system at different temperatures remains unclear. This paper attempts to seek an answer to this question by compiling the relevant literature to find the effect of individual parameters such as different aging times, temperatures, oil compositions, and rock lithologies on wettability alteration. Results observed from data analysis showed different windows for aging conditions depending on the core sample lithology, initial wettability, and type of oil used. It was noticed that the higher the asphaltene content in the crude oil used, the lower the time and temperature that it takes to alter the sample wettability. Aging a sandstone core under 80 °C using crude oil with 11 wt % % asphaltene took 7 days to shift the core from strongly water-wet to neutral-wet. The same wettability alteration was achieved in 14 days when aging the sandstone sample at 90 °C using crude oil with 0.85 wt % asphaltene content. Generally, it was observed that the aging time decreased as the temperature increased. Moreover, as the sample has a lower initial water wettability condition, the time that it needs to be aged becomes higher. Results indicated that carbonates in general require less aging time to alter their wettability condition to oil-wet, around 1-7 days, compared with sandstones, around 14-21 days.

Experimental Study on Relative Permeability Characteristics for CO2 in Sandstone under High Temperature and Overburden Pressure

In this study, CO2 seepage of sandstone samples from the Taiyuan-Shanxi Formation coal seam roof in Ordos Basin, China, under temperature-stress coupling was studied with the aid of the TAWD-2000 coal rock mechanics-seepage test system. Furthermore, the evolution law and influencing factors on permeability for CO2 in sandstone samples with temperature and axial pressure were systematically analyzed. The results disclose that the permeability of sandstone decreases with the increase in stress. The lower the stress is, the more sensitive the permeability is to stress variation. High stress results in a decrease in permeability, and when the sample is about to fail, the permeability surges. The permeability of sandstone falls first and then rises with the rise of temperature, which is caused by the coupling among the thermal expansion of sandstone, the desorption of CO2, and the evaporation of residual water in fractures. Finally, a quadratic function mathematical model with a fitting degree of 98.2% was constructed between the temperature-stress coupling effect and the permeability for CO2 in sandstone. The model provides necessary data support for subsequent numerical calculation and practical engineering application. The experimental study on the permeability characteristics for CO2 in sandstone under high temperature and overburden pressure is crucial for evaluating the storage potential and predicting the CO2 migration evolution in underground coal gasification coupling CO2 storage projects.

Behaviors of CO2 Hydrate Formation in the Presence of Acid-Dissolvable Organic Matters

Carbon storage in the form of solid hydrate under seafloor has been considered to be promising for greenhouse gas control. Yet, open issues still remain on the role of the organic matters abundant in marine environments in the kinetics of hydrate formation; of particular interest is the involvement of the acid-dissolvable organic matters accompanying the acidification upon CO₂ injection. In this work, the CO₂ hydrate formation in the presence of the organic matters was in-situ monitored through the low-field nuclear magnetic resonance technique. It was found that the organic matters could kinetically promote the formation of CO₂ hydrate; this effect was further enhanced by the sulfur-containing acid-dissolvable organic matters. Water in the large pores was preferentially consumed; the following water conversion facilitated by the organic matters would result in a fragmentation of the large pores into separated small pores isolated by the hydrate clusters. Consequently, a further enhancement of the gas-water contact is suggested as the existence of substantial hydrate patches could act as a mass transfer barrier. Our findings expand our understandings on the kinetics of CO₂ hydrate formation in the presence of the organic matters and indicate the stability zone of gas hydrate a kinetically favorable geological setting for CO₂ sequestration.