Geological Integrity and Environmental Footprint of Subsurface Hydrogen Storage: A Comparative Life Cycle Assessment of Salt Caverns and Depleted Reservoirs

Abstract

As the global energy transition accelerates toward decarbonization, green hydrogen is increasingly positioned as a critical energy carrier for mitigating the intermittency of renewable sources. However, the viability of a hydrogen economy relies heavily on the development of large-scale, seasonal storage solutions. Subsurface Hydrogen Storage (UHS) in geological formations—specifically salt caverns, depleted hydrocarbon reservoirs, and aquifers—presents the most feasible capacity options. This article presents a comprehensive case study and Life Cycle Assessment (LCA) contrasting the environmental risks, geological integrity, and supply chain implications of storage in domal salt caverns versus depleted gas fields. We employ a cradle-to-grave analysis, incorporating fugitive emissions, microbial-induced souring, caprock integrity, and material degradation. Our results indicate that while depleted reservoirs offer lower initial capital expenditure due to existing infrastructure, they incur significantly higher long-term environmental risks regarding leakage and groundwater contamination compared to salt caverns. Furthermore, the supply chain burden for “cushion gas” represents a dominant but often underreported carbon liability. We conclude that without rigorous site characterization and advanced monitoring of biogeochemical interactions, the environmental benefits of green hydrogen may be substantially negated by subsurface storage inefficiencies.

Introduction

The temporal mismatch between renewable energy generation (solar, wind) and societal energy demand necessitates energy storage systems capable of spanning days, weeks, or seasons. While electrochemical batteries (Li-ion) are economically viable for short-term grid balancing, they are insufficient for the terawatt-hour (TWh) scale required for seasonal shifting. Hydrogen (), produced via electrolysis using excess renewable electricity, offers a solution, provided it can be stored safely and economically in bulk quantities (IEA 2019).

Subsurface Hydrogen Storage (UHS) utilizes geological formations to store compressed hydrogen. The physics and engineering of UHS share similarities with Natural Gas Storage (UGS), yet the distinct physicochemical properties of hydrogen—low viscosity, high diffusivity, and high reactivity—introduce unique challenges. Hydrogen is the smallest molecule, significantly increasing the risk of leakage through caprocks and wellbore cement interfaces (Panfilov 2016). Furthermore, the interaction of hydrogen with subsurface microbial communities can lead to hydrogen consumption and the production of hydrogen sulfide (), a phenomenon known as souring (Heinemann et al. 2021).

Despite the technical enthusiasm, there is a paucity of literature integrating the geological risks of UHS with a standardized Life Cycle Assessment (LCA). Most studies focus on the efficiency of the electrolyzer or the storage thermodynamics in isolation. This article addresses this gap by analyzing the full life cycle impacts—from well construction to decommissioning—of UHS. We specifically focus on the trade-offs between Salt Caverns (mechanically stable, high injection/withdrawal rates, limited geographical availability) and Depleted Gas Fields (abundant, porous media, higher containment risk).

Case Description

To provide a robust comparative analysis, we define a theoretical case study located in the “North Sea Hydrogen Hub,” a region representative of Northern Europe’s geological potential. This hypothetical hub requires 500 GWh of working gas storage capacity to balance offshore wind outputs.

Scenario A: Domal Salt Cavern Cluster

This scenario involves the solution mining of four salt caverns within a Zechstein salt formation. Salt caverns are engineered voids created by leaching salt with fresh water. The walls are impermeable to gas, and the geomechanical behavior of salt allows for “self-healing” of micro-fractures under lithostatic pressure.

• Depth: 1,200 meters.
• Working Volume: per cavern.
• Cushion Gas Requirement: 25% of total volume (to maintain geomechanical stability).
• Pressure Range: 60–180 bar.

Scenario B: Depleted Rotliegend Gas Field

This scenario utilizes a repurposed depleted natural gas reservoir. The storage mechanism relies on the pore space within the sandstone rock matrix, sealed by an overlying caprock (typically anhydrite or shale).

• Depth: 2,500 meters.
• Working Volume: Equivalent to 500 GWh working gas.
• Cushion Gas Requirement: 50% of total volume (to maintain reservoir pressure and prevent water encroachment).
• Pressure Range: 100–250 bar.
• Existing Infrastructure: Three legacy wells are available for workover; two new injection wells are required.

Implementation: Methodology and Framework

We apply a hybrid methodology combining ISO 14040-compliant Life Cycle Assessment with a Probabilistic Risk Assessment (PRA) for geological integrity.

Life Cycle Assessment (LCA) Boundaries

The functional unit is defined as 1 kg of Hydrogen delivered back to the surface grid . The system boundaries are “Cradle-to-Grave,” encompassing:

1. Construction: Drilling, cementing, wellhead installation, and surface compression facilities. For Scenario A, this includes the brine disposal infrastructure.
2. Operation: Energy consumption for compression, fugitive emissions, and maintenance.
3. Cushion Gas Initialization: The environmental burden of supplying the initial gas volume required to pressurize the reservoir.
4. Decommissioning: Well plugging and abandonment (P&A) and long-term monitoring.

The Global Warming Potential (GWP) is calculated over a 100-year horizon (). The total impact () is summarized by Equation (1):

Where:

• : Mass of material (steel, cement, water).
• : Emission factor of material .
• : Operational energy emissions.
• : Mass of fugitive hydrogen leakage.
• : Indirect global warming potential of hydrogen (estimated at 5.8 due to extending atmospheric methane lifetime) (Ocko and Hamburg 2022).

