Chinedu Junior Okere

The growing mismatch between renewable energy supply and demand necessitates large-scale seasonal underground hydrogen storage (UHS) in deep saline aquifers. This study presents a field-scale compositional numerical simulation assessment of operational strategies for UHS in homogeneous and heterogeneous anticline deep saline aquifers using CMG simulator on an optimized 91 x 44 x 10 corner-point grid model. Cushion gas type and fraction, well configuration, reservoir petrophysical properties, and cyclic injection-production schedules were systematically evaluated against cumulative hydrogen mass stored and recovery efficiency. Results shows that nitrogen consistently outperformed CO2 and CH4 across all cushion gas fractions, yielding 268,706.5 kg at 20% fraction, attributable to its chemical inertness, low aqueous solubility, and favorable gravitational segregation from hydrogen. Reservoir heterogeneity enhanced stored hydrogen mass by approximately 12 to 15% relative to the homogeneous formation by enhancing plume distribution and improved volumetric sweep efficiency. Recovery efficiency remained insensitive to injector-to-producer spacing across 0 to 60 m, peaking at 91.48% at 15 m spacing. Mole fraction analysis identified nitrogen as providing the best operational producer placement, offering field operators a flexibility in well positioning without losing hydrogen purity. This study provides practical screening and operational design criteria for large-scale UHS in saline aquifer systems.

The development of large-scale, flexible, and safe hydrogen storage is critical for enabling a low-carbon energy system. Deep saline aquifers (DSAs) offer substantial theoretical capacity and broad geographic distribution, making them attractive options for underground hydrogen storage. However, hydrogen storage in DSAs presents complex technical, geochemical, microbial, geomechanical, and economic challenges that must be addressed to ensure efficiency, safety, and recoverability. This study synthesizes current knowledge on hydrogen behavior in DSAs, focusing on multiphase flow dynamics, capillary trapping, fingering phenomena, geochemical reactions, microbial consumption, cushion gas requirements, and operational constraints. Advanced numerical simulations and experimental observations highlight the role of reservoir heterogeneity, relative permeability hysteresis, buoyancy-driven migration, and redox-driven hydrogen loss in shaping storage performance. Economic analysis emphasizes the significant influence of cushion gas volumes and hydrogen recovery efficiency on the levelized cost of storage, while pilot studies reveal strategies for mitigating operational and geochemical risks. The findings underscore the importance of integrated, coupled-process modeling and comprehensive site characterization to optimize hydrogen storage design and operation. This work provides a roadmap for developing scalable, safe, and economically viable hydrogen storage in DSAs, bridging the gap between laboratory research, pilot demonstration, and commercial deployment.

The potential for hydrogen production from heavy oil reservoirs has gained significant attention as a dual-benefit process for both enhanced oil recovery and low-carbon energy generation. This study investigates the technical and economic feasibility of producing hydrogen from heavy oil reservoirs using two primary in situ combustion gasification strategies: cyclic steam/air and CO₂ + O₂ injection. Through a comprehensive analysis of technical barriers, economic drivers, and market conditions, we assess the hydrogen production potential of each method. While both strategies show promise, they face considerable challenges: the high energy demands associated with steam generation in the steam/air strategy, and the complexities of CO₂ procurement, capture, and storage in the CO₂ + O₂ method. The novelty of this work lies in combining CMG-STARS reservoir simulations with GoldSim techno-economic modeling to quantify hydrogen yields, production costs, and oil–hydrogen revenue trade-offs under realistic field conditions. The analysis reveals that under current technological and market conditions, the cost of hydrogen production significantly exceeds the market price, rendering the process economically uncompetitive. Furthermore, the dominance of oil production as the primary revenue source in both methods limits the economic viability of hydrogen production. Unless substantial advancements are made in technology or a more cost-efficient production strategy is developed, hydrogen production from heavy oil reservoirs is unlikely to become commercially viable in the near term. This study provides crucial insights into the challenges that must be addressed for hydrogen production from heavy oil reservoirs to be considered a competitive energy source.

The global emphasis on clean energy has increased interest in producing hydrogen from petroleum reservoirs through in situ combustion-based processes. While field practices have demonstrated the feasibility of co-producing hydrogen and oil, the question of which offers greater economic potential, oil, or hydrogen, remains central to ongoing discussions, especially as researchers explore ways to produce hydrogen exclusively from petroleum reservoirs. This study presents the first integrated techno-economic model comparing oil and hydrogen production under varying injection strategies, using CMG STARS for reservoir simulations and GoldSim for economic modeling. Key technical factors, including injection compositions, well configurations, reservoir heterogeneity, and formation damage (issues not addressed in previous studies), were analyzed for their impact on hydrogen yield and profitability. The results indicate that CO₂-enriched injection strategies enhance hydrogen production but are economically constrained by the high costs of CO₂ procurement and recycling. In contrast, air injection, although less efficient in hydrogen yield, provides a more cost-effective alternative. Despite the technological promise of hydrogen, oil revenue remains the dominant economic driver, with hydrogen co-production facing significant economic challenges unless supported by policy incentives or advancements in gas lifting, separation, and storage technologies. This study highlights the economic trade-offs and strategic considerations crucial for integrating hydrogen production into conventional petroleum extraction, offering valuable insights for optimizing hydrogen co-production in the context of a sustainable energy transition. Additionally, while the present work focuses on oil reservoirs, future research should extend the approach to natural gas and gas condensate reservoirs, which may offer more favorable conditions for hydrogen generation.