Integrity Issues for Underground Gas Storage Wells

Underground gas storage (UGS) facilities are vital components of energy management systems, offering solutions for managing high-demand periods, providing backup supplies during emergencies, and maintaining critical energy reserves. The United States dominates global UGS capacity, accounting for the largest share in several categories. As shown in Fig. 1, the United States holds 25% of the world's salt cavern facilities, 64% of depleted fields, and 57% of the total UGS facilities. Figure 2 provides a broader view of the distribution of UGS facilities and capacities across different countries. It illustrates that the United States not only leads in the total number of facilities but also holds a significant share of global gas capacity in several types of reservoirs. Specifically, the United States accounts for 43% of the salt cavern gas capacity and 50% of the total gas capacity worldwide. Other notable countries include Russia and Germany, with Russia holding a 24% share of the total gas capacity, primarily in porous reservoir facilities, while Germany holds 32% of the total maximum withdrawal capacity from UGS sites. Countries like Canada and Ukraine are also significant contributors, particularly in the number of depleted field facilities, with Canada holding 21% and Ukraine 19%. Additionally, regions like China and Argentina are emerging players with increasing capacities, represented by their share of total facilities and gas withdrawal capabilities. This distribution reflects the varied approaches to underground gas storage across different geological settings and energy needs [1]. The integrity of these storage systems is of paramount importance to their safety and economic viability, with wellbore integrity being a critical component. Typically, robust cement systems act as barriers throughout the well's lifecycle to prevent gas migration and maintain well integrity [2]. The effectiveness of UGS operations is significantly determined by the cement sheath's capacity to endure cyclic thermal and mechanical stresses, along with its resistance to corrosion throughout the well's lifespan. Compromises in the integrity of the cement sheath such as debonding at interfaces, the presence of mud layers or channels, free water pathways, or excessive hydraulic, thermal, or mechanical stresses can compromise the well integrity. Such failures may result in severe outcomes, including gas leakage, posing significant safety and environmental risks. These failures not only diminish storage capacity but also increase the risk of natural gas explosions, threatening both human safety and production activities [3]. Consequently, engineers and scientists have developed specialized cement compositions to mitigate such risks. For example, the use of latex or polypropylene fibers has been shown to improve compressive strength, while lightweight slurries and engineered fiber materials are used to prevent formation damage in depleted or unconsolidated formations [4,5]. Additionally, expanded cement systems were designed to maintain integrity under harsh downhole conditions [6]. Self-healing cement was introduced as a novel material which can repair cracks through encapsulation, a process that offers promise for long-term well integrity in UGS operations [7].

Ensuring well integrity in UGS systems involves not only selecting the appropriate cement formulations but also understanding the external factors that can impact cement performance. Pressure and temperature cycles can lead to radial cracks in the cement sheath, which, in turn, can cause debonding at the casing–cement bond [8,9]. Formation pore pressure change based on the depth and lithology can lead to radial fractures and disking within the cement [10]. While considerable research has been conducted on cement sheath integrity, there is limited focus on the impact of lithological variations on the sealing performance of the cement sheath [11,12]. In a study examining the effects of formation properties on cement performance, Boukelhifa et al. [13] explored how variations in formation properties influence cement performance by employing metal rings of different thicknesses to simulate rocks with varying stiffness. Their findings demonstrated that cement sheaths in less rigid formations were more vulnerable to failure compared to those in more rigid formations. In another study, De Corina et al. [14] examined thermal cycling effects on cement integrity using perforated rock cores and cement slurries to mimic real formation conditions. The results revealed that after 20 thermal cycles, sandstone samples showed significant debonding and crack propagation, while shale samples remained mostly unaffected. This highlights the critical role of lithology in determining cement sheath integrity and emphasizes the need for strong bonding at the cement–formation interface (CFI) to minimize the risk of gas leakage [15].

Given the complexity of downhole environments, numerical simulations play a crucial role in studying gas leakage mechanisms and predicting when failures might occur at cement interfaces. Cohesive zone models in plane strain settings have been widely utilized to map gas migration paths across formations with different lithological characteristics [16–18]. Qiu et al. [16] further enhanced the analysis of near-wellbore stresses by implementing local grid refinement techniques, improving the understanding of formation heterogeneity, and bridging the gap between large-scale field stresses and localized near-wellbore stress distributions.

These findings highlight the importance of considering not just advanced formulations but also comprehensive risk assessments and the development of preventive and mitigative strategies. As demonstrated by UGS leakage reports [1], the most common well component failures occur in casings (55%) and wellheads (32.5%), with human intervention and corrosion being the primary causes. Addressing the challenges of micro-annuli formation, mechanical-thermal loading, cement composition inadequacies, and casing corrosion is essential to ensure the safety and functionality of UGS systems.