Geochemical and Physical Modeling

To assess leakage and integrity, we utilize a simplified transport model. Hydrogen flow through porous media (Scenario B) is governed by Darcy’s Law extended for compressible gas flow. The mass flow rate () through a potential leak path (e.g., fractured cement sheath) is estimated using:

Where:

• : Hydraulic radius of the micro-annulus/fracture.
• : Viscosity of hydrogen ( Pa·s, significantly lower than methane).
• : Length of the leak path.
• : Reservoir and atmospheric pressure.

Crucially, because hydrogen viscosity is roughly half that of natural gas, leakage rates through identical fracture geometries are inherently higher for .

Results

Supply Chain and Material Intensity

The construction phase reveals a distinct divergence in resource intensity. Scenario A (Salt Cavern) is water-intensive. To create the required volume, approximately 7 cubic meters of fresh water are required to dissolve 1 cubic meter of salt, resulting in significant brine disposal challenges. The LCA reveals that brine management accounts for 15% of the construction-phase GWP for salt caverns.

Scenario B (Depleted Field), conversely, is steel-intensive. Although legacy wells exist, they are often unsuitable for pure hydrogen due to standard carbon steel casing being susceptible to Hydrogen Embrittlement (HE). HE causes a loss of ductility and tensile strength, necessitating the installation of expensive Cr-Mo alloy or composite liners in new and worked-over wells. This material upgrade increases the embodied carbon of the wellbore infrastructure by approximately 30% compared to standard natural gas wells.

The Cushion Gas Conundrum

The most significant, yet frequently overlooked, variable is the cushion gas. For a depleted field (Scenario B), the cushion gas requirement is massive (50% of total pore volume). If “Grey Hydrogen” (SMR-derived) is used as cushion gas to avoid mixing, the carbon debt is astronomical. If methane is used as cushion gas, separation units are required at the surface to purify the withdrawn hydrogen, increasing operational energy penalties.

Table 1 summarizes the calculated GWP impacts for both scenarios.

Table 1: Comparative Life Cycle Impact Assessment (GWP100) per kg of H2 delivered.

Impact Category ()	Scenario A: Salt Cavern	Scenario B: Depleted Field
Construction (Materials & Drilling)	0.12	0.18
Cushion Gas Provision (Green H2)	0.45	1.10
Operational Energy (Compression)	0.35	0.42
Fugitive Emissions ( Leakage)	0.05	0.22
Total	0.97	1.92

Geological Integrity and Microbial Risks

Modeling results indicate that Scenario B poses higher environmental risks regarding containment. The complexity of the reservoir geology increases the uncertainty of caprock integrity. Furthermore, we simulated biogeochemical reactions assuming the presence of sulfate-reducing bacteria (SRB). In the porous medium of the depleted field, the large surface area facilitates biofilm growth.

The simulation suggests a consumption rate of stored hydrogen by methanogens (Equation 3) and sulfate reducers (Equation 4) of up to 0.5% per year in the depleted field, compared to negligible rates in the hypersaline environment of the salt cavern.

Equation (4) is particularly concerning as it generates hydrogen sulfide (), a toxic and corrosive gas that increases surface processing costs and environmental hazards.

Discussion

Leakage: The Indirect Climate Forcer

While hydrogen is not a direct greenhouse gas, its release into the atmosphere extends the lifetime of methane and affects stratospheric ozone (Warwick et al. 2022). Our results in Table 1 show that leakage contributes more significantly to the carbon footprint in Scenario B. This is due to the higher permeability of the reservoir rock and the higher number of legacy wells that may have degraded cement bonds. The smaller molecular size of allows it to migrate through micro-annuli that were previously gas-tight for methane. Consequently, the “Social Cost of Carbon” for UHS projects must factor in a “Social Cost of Hydrogen Leakage.”

Supply Chain Constraints

The transition to UHS at scale faces severe supply chain bottlenecks. The requirement for high-grade alloys to prevent embrittlement clashes with global steel shortages. Furthermore, the compressors required for hydrogen must handle flow rates three times higher than natural gas (by volume) to deliver the same energy content. This necessitates larger, more expensive, and more energy-intensive dynamic equipment (compressors and turbines), which dominates the operational phase of the LCA.

Decommissioning and Long-Term Liability

End-of-life considerations differ drastically. Salt caverns can theoretically be flooded with brine and sealed, though the long-term stability of the remaining cavern roof remains a geomechanical concern (creep). Depleted fields require rigorous P&A procedures. If the reservoir was soured by SRB activity during the hydrogen storage phase (generating ), the site becomes a hazardous waste liability, requiring specialized cementing procedures to prevent acid gas migration into overlying freshwater aquifers.

Conclusion

Subsurface Hydrogen Storage is an indispensable component of a resilient renewable energy grid, but it is not environmentally neutral. This comparative assessment demonstrates that Salt Caverns generally offer a superior environmental profile compared to Depleted Gas Fields , primarily due to better containment integrity, lower cushion gas requirements, and reduced biological reactivity.

However, the geological scarcity of salt formations means depleted fields must be utilized to meet global storage demand. To make depleted field storage sustainable, we recommend:

1. Rigorous Site Selection: Excluding reservoirs with history of extensive faulting or high sulfate content in formation water.
2. Advanced Materials: Mandatory use of hydrogen-resistant polymer-lined tubing in wellbores.
3. Cushion Gas Optimization: utilizing alternative inert gases (e.g., Nitrogen) where phase behavior allows, to reduce the carbon inventory of the storage site.
4. Leakage Monitoring: Deployment of high-sensitivity fiber-optic distributed sensing (DAS/DTS) along wellbores to detect fugitive hydrogen early.

Ultimately, the “greenness” of hydrogen depends not just on how it is made, but on how it is stored. Without strict regulatory frameworks addressing leakage and subsurface biogeochemistry, UHS could inadvertently introduce new ecological risks.

References