This study investigates the impact of injection depth on CO₂ plume migration dynamics in saline aquifers, a critical aspect of secure and efficient carbon capture, utilization, and storage (CCUS). While CCUS offers a vital pathway for mitigating greenhouse gas emissions, challenges such as buoyancy-driven flow, salinity effects, and potential leakage threaten long-term CO₂ containment. Using compositional reservoir simulation (CMG GEM 2021.10, Calgary, Canada) and Illinois Basin Decatur Project (IBDP) data, we modeled CO₂ injection into a 10,000 ppm salinity aquifer, evaluating the effects of single- and multi-depth injection (5370 to 5385 ft). The results demonstrate that multi-depth injection significantly enhances CO₂–brine contact area, promoting dissolution trapping and mitigating buoyancy-driven migration. This enhanced dissolution and residual trapping improves horizontal containment and overall storage security in the modeled salinity environment. The work provides valuable insights for optimizing injection strategies to maximize CO₂ storage efficiency and minimize leakage risks.

Optimizing oil recovery from mature reservoirs remains a key challenge in the petroleum industry. This study evaluates the efficiency of CO₂-WAG injection compared to continuous CO₂ and water flooding using a sector model of the X Oil Field. A compositional reservoir simulator was employed to analyze oil recovery under water-wet and mixed-wet conditions, incorporating three-phase relative permeability and wettability effects. The results show that continuous CO₂ flooding yields the highest oil recovery, with water-wet systems outperforming mixed-wet reservoirs. CO₂-WAG injection provides a balanced approach, enhancing recovery while enabling CO₂ sequestration, but remains less effective than continuous CO₂ flooding. Water flooding, though the least efficient in terms of oil recovery, demonstrates long-term production stability. The gas–oil ratio (GOR) is notably higher in CO₂-WAG, indicating gas breakthrough challenges. These findings emphasize the significant role of wettability in enhanced oil recovery (EOR) and suggest that continuous CO₂ flooding is the most effective technique for maximizing production in heterogeneous reservoirs. This study contributes valuable insights for optimizing injection strategies, improving hydrocarbon recovery, and supporting sustainable reservoir management.

While the “low salinity waterflooding” (LSWF) has been praised for enhancing oil recovery from different core rocks, the performance of the technique in different wettability environments remains unclear. The consensus is that LSWF does not work well in water-wet carbonate oil reservoirs. The main research objective was to determine the effect of LSWF on the displacement efficiency (DE) in different wettability environments. Carbonate core flooding experiments on rocks with different wettabilities were performed at in-situ reservoir conditions using seawater as a “base water”. Seawater was sequentially diluted 10 to 50 times and spiked 2 and 6 times with sulfate. Following sequential flooding with four different waters, the DEs were measured for different wettabilities. Five different sequential brine floodings were performed on carbonate rocks. Results indicated that optimum low salinity water is a function of system wettability. Seawater (≈ 50,000 ppm) is the optimum brine for oil-wet and intermediate-wettability systems. Sequential flooding consisting of seawater followed by diluted seawater in a water-wet system yielded the highest DE of 88%. Besides, low-salinity brine followed by sulfate performed better in a water-wet environment than in oil- and intermediate-wettability systems.

CO₂ flooding has become a strategic tool for enhanced oil recovery and reservoir management in mature fields. This technique, however, is rarely utilized in asphaltenic crude oil systems, due to the likely occurrence of high asphaltene precipitation. The effect of asphaltene concentrations and CO₂ injection pressures has mostly been the focus of studies in determining asphaltene precipitation rates. However, asphaltene precipitation is not the only direct factor to be considered in predicting the extent of damage in an asphaltenic crude oil system. In this study, a compositional reservoir simulation was conducted using Eclipse 300 to investigate the injection pressure at which asphaltene-induced formation damage can be avoided during both miscible and immiscible CO₂ flooding in an asphaltenic crude system. Simulation results indicate that asphaltene-induced permeability reduction exceeded 35% in most affected zones, with a corresponding drop in injectivity of 28%. Cumulative oil recovery improved by 19% compared to base cases without CO₂ injection, achieving peak recovery after approximately 4200 days of simulation time. As CO₂ was injected below the Minimum Miscibility Pressure (MMP) of 2079.2 psi, a significantly lower asphaltene precipitation was observed near the injector. This could be attributed to the stripping of lighter hydrocarbon components (C2–C7+) occurring in the transition zone at the gas–oil interface. Injecting CO₂ at pressures above the MMP resulted in precipitation occurring throughout the entire reservoir at 3200 psia and 1000 bbl/day injection rates. An increase in the injection rate at pressures above the MMP increased the rate of precipitation. However, a further increase in the injection rate from 1000 bbl/day to 4200 bbl/day resulted in a decrease in asphaltene deposition. The pressure drop in the water phase caused by pore throat increase demonstrated that water injection was effective in removing asphaltene deposits and restoring permeability. This work provides critical insights into optimizing CO₂ injection strategies to enhance oil recovery while minimizing asphaltene-induced formation damage in heavy oil reservoirs.

Scale deposition during waterflooding, driven by the incompatibility between injected seawater and formation of water, poses significant challenges to reservoir performance. This study examines the mechanisms of inorganic scale formation and assesses its impact on productivity index, permeability, and pressure dynamics using the ECLIPSE simulator. A five-layered reservoir model with one injector and one producer (spaced 700 feet apart) was simulated under varying seawater injection rates of 1000, 3000, and 5000 stock tank barrels per day (stb/day). The results revealed rapid water breakthrough and escalating water cuts (34–38%) across scenarios, with scale deposition concentrated in layers 3 and 4, reducing permeability by up to 47% and productivity index by 50%. Layer 3 exhibited a threefold higher scaling due to the intense mixing of seawater and the formation of water. The study highlights the necessity of sulfate removal, alternative water sources, well repositioning, and preemptive scale inhibition to minimize reservoir damage caused by scale-induced permeability impairment.

Hydrogen energy is valued for its diverse sources and clean, low-carbon nature and is a promising secondary energy source with wide-ranging applications and a significant role in the global energy transition. Nonetheless, hydrogen’s low energy density makes its large-scale storage and transport challenging. Liquid hydrogen, with its high energy density and easier transport, offers a practical solution. This study examines the global hydrogen liquefaction methods, with a particular emphasis on the liquid nitrogen pre-cooling Claude cycle process. It also examines the factors in the helium refrigeration cycle—such as the helium compressor inlet temperature, outlet pressure, and mass—that affect energy consumption in this process. Using HYSYS software, the hydrogen liquefaction process is simulated, and a complete process system is developed. Based on theoretical principles, this study explores the pre-cooling, refrigeration, and normal-to-secondary hydrogen conversion processes. By calculating and analyzing the process’s energy consumption, an optimized flow scheme for hydrogen liquefaction is proposed to reduce the total power used by energy equipment. The study shows that the hydrogen mass flow rate and key helium cycle parameters—like the compressor inlet temperature, outlet pressure, and flow rate—mainly affect energy consumption. By optimizing these parameters, notable decreases in both the total and specific energy consumption were attained. The total energy consumption dropped by 7.266% from the initial 714.3 kW, and the specific energy consumption was reduced by 11.94% from 11.338 kWh/kg.