The literature review on zonal isolation issues in underground gas storage wells highlights the importance of proper cement composition and placement, particularly for remedial purposes, casing corrosion, and preventative precautions, such as thickness logs, temperature logs, and anticorrosion additives in the completion fluids. While proper cement composition and placement are key factors in achieving zonal isolation in UGS wells, other factors, such as wellhead leaks and tubing leaks, also play a significant role in addressing these challenges. Additionally, factors such as formation heterogeneity, wellbore pressure, and temperature fluctuations can contribute to zonal isolation challenges in UGS wells. These challenges require a comprehensive understanding of the geomechanical and geochemical properties of the subsurface as well as continuous monitoring and maintenance of wellbore integrity throughout the life of the well. By addressing these challenges, operators can minimize the risk of gas leaks, wellbore collapse, and other potential hazards associated with underground gas storage operations. Several critical mechanisms and failure modes affect the integrity of the cement barriers. Leakage pathway development Fig. 3 is essential for understanding the effectiveness of current zonal isolation strategies and areas in which theoretical models do not fully align with field applications. One of the primary concerns in zonal isolation is the formation of micro-annuli, which are small gaps between the cement sheath and casing or formation, typically resulting from insufficient cement application or inadequate bonding. Annular fractures form as cylindrical cracks surrounding the casing, often triggered by high treatment pressures or significant pressure fluctuations. These fractures are particularly common in conditions of low confining stress or inadequate cement quality [19]. The integration of advanced cementing solutions is particularly crucial for wells constructed before the widespread adoption of modern zonal isolation methods. Reference [20] notes that some wells, especially those predating 1917, lack cement zonal isolation entirely, making them prime candidates for remediation. By applying innovative cementing materials to these wells, operators can significantly reduce the risk of containment loss, thereby enhancing both environmental safety and operational reliability. The factors contributing to these issues include poor slurry composition, insufficient casing centralization, and inadequate displacement of drilling fluids during cement. These gaps can significantly compromise the integrity of a barrier by allowing gas migration [10]. In addition to bonding, several other factors influence the integrity of the cement sheath. The ability of a cement sheath to maintain zonal isolation can be compromised by numerous factors, either independently or in combination. These include the design of spacers for mud cake removal, gel strength and fluid loss properties of the cement slurry, shrinkage, permeability, and the presence of free fluid, all of which contribute to the risk of gas migration.

Mechanical integrity is crucial for long-term isolation and integrity of oil and gas wells. Mechanical failures in the cement sheath can lead to severe operational, environmental, and safety issues, including gas leaks and groundwater contamination. These failures often result from cyclic stresses imposed by the thermal and pressure fluctuations inherent in UGS operations. Variations in injection and production rates or extreme downhole conditions can cause thermal cycling, which affects cement integrity through expansion and contraction. This results in radial cracking of the annular cement sheath, threatening well integrity.

The tensile strength of cement is only a fraction of its compressive strength, making the annular cement sheath prone to radial cracking when casings expand owing to heat [21]. Changes in the downhole conditions, such as the injection of cooler fluids or halting production, can lead to casing contraction, which poses challenges in preserving the integrity of the annular cement sheath. Consequently, the expansion and contraction of the casing often result in cracking and debonding of the cement sheath. Maintaining the mechanical integrity of the cement sheath is essential for ensuring the reliability of UGS wells [22]. When stresses act at the interface, the cement material becomes more prone to compressive damage, leading to interfacial debonding and the formation of a micro-annulus. This phenomenon increased the likelihood of gas migration along the cement sheath. As the micro-annulus enlarges to a size that allows fluid movement, the structural integrity of the cement sheath is weakened, providing pathways for fluid flow. Research highlights that micro-annuli at the casing–cement interface and the cement–formation interface can serve as conduits for gas leakage, underscoring their significance in well-integrity challenges. To mitigate these risks, a thorough stress analysis is essential for the design of cement sheaths. Figure 4 shows the radial stress distribution along the well depth at the casing–cement interface (CCI) and CFI after 20 pressure cycles. The data compared the radial stress at two internal gas pressures, 7 MPa and 14 MPa, to evaluate the changes in internal pressure impact stress profiles along the wellbore in a gas storage environment. At both pressure levels, the radial stress increased linearly with depth, from 17 MPa near the top (800 m) to approximately 24 MPa at the bottom (900 m).

This trend suggests a proportional relationship between depth and radial stress, which may be attributed to the increasing overburden pressure and confinement effect of the surrounding formations as the depth increases. The results show that a higher internal gas pressure (14 MPa) results in a higher overall radial stress at both the CCI and CFI compared to the 7-MPa scenario. This indicates that increasing the internal pressure in the gas storage cavern enhances the stress on the cement sheath and surrounding formation, potentially influencing the risk of interfacial debonding or the development of micro-annuli. Under both pressure conditions, the CFI experienced a slightly higher radial stress than the CCI. This difference could arise from the different mechanical properties and bonding strengths of the formation and casing materials, leading to variations in load distribution. The higher stress at the CFI may imply a greater susceptibility to stress-induced micro-annuli, particularly under elevated internal pressures, which could facilitate gas leakage pathways if the stress exceeds the bonding threshold (Fig. 5).

