The generation of hydrogen in-situ from hydrocarbon reservoirs has emerged as a carbon neutral technology for fossil fuel-based hydrogen production. This technology has been extensively investigated for heavy oil reservoirs through in-situ combustion gasification. This study proposes in-situ hydrogen generation from depleted gas reservoirs and assess graphite gravel packing for selective hydrogen production with underground carbon storage. The viability of this hydrogen generation process was accessed through process simulation, followed by experimental investigation and molecular simulation of the selective production of hydrogen through graphite. Equilibrium and kinetic models reproduced measured effluent fractions, confirming their reliability. The simulation outcomes reveal that higher temperature and steam-to-carbon ratio increase hydrogen yield/purity, whereas high pressure favors methanation. This necessitates elevated temperatures beyond the usual reaction temperature under reservoir conditions. Longer residence time and judicious catalyst loading improve conversion while limiting diminishing returns. Adiabatic simulation yields lower hydrogen purity than isothermal but better reflects field behavior. Reservoir mineralogy governs outcomes as quartz-rich rocks inhibit hydrogen production by steam reforming, while clays/feldspars reported elsewhere can be catalytic. The experimental results showed that graphite can be used as gravel pack in the production well to produce hydrogen and retain carbon dioxide underground. Literature report indicates that high compaction can further enhance separation significantly reducing the carbon emission associated with hydrogen production from fossil fuels.

Surfactants play a critical role in enhanced oil recovery (EOR) applications; however, their performance is often compromised in harsh reservoir conditions, such as high temperature and high salinity, due to precipitation caused by interactions with multivalent metal ions. Chelating agents were introduced into oilfields for various purposes due to their ability to sequester metal ions. In this work, we conducted a comprehensive investigation about chelating agent-surfactant (CS) flooding for carbonate reservoirs, as an alternative to the well-established alkaline surfactant (AS) flooding used in sandstone. The tested surfactants include sodium dodecyl sulfate (anionic) (SDS), dodecyltrimethylammonium bromide (cationic) (DTAB), Triton X100 (nonionic), and a locally synthesized zwitterionic surfactant. The tested chelating agents include diethylenetriaminepentaacetic acid (DTPA), ethylenediaminetetraacetic acid, and glutamic acid N,N-diacetic acid. pH and temperature, as dominant factors in chelating agent solubility and brine stability, were modified to test chelating agent solutions of different concentrations and their mixtures with surfactants. Interfacial tension reduction by chelating agents alone, surfactants alone, and their mixtures were measured. Wettability alteration brought by chelating agents and surfactants on carbonate rock surfaces was evaluated using the static contact angle method. Based on the obtained results, chelating agents can be applied as low-cost additives for surfactant stabilization in high salinity conditions. The addition of chelating agents significantly improved the stability of SDS and DTAB in salt solutions and seawater. At a relatively low concentration (0.25 wt%), DTPA was able to stabilize DTAB of 1.00 wt% in seawater at high temperature (90 ℃). DTPA, among the tested three chelating agents, exhibited a stronger stabilization effect on surfactants of different ion types. When chelating agents are to be applied in brine, an optimal applicable pH range of 5–9 is recommended so not to induce solubility issue of chelating agents or stability issues of metal ions. In this range, IFT reduction is more significant at high pH, while wettability alteration is more significant at low pH. The combination of a cationic surfactant with a chelating agent forms a low adsorption wettability modifier which can change strongly oil-wet rock to water-wet conditions, thus significantly increasing the residual oil recovery from oil-wet carbonate formations. Zwitterionic and nonionic surfactants are also applicable to combine with a chelating agent for EOR purposes. Anionic surfactant SDS, however, showed a growing inhibition on the wettability alteration effect induced by EDTA as the concentration of SDS increased.

The utilization of supercritical CO₂ in oil and gas reservoir engineering, particularly for enhanced oil recovery, has garnered considerable attention due to its potential to boost hydrocarbon production while reducing CO₂ emissions. This study investigates the improvements achievable in CO₂-enhanced oil recovery and subsequent carbon storage capacity within heterogeneous carbonate reservoirs through supercritical CO₂ miscible injection after seawater flooding. Utilizing a dual-core flooding setup with carbonate core samples exhibiting significant permeability contrast, experiments were conducted under reservoir conditions using live oil, seawater, and supercritical CO₂ miscible injection. To enhance CO₂-enhanced oil recovery and storage within low-permeability zones, a thermal foam gel system was introduced into a highly permeable core after initial supercritical CO₂ miscible injection, effectively sealing off high-permeability zones and improving displacement and storage capacity. Results demonstrate that reservoir heterogeneity notably influences supercritical CO₂-enhanced oil recovery efficiency and sequestration in low permeable regions, with bypass flow in high- permeable regions hindering displacement efficiency and CO₂ storage capacity. However, plugging high-permeability zones using a thermal foam gel system after the initial supercritical CO₂ miscible injection, about 15% extra oil recovery of the pore volume from low-permeability zones was recovered during the second supercritical CO₂ miscible injection, and the equivalent pore space provides a site for storing CO₂ also. Additionally, dynamic characteristic parameters such as injectivity, permeability loss, and endpoint relative permeability related to supercritical CO₂ storage are discussed in this study. The study’s outcomes contribute to advancing the understanding of CO₂-enhanced oil recovery and sequestration, facilitating the development of more effective and sustainable reservoir management practices.