In the energy industry’s most challenging production environment, the question is often not whether a resource can be produced, but whether the risks surrounding it can be managed without endlessly expanding surface infrastructure – and with minimal environmental impact.
Managing a Costly Constraint
Sour gas – natural gas containing hydrogen sulfide – is a widespread phenomenon. It occurs in roughly a quarter of global oil and gas reserves, including fields across the Middle East and the United States, where its handling has long required a careful balance between safety, operational reliability, environmental performance and commercial return. For operators working with sour gas reserves, hydrogen sulfide is more than a technical complication. Toxic and corrosive, it can shape the design of facilities, the pace of development and the capital required to bring an asset into production. The vast majority of such projects are either environmentally risky or economically unviable, which is why these resources are often simply left undeveloped. In international classifications, they fall into the category of stranded resources.
Ruslan Mardanov’s research approaches that problem from below the surface. His methodology examines the possibility of injecting acid gases into deep saline aquifers and carbonate reservoirs, where they can be contained and, over time, chemically transformed. The work combines reservoir engineering with geochemistry, looking at where injected gas goes, but also at what happens when it encounters the fluids and mineral structures already present underground.
That distinction gives the research a practical focus. Conventional acid-gas management has tended to rely on surface sulfur storage and related handling systems, which introduce significant capital outlays as well as operational and environmental risks. Mardanov’s work explores whether certain geological formations can serve as part of the solution instead, offering operators a structured framework for evaluating subsurface disposal in locations where sour gas production remains commercially important.
From Injection to Long-Term Containment
At the core of Mardanov’s methodology is a predictive geochemical model that tracks the interaction of injected acid-gas mixtures with reservoir rock over time. Rather than relying solely on broad estimates of subsurface behavior, the model is designed to help engineers assess conditions within a particular formation. Pressure, temperature, fluid composition and mineralogy all influence whether a gas remains mobile, dissolves into formation water or becomes part of a more stable mineral state.
The research presented at the EAGE Global Energy Transition Conference in Rotterdam in 2024 and 2025 considered the co-injection of hydrogen sulfide and carbon dioxide. It identified a result with clear operational implications: solubility trapping is lower when the gases are injected together than it is in single-gas injection. But the combined process can also set off chemical reactions that increase long-term mineral trapping by 42 percent, according to the research. In practical terms, that may allow a larger share of the injected gas to become fixed in stable minerals, including pyrite.
For energy companies, permanence is the central issue. Disposal is not simply a matter of placing gas at depth; it requires confidence that the chosen formation can contain it over the long term. Mardanov’s work frames that assessment as an engineering and geochemical question that should be evaluated before development decisions are made. The methodology has been peer-reviewed, according to the material describing the research, and its relevance rests on the presence of comparable geological conditions in several sour-gas-producing regions.
Where Safety Meets Field Economics
The business case for subsurface acid-gas management is tied directly to safety and environmental neutrality. If operators can reduce their dependence on surface infrastructure, they may lower the risk associated with storing and handling sulfur-bearing byproducts at operating sites. The research projects that the methodology could reduce capital expenditure by half compared with conventional approaches – and a single major Middle Eastern project has already demonstrated savings of more than USD 600 million. Scaling these results across the broader oil and gas sector depends on specific reservoir characteristics and deployment conditions, but they vividly illustrate the scale of the cost pressures that this research is designed to address.
The methodology also has implications for production planning. In major sour gas assets, surface-processing capacity often becomes a constraint on output even when a reservoir holds substantial resources. Mardanov’s approach suggests that operators may be able to safely increase production without proportionally expanding surface infrastructure, provided the relevant subsurface conditions support injection and long-term trapping. It is a proposition that places geology and reservoir chemistry closer to the center of investment planning.
Ruslan Mardanov received a 2026 Global Recognition Award in the research category for this methodology, which connects environmental management with the operational realities of sour gas development. The significance of his work is not that it removes every uncertainty from complex reservoirs, but that it provides a more disciplined way to confront them. Such risk assessment could potentially increase the official commercial reserves of the United States by roughly one‑tenth, and those of the Middle East by 15‑20 percent. As energy companies weigh the future of sour gas fields, Mardanov’s research offers a clear proposition: the solution to one of the industry’s most persistent challenges may lie not in costly surface infrastructure, but in the very ground beneath the field. What has long been viewed as a stranded resource could become a manageable asset – if the subsurface is understood and used wisely.