The observed increase in the radial stress with depth and under higher internal pressures has critical implications for good integrity in gas storage applications. Sustained high-stress levels, especially near the CFI, can accelerate cement sheath degradation or promote debonding at the cement–formation interface. This finding underlines the importance of managing the internal gas pressures within safe limits to mitigate the risk of gas under different pressure conditions. The linear stress increase across the depth after several cycles also suggests that repeated pressure cycling maintains a consistent load distribution without significant stress relaxation or redistribution. However, further research is necessary to investigate the potential cumulative effects of prolonged cycling, which may affect cement integrity differently over longer operational periods.

UGS facilities experience repeated stresses owing to the daily gas injection and extraction operations. This cyclic activity leads to frequent pressure changes that affect the entire UGS system, including active and abandoned wells, as well as reservoir containment structures, such as caprocks. These pressure fluctuations increased the likelihood of containment failure or leakage over time. Cyclic variations in pressure and temperature shown in (Fig. 6) experienced during the storage and production phases of UGS wells, shown in Fig. 6, demand the use of a cement sheath capable of withstanding these stress conditions. Cement with low Young's modulus and low expansion properties is the best option for mechanical durability and resistance to stress [6]. During cement hydration, pores between grains develop as the total volume of hydration products, and the remaining water is smaller than the combined volume of the original cement powder and water used in the reaction. It has been demonstrated that overlooking the poromechanical properties of cement in thermal wells can be crucial because heating the cement sheath may generate extremely high pore pressures within the cement. This can damage the cement sheath itself or lead to the formation of micro-annuli along the boundaries of the cement sheath. An analysis of the water properties revealed that water with a high specific mass could increase the pore pressure within the cement. To mitigate the risk of compromising the cement integrity, it is advisable to design cement systems that initially have a low specific mass of water in the cement pores when heating begins. This can be achieved by optimizing the cement's hydration reactions to use a significant amount of the available water (Fig. 7). Furthermore, extending the duration between the cementing process and the initiation of heating can be beneficial because it allows more water to be consumed by these hydration reactions, thereby reducing the specific mass of water. However, if water flows from the surrounding formation into the cement during this waiting period, it can counteract this effect by increasing the specific mass of water. The use of cement mixtures with a lower water–cement ratio is also advantageous. Mechanistic studies suggest that heating frequently leads to a decrease in the effective stress within the cement, which may prompt the development of a micro-annulus along the boundaries of the cement sheath. When a micro-annulus forms during the heating phase, it opens due to positive pressure, functioning similarly to a hydraulic fracture. It extends until the internal pressure drops below the surrounding radial stress. Should this micro-annulus reach a reservoir or surface, some of its water may be expelled, reducing the pressure within it, which then closes. This sequence can effectively “dry out” the cement, subsequently decreasing the specific mass of water and reducing pore pressures in subsequent heating cycles [22].

The mechanical performance of cement sheaths is highly influenced by the critical range of Poisson's ratio. When this ratio exceeds the critical range, an increase in the elastic modulus can reduce the internal pressure capacity of the cement sheath, making it more susceptible to yielding. In such scenarios, reducing the elastic modulus can improve the ability of a cement sheath to resist failure. On the other hand, if Poisson's ratio falls below the critical range, an increase in the elastic modulus enhances the pressure tolerance of the sheath. However, when Poisson's ratio is near the critical range, changes in the elastic modulus have a minimal impact on the ability of the cement sheath to withstand internal pressures [23]. Interface debonding is a significant issue that often occurs at the boundaries between the casing and cement, or between the cement and the surrounding formation. Deng et al. [24] stated that this failure mechanism is strongly associated with the accumulation of plastic strain in cement materials. Furthermore, pressure fluctuations exacerbate the risks of micro-annuli formation at these interfaces, particularly when the cement sheath enters a plastic state. Such risks are particularly pronounced in both the shallow and deep sections of wells, where stress variations are the most severe. The stability of underground storage systems may be affected by mineral precipitation owing to geochemical processes. These processes involve interactions between the injected hydrogen and the formation of brine [25]. The geochemical composition of the caprock porosity can change because of reactions between hydrogen and certain minerals and permeability, both of which are essential for maintaining efficient sealing ability. Additionally, the physicochemical characteristics of the caprock, such as capillary pressure, hydrogen upward diffusion, and wettability, control the long-term hydrogen containment and trapping capacity. Within reservoirs, formation connectivity is influenced by precipitation, mineral dissolution, and fluid movement, which affect the cycle of hydrogen, effectiveness, and full recuperation. These geochemical reactions can also change the geochemistry of the brine. The dissolution and precipitation of minerals have a profound effect on wellbore stability, thereby increasing the risk of borehole collapse and structural failure. Consequently, cement degradation caused by chemical reactions with hydrogen in the surrounding environment can compromise both wellbore stability and overall productivity. Compared to other gases, such as CO₂ and methane, hydrogen exhibits distinct reactivity characteristics with wellbore cement, which is attributed to its low density and high diffusivity. This makes hydrogen more likely to penetrate the cement seal, potentially leading to different degradation mechanisms compared to CO₂ and methane storage environments. Previous studies have shown that while CO₂ reacts with cement to form carbonates, reducing porosity and potentially self-sealing leakage paths, hydrogen's interaction is less understood and may not offer such self-sealing benefits due to its reactivity profile and diffusivity characteristics [26].

The integrity of underground gas storage wells critically depends on the properties and behaviors of cement sheaths surrounding the casing. Key aspects affecting this integrity include the shrinkage and expansion of cement sheaths after placement, driven by cement hydration and the underground thermal conditions (Fig. 8). Changes in tangential and radial stresses may result from the casing deformation due to cement bulk shrinkage or variations in temperature and pressure, posing a risk to well integrity [27]. The hydration of cement, a chemical reaction between water and cement, is crucial for setting and developing the mechanical strength of the cement over time. This reaction is exothermic, releasing heat and resulting in volumetric changes, primarily shrinkage. Taleghani et al. [28], highlighted that silica is commonly added to cement slurries that will be exposed to temperatures when expect to exceed 230 °F. These changes are significant as they can compromise the zonal isolation essential for the safe operation of gas storage wells [10]. The physical properties of cement, such as shrinkage and elasticity, directly influence bonding properties, which are crucial for maintaining the integrity of the sheath. Contrary to earlier beliefs, recent studies indicate that the compressive strength of cement is a vital factor in its tendency to debond. This is analyzed using the sophisticated Mohr–Coulomb criterion for predicting compressive failure. Addressing the challenges posed by cement hydration and the associated thermal and mechanical stresses is crucial for ensuring underground gas storage wells' long-term stability and safety.

The subsurface temperature environment of gas storage wells undergoes significant variations due to several factors, such as depth, geothermal gradient, and operational activities, including injection and withdrawal cycles. These temperature changes induce thermal expansion or contraction in the cement sheath, an essential component that provides zonal isolation and structural support [10]. For underground gas storage wells, the potential for chemical degradation of the cement sheath poses a significant risk. This highlights the need for careful material selection, including cement with modified compositions that can resist CO₂-induced degradation. The design of underground gas storage facilities must account for the potential presence of sour gases and incorporate strategies for monitoring and mitigating their impact on well integrity. This might involve advanced cementing techniques, such as the use of additives that enhance the cement's resistance to acidic environments or the deployment of protective liners that shield the cement from direct exposure to CO₂. As a result of this, ideal mixtures of cement slurry additives and formulations are needed to create cement sheaths that possess the necessary long-term durability and resistance to attacks from carbonic acid or aqueous CO₂, crucial for geological sequestration.

Well barriers are critical components in ensuring the integrity and safety of UGS wells. Their primary purpose is to prevent the migration of gases or fluids that can lead to environmental contamination and operational hazards. The literature provides extensive documentation on several types of well barriers, including mechanical seals, cement plugs, and composite materials designed to withstand the harsh conditions of underground storage. Several studies highlight the mechanical and chemical challenges discussed in the previous section, considering the policies and specifications of each set of standards because those challenges offer to ensure that the cement used in wellbore stability and abandonment retains its integrity throughout the well's life, essential for comparing the Norwegian Oil and Gas Association (NORSOK) and American Petroleum Institute (API) standards for well cement integrity. Recent advancements in barrier technologies focus on enhancing material properties to resist mechanical and chemical stresses. Innovations such as flexible cement formulas and smart materials that adapt to changing conditions have shown promise in improving the longevity and effectiveness of well barriers [29]. Developing standards like those from the API and the NORSOK has also been crucial in setting benchmarks for barrier performance and safety.

Wells drilled into hydrocarbon-bearing or highly pressurized formations, where there is a risk of fluid flow to the surface, must have at least two barriers such as cement plug and cement retainer, followed by a cement plug placed on top of the retainer after the operation for additional security. The primary and secondary barriers can be explained as follows:

Primary well barrier—Typically located near the production zone, it serves as the first line of prevention against unintended flow.

Secondary well barrier—Preferably located on the stage collar zone or near the surface as a secondary backup.

Before planning the well barrier, the shape of the well should be drawn, and all potential inflow points must be identified. According to this plan, the height of the barriers and the design should be based on the type of potential hydrocarbons in the well. If necessary, workover operations can be performed using a workover rig or coiled tubing. To ensure well safety, a casing integrity test should be conducted with the help of a packer both before and after the operation to confirm integrity. During this test, another critical factor is the workover fluid used, as the type of fluid can affect the cement composition or the effectiveness of the cement. The necessary number of well barriers, as outlined in Table 1 for the general section, includes specific criteria for barriers that prevent fluid movement between the formation and the perforation or open hole section to surface during permanent abandonment. Table 2 provides an overview of the well barriers implemented during the abandonment process, outlining their functions and the required depths.

The continuous development of well-barrier technologies aims to address the diverse challenges of underground gas storage. Researchers have been exploring the use of novel materials and composites that offer enhanced mechanical strength and chemical resistance. For instance, nano-enhanced cement incorporates nanoparticles to improve the density and impermeability of cement sheaths, thus providing better protection against gas migration and chemical attacks [26]. Recent advances in cement nanocomposites offer promising solutions for remedial cementing operations, particularly for squeeze jobs where enhanced ductility and bonding characteristics are crucial. Studies have shown that graphite nanoplatelet (GNP) (Fig. 9)-modified cement can significantly improve the mechanical properties and sealing capabilities of repair cement systems. Tabatabaei and Taleghani [30] demonstrated that surface-modified GNPs enhanced cement sheath durability by increasing the compressive strength up to 317% and flexural strength by 209% compared to conventional cement systems. This improvement in mechanical properties makes GNP-modified cement particularly suitable for squeeze operations where the repair cement must withstand cyclic loading conditions. The research also showed that acid-functionalized GNPs improved the cement–formation bonding strength by approximately 175% [30], which is critical for achieving effective zonal isolation during remedial operations.

Santos et al. [31] further demonstrated that GNP-modified cement exhibited superior performance in preventing micro-annuli formation at the cement–casing interface, with experimental results showing a significant reduction in gas migration potential. The enhanced ductility and crack-bridging capabilities of GNP–cement composites, as evidenced by Tabatabaei et al. [32], make them particularly effective for repairing stress-induced cracks and micro-annuli in damaged wellbores. More recently, studies have focused on optimizing GNP surface modification techniques to achieve better dispersion and stronger interfacial bonding with the cement matrix, resulting in improved barrier properties for remedial cementing applications [33]. A key advantage of GNP-modified cement for squeeze jobs is its ability to maintain zero-free fluid content while providing enhanced mechanical properties, addressing both the placement and long-term integrity requirements of remedial cementing operations. Another innovative approach involves using shape-memory polymers that can adapt and seal cracks autonomously, responding to changes in pressure and temperature within the wellbore [31]. Expandable shape-memory polymer (SMP) additives present a promising solution for improving cement sheath ductility and preventing micro-annulus formation. Unlike conventional expansive additives that may compromise mechanical properties, SMP additives can enhance both the expansion capabilities and ductility of the cement system. Studies have shown that SMP fibers can achieve linear expansion up to 0.61% at 6% concentration while improving the tensile strength and ductility of the cement matrix [34]. The enhanced ductility allows the cement sheath to better accommodate stress cycles and deformation without catastrophic failure, which is particularly important during hydraulic fracturing operations where the cement experiences frequent pressure and temperature fluctuations. When programmed to expand at temperatures below the cementing zone temperature, these additives expand before cement setting but after placement, helping to prevent the formation of micro-annuli at critical interfaces [28]. The fiber form of SMP additives provides additional benefits through crack-bridging mechanisms, with studies demonstrating over 30% higher expansion compared to particulate forms while maintaining good rheological properties [31]. This combination of controlled expansion and improved ductility makes SMP additives particularly effective at preventing the formation of micro-annuli and maintaining long-term wellbore integrity, especially in wells subjected to cyclic loading conditions.

Real-world applications of these technologies provide insights into their effectiveness. In one notable case, a UGS facility utilized flexible cement technology that demonstrated significant resistance to thermal and mechanical stresses during injection and withdrawal cycles. The application of this technology not only enhanced the integrity of the well but also extended its operational lifespan, demonstrating a successful adaptation to the cyclical nature of gas storage operations [35]. The impact of these advanced technologies is evaluated through a combination of laboratory tests and field trials.

In the literature, the importance of verifying the sealing efficacy of both external and internal well-barrier elements through methods such as logging, tagging, and pressure testing is widely acknowledged and is a fundamental procedure as prescribed by standards from bodies like API and NORSOK. These verification techniques are critical to confirm that the barriers installed are up to the operational and safety standards required for underground gas storage facilities. Well logging (Fig. 10) has become an essential, nonintrusive method for continuously assessing the integrity of casing cement, which serves both primary and secondary barrier roles.

The stipulations regarding the dimensions of cement plugs and the specific conditions under which they are tested—including tagging and pressure testing—are vital for guaranteeing that these barriers function reliably across diverse geological and operational contexts. Comprehensive guidelines, such as those outlined in Refs. [36–40] and NORSOK D-010, have been specifically designed to address issues like gas migration, establishing standardized best practices across the industry. Nevertheless, despite these detailed standards, there often exists a gap between anticipated outcomes and actual field results, due to the unpredictable downhole conditions, which laboratory simulations may not effectively replicate. For example, the control of gas migration that depends heavily on the gel strength of cement slurries, as per API RP 10B-6 [36], tends to vary in real-world applications compared to controlled environments. Moreover, slurry gel transition times do not always adhere to the ideal <45 min, particularly under severe conditions, posing unanticipated risks that are not always covered by existing standard protocols [21]. Field reports also frequently show discrepancies between expected and real-world outcomes, suggesting that current standards may not fully account for the varying geological and operational complexities encountered in the field. Moreover, only reliying onstatic testing times, as recommended in API RP 10B-6 [36] for evaluating gel strength transitions, may fail to account for the dynamic nature of underground environments, where variations in temperature and pressure can drastically impact the chemical behavior and physical characteristics of barrier materials. This oversight highlights a critical gap in the standardization process, where empirical data from field operations could inform more adaptable and responsive testing protocols. Therefore, this article advocates for revising existing standards to incorporate adaptive testing intervals and criteria that better mirror the complex realities of underground gas storage operations. Such enhancements could lead to more reliable, well-barrier performances, improving storage facilities' safety and operational efficiency [41]. Based on the field experience, several accidents occurred in the oil industry because of the lack of barrier length. Estimating the well-barrier length depends on the well conditions. Instead of defining the minimum well-barrier length, defining well conditions into categories based on the changing environment, type of well fluid, type of cement and its discharging techniques, lab test results or rheological properties, type of casing (gas tight or not), well production history and well cement quality percentage after the cement bond log and risk assessment result. Determining the required height of a cement barrier for mitigating specific leak paths involves a multifaceted approach that considers various physical, environmental, and material factors. The accuracy of these calculation methods can significantly influence the effectiveness of the barrier in preventing leaks. The universal application of the NORSOK D-010 model needs to account for the diverse scenarios wells may encounter. It requires the same plug high whether it can leak or not. Using a risk-based approach would give a more realistic picture of the hazards that are there. The minimum plug length for well abandonment, whether the well is in an open hole or cased hole condition, has been standardized by authorized agencies. If cement is used, it also influences whether logging (annular cement) is required to certify the quality. To understand the differences between the different country's regulations, Fig. 11 provides a summary highlighting that regulations and standards vary across different nations. Each well is different, and the length of the cement barrier can vary based on the specific bottom hole conditions. For example, if we compare the NORSOK D-010 and Texas Administrative Code standards, we can see that they unconditionally require different cement plug heights. As an oil and gas company, which one should we choose? A risk-based approach to cement barrier lengths could be used to answer this question.

Standardized testing procedures, such as those outlined by API and NORSOK, measure parameters like tensile strength, permeability, and resistance to chemical degradation. Field trials provide additional data on performance under operational conditions, helping to refine the technologies and their applications. However, while the literature on advanced well-barrier technologies often presents an optimistic view of their effectiveness, field experiences sometimes tell a different story. Numerous factors, including environmental conditions, operational practices, and material behavior under real-world stresses, can lead to outcomes that diverge significantly from theoretical expectations. In several field applications, nano-enhanced cement has shown variable performance, particularly in wells with high-salinity levels where nanoparticles tend to agglomerate, reducing their effectiveness. For instance, in a UGS well in Texas, nano-enhanced cement initially showed promising results; however, within a year, increased permeability was observed, attributed to the harsh saline environment accelerating nanoparticle degradation. Shape-memory polymers are praised for their ability to seal micro-cracks and adapt to environmental changes autonomously. However, although effective in laboratory settings, these polymers have sometimes failed to activate under the low temperatures common in deep geological formations. In the case of Alberta, Canada, the polymers did not exhibit the expected memory effect, due to inadequate thermal activation deep underground. On the other hand, field reports from a site in Louisiana indicated that the chemical resistance of the cement degraded faster than anticipated when exposed to high concentrations of H₂S, leading to the necessity for early well intervention and recementing, which was not predicted by initial laboratory tests.

Geographically, UGS wells are distributed across many countries with significant natural gas consumption and production. In the United States, for example, UGS facilities are concentrated in regions with extensive natural gas infrastructure, such as Texas, Louisiana, and Pennsylvania. Several case studies have highlighted the extent of greenhouse gas emissions from UGS wells. For instance, a study conducted in California found that a significant amount of methane was released from a UGS facility due to aging infrastructure and insufficient maintenance. Another study in Europe reported similar findings, emphasizing the need for improved monitoring and repair practices [37]. One of the most significant methane emission events in the United States occurred at the Aliso Canyon UGS facility in California. From October 2015 to February 2016, a catastrophic gas leak resulted in the release of approximately 97,100 metric tons of methane into the atmosphere, as illustrated in Fig. 12 [38]. This incident is recognized by the U.S. Environmental Protection Agency (EPA) as the largest accidental release of climate-altering gases in the nation's history, with emissions equivalent to approximately 2.0 million metric tons of CO₂. The scale of this release accounted for 6% of the total emissions from natural gas transmission and storage reported in the EPA's 2015 Greenhouse Gas Inventory. If these emissions were included in the inventory, methane emissions from storage wells would increase by 770%, far surpassing the 1999–2014 average baseline of 14,879 metric tons per year.

This incident highlighted the potential scale of emissions from UGS facilities and the need for stringent monitoring and maintenance protocols. There are 2715 active UGS wells across 160 facilities in twenty-nine states, many of which, like the Aliso Canyon well, were designed for oil production, not for gas storage. These wells, often repurposed from older infrastructure, may have design limitations such as single-point-of-failure configurations. The median age of these repurposed wells is 74 years, with some dating back to a time before modern well construction standards. Notably, 210 active wells were constructed before 1917, a period when cement zonal isolation techniques were not yet implemented [20]. National assessment reveals that a substantial number of UGS wells in the United States are potentially vulnerable to failure due to their age and design. The study calls for urgent regulatory actions to enhance the safety and reliability of the natural gas storage infrastructure. By addressing these vulnerabilities, the risk of future incidents can be significantly mitigated, protecting both public health and the environment. Risk management plays a crucial role, especially in UGS wells. It is especially important to monitor UGS wells that are currently injecting or producing gas at regular intervals. When examining past incidents, casing-related accidents constitute a massive portion of all-leak accidents [42]. Correspondingly, the direct contact of the casing with surface sources over time leads to corrosion and eventually results in casing failure. Integrating the aspect of cement integrity into the recommendations for the prevention and mitigation of gas storage facility incidents like the one at Aliso Canyon involves a comprehensive approach. The integrity of the cement used in well casings is critical for ensuring these wells' safety and operational effectiveness. Regulatory bodies should focus on the regular and comprehensive inspections of gas storage facilities and specifically mandate the integrity testing of cement used in well casings. These regulations should include standards for cement composition, placement procedures, and long-term durability to prevent gas migration and ensure wellbore stability. For the succesfuly abandonment of UGS wells using a cement plug, the length of the plug plays a significant role in ensuring well integrity and long-term sealing effectiveness. Based on the lab tests and simulations (Figs. 13 and 14), decreasing the plug length increases the risk of leakage. Reduction in the plug length from 200 to 100 m will increase the leakage rate to the environment by approximately 60%. Decreasing the plug length by 20 m (from 200 to 180 m) will increase the leakage rate by approximately 10%, and a 40-m-shorter plug (160 m) will lead to a 20% increase in the leakage rate. Cement bond logs are a primary method for evaluating the integrity of cement work behind the casing. The cement bond log (CBL) measures the bond between the casing and the cement placed in the annulus between the casing and the wellbore. A good cement bond suggests that there are no channels or voids that would allow gas migration. However, it could not be sufficient sometimes because micro-cracks are not usually measured using the CBL logs. Advanced ultrasonic tools can provide a detailed image of the cement–casing and cement–formation interfaces. These tools can detect incomplete cement fills, channels within the cement, and other anomalies that could compromise well integrity. Temperature variations can indicate the flow of fluids, suggesting potential pathways through the cement sheath or between the cement and casing. Distributed temperature sensing (DTS) technology can be used to monitor temperature variations along the wellbore. Similarly, distributed acoustic sensing technology employs fiber optics to detect acoustic signals, providing valuable insights into well integrity and fluid flow. As known, gas storage wells are old wells, meaning that data acquisition may need to be improved most of the time. Even though CBL and DTS show that the integrity of cement is good, for assessing the integrity of older cement jobs, electromagnetic corrosion tools can identify corrosion in the casing, which may indicate the presence of aggressive chemicals that could also compromise the cement.

On the other hand, packer and tubular selection is vital for the gas storage wells. Packer and wellhead seals must be selected with special design and must pass the V0 test, and tubular threats must be selected as gas tight. The Special Grade V0 validation includes gas testing, axial loads, temperature cycling, and a bubble-tight gas seal to meet specific well condition requirements for a tight gas seal. While the test parameters align with those of Grade V1, the key distinction is that no gas leakage is permitted during the hold period, as stipulated in API Spec 11D1 [39]. Based on the comprehensive research and analysis of the zonal isolation issues in UGS wells which leads to greenhouse gas emissions, particularly focusing on the integrity problems related to cement plugs used in gas storage wells, here are some discussion remarks that could be highlighted in this study as critical cement plug heights for varied gases, reservoir characteristics' role, importance of cement slurry design, regulatory and safety considerations, uniformity in reservoir conditions assumption, effectiveness of risk-based methodology, and cross-comparative analysis of UGS wells histories. Newly constructed wells are not always resistant to leaks and spills. Design issues or challenges may compromise the integrity of the casing. Substandard materials can significantly raise the risk of leaks. For example, at the Magnolia UGS facility, a casing failure followed by a gas release occurred merely a month after receiving operational certification. Geological conditions, including high-pressure gas or water zones at shallow to intermediate depths, may compromise the integrity of annular seals, leading to potential leakage. Moreover, the presence of hydrogen sulfide (HS) and carbon dioxide (CO₂) in the surrounding environment (Fig. 15) can accelerate the deterioration of annular seals and steel casing, further endangering the system's stability.

This research brings a novel perspective to optimizing cement plug heights for gas storage wells, highlighting the intricate interplay between gas properties, reservoir characteristics, and cement slurry design [43]. The findings highlight the need for enhanced risk management practices in UGS operations, particularly for older wells with single-point-of-failure designs. The disproportionate impact of a few large events on overall emissions suggests that targeted interventions on high-risk wells could significantly reduce methane emissions. The study also underscores the importance of accurate and comprehensive reporting of UGS incidents to improve risk assessment and management.

The findings of this study emphasize the multifaceted challenges associated with maintaining integrity in UGS wells, particularly in the aging infrastructure that was originally designed for production. These wells are often constructed according to older standards that do not account for the unique demands of gas storage operations. As these wells are repurposed, issues such as mechanical failure, thermal cycling, and chemical degradation have become increasingly prominent, particularly under cyclic operational conditions. Thermal and mechanical stresses often lead to structural failures, such as radial cracking, debonding at the casing–cement or cement–formation interfaces, and micro-annuli formation. For example, the data indicate a 60% increase in leakage rates when cement plug lengths are reduced from 200 m to 100 m, highlighting the direct correlation between design parameters and well integrity. These findings demonstrate the importance of tailoring cement designs to the geomechanical and operational conditions of UGS wells.

Recent advances in material technology, such as GNP-modified cements and SMPs, offer promising solutions to address these challenges. GNP-modified cements have shown significant improvements in mechanical properties, including enhanced compressive and flexural strengths, making them highly suitable for cyclic loading environments. Acid-functionalized GNPs have also been demonstrated to improve the bonding strength at the cement–formation interface, addressing one of the key weaknesses of conventional cement systems. However, field applications of GNP-modified cement have revealed challenges, such as nanoparticle agglomeration in high-salinity environments, which reduces their effectiveness. This highlights the need for further refinement of the dispersion techniques and surface modification processes to optimize the performance under varying field conditions. On the other hand, SMP additives provide unique advantages in their ability to expand and adapt to stress cycles, reducing the risk of micro-annuli formation. These materials combine controlled expansion with improved ductility, allowing the cement sheath to maintain its integrity under thermal and mechanical stress fluctuations. However, their performance is influenced by factors such as activation temperature and environmental conditions. For instance, achieving consistent activation in low-temperature formations remains a challenge, necessitating further research and optimization for broader applicability.

Furthermore, regulatory approaches should prioritize risk-based design methodologies that address the specific needs of aging infrastructure. Enhanced monitoring programs tailored to facility age and operational history are critical for the early detection of potential failures. Technologies such as DTS and advanced ultrasonic tools for cement bond evaluation provide valuable insights but require wider adoption and integration into standard practices. Field data also underscore the importance of proactive maintenance strategies. For example, wells located in environments with high H₂S and CO₂ concentrations experience accelerated cement degradation, leading to an increased risk of gas migration. These observations reinforce the need for specialized cement formulations capable of resisting chemical degradation while maintaining their mechanical properties. The adoption of dual-barrier systems that incorporate both mechanical and cement barriers offers a robust approach to enhancing well integrity of high-risk scenarios. The environmental and economic implications of UGS well-integrity failure are significant. Incidents such as the Aliso Canyon gas leak have resulted in substantial greenhouse gas emissions and financial losses associated with compromised storage systems. These cases highlight the urgency of advancing well-integrity management practices to mitigate such risks while ensuring the safety and reliability of gas storage operations.

This study highlights the complex challenges associated with maintaining well integrity in UGS facilities, particularly in repurposed wells. The behavior of cement sheaths under cyclic operational conditions demonstrates a clear link between the design parameters and well performance. Field data, such as a 60% increase in leakage rates associated with reduced cement plug lengths, underscore the critical importance of tailoring cement designs to specific geomechanical and operational conditions. Furthermore, cyclic loading and temperature fluctuations have been shown to accelerate cement degradation, particularly in wells exposed to high-stress and corrosive environments.

In the United States, many UGS wells originally drilled as production wells in the mid-20th century have been operating as storage wells for decades beyond their initial design lifespan. This extended use emphasizes the importance of robust long-term integrity solutions. Advanced materials, such as nano-enhanced cement and shape-memory polymers, have shown significant potential for addressing these challenges. However, inconsistencies in the field performance highlight the need for more representative testing protocols and further research to optimize these materials under diverse operating conditions. The findings of this review have important implications for industrial practices and regulatory frameworks. Risk-based design methodologies should be prioritized, particularly for aging wells and those with single-point-of-failure designs. Proactive monitoring programs tailored to facility age and operational history are essential for early detection of potential integrity failures. Additionally, dual-barrier systems that incorporate mechanical and cement barriers represent a robust solution for high-risk wells. However, implementing these solutions requires an integrated approach that combines material innovation, advanced monitoring technologies, and updated regulatory standards. Future research should focus on developing advanced cement formulations tailored specifically for the unique conditions of UGS operations. This includes creating materials capable of withstanding cyclic mechanical and thermal loading while resisting chemical degradation. Real-time monitoring technologies and predictive modeling systems must be developed to better understand and mitigate potential failure mechanisms. Standardized testing protocols that simulate field conditions more accurately are critical for bridging the gap between laboratory performance and real-world applications. Although progress has been made in understanding the failure mechanisms and mitigation strategies for UGS well integrity, significant gaps remain between theoretical advancements and field implementation. Addressing these gaps through improved materials, enhanced monitoring systems, and more robust regulatory frameworks is critical for the safe and sustainable operation of UGS facilities. As reliance on UGS wells infrastructure grows, the adoption of proactive, risk-based approaches will be essential for ensuring operational safety, environmental protection, and long-term viability of UGS systems. These findings provide a foundation for advancing well-integrity management and adapting industry practices to meet the demands of modern UGS operations.

There are no conflicts of interest. This article does not include research in which human participants were involved. Informed consent is not applicable. This article does not include any research in which animal participants were involved.

No data, models, or code were generated or used for this article.

API =

American Petroleum Institute

CCI =

Casing–cement interface

CFI =

Cement formation interface

GNP =

Graphite nanoplatelet

NORSOK =

Norwegian Oil and Gas Association

SMP =

Shape-memory polymer

UGS =

Underground gas storage