Storage In Geological Formations Research Articles

Monitoring Salt Domes Used for Energy Storage With Microseismicity: Insights for a Carbon‐Neutral Future

AbstractUnderground storage in geologic formations will play a key role in the energy transition by providing low‐cost storage of renewable fuels such as hydrogen. The sealing qualities of caverns leached in salt and availability of domal salt bodies make them ideal for energy storage. However, unstable boundary shear zones of anomalous friable salt can enhance internal shearing and pose a structural hazard to storage operations. Considering the indistinct nature of internal salt heterogeneities when imaged with conventional techniques such as reflection seismic surveys, we develop a method to map shear zones using seismicity patterns in the US Gulf Coast, the region with the world's largest underground crude oil emergency supply. We developed and finetuned a machine learning algorithm using tectonic and local microearthquakes. The finetuned model was applied to detect microearthquakes in a 12‐month long nodal seismic dataset from the Sorrento salt dome. Clustered microearthquake locations reveal the three‐dimensional geometry of two anomalous salt shear zones and their orientations were determined using probabilistic hypocenter imaging. The seismicity pattern, combined with borehole pressure measurements, and cavern sonar surveys, shows the spatiotemporal evolution of cavern shapes within the salt dome. We describe how shear zone seismicity contributed to a cavern well failure and gas release incident that occurred during monitoring. Our findings show that caverns placed close to shear zones are more susceptible to structural damage. We propose a non‐invasive technique for mapping hazards related to internal salt dome deformation that can be employed in high‐noise industrial settings to characterize storage facilities.

New algorithm of three-phase equilibrium calculations for CO2-hydrocarbon-water systems

In this century, global warming caused by the accumulation of atmospheric carbon dioxide has become an essential concern. The industry has two main decarbonization options: CO2 capture for permanent storage in geological formations and CO2 utilization for enhancing oil recovery (EOR). Both methods require accurate reservoir simulation to correctly describe the fluids flowing process and design an optimal injection plan. However, existing reservoir simulation practices often neglect the interaction and dissolution of CO2 and hydrocarbon components in water, leading to inaccurate predictions. Neglecting CO2 dissolution in water undermines storage estimation for capture and results in unreliable EOR descriptions. Therefore, to address this, our study focuses on developing a reliable and accurate phase equilibrium calculation package for hydrocarbon-CO2-water three-phase systems, which meets the demanding efficiency and robustness criteria of reservoir simulation. In this paper, we first introduce the methodology of the three-phase equilibrium calculation algorithm, then illustrate the numerical techniques employed to improve computational efficiency and finally demonstrate superior robustness of this algorithm through comprehensive case studies. Our research contributes three key improvements. First, we have increased the reliability of phase behavior descriptions by considering the dissolution of CO2 and hydrocarbon components in water. Second, we have enhanced the robustness of the three-phase equilibrium calculations algorithm, enabling accurate determination of three-phase statuses and fluid behaviors where standard commercial software may fail. Third, our algorithm exhibits notable efficiency improvements, ensuring its suitability for three-phase compositional simulations. The findings of this research provide valuable insights into the accurate modeling of hydrocarbon-CO2-water three-phase systems and offer practical solutions for designing effective CO2 reduction strategies.

Assessing the Limit of CO2 Storage in Seawater as Bicarbonate-Enriched Solutions.

The dissolution of CO2 in seawater in the form of bicarbonate ions is an attractive alternative to storage in geological formations, on the condition that the storage is stable over long periods and does not harm the marine environment. In this work, we focus on the long-term chemical stability of CO2 absorbed in seawater as bicarbonate by monitoring the physico-chemical properties of the solutions (pH, dissolved inorganic carbon and alkalinity) in six different sets of experiments on both natural and artificial seawater lasting up to three months. The bicarbonate treatment of natural seawater consists of mixing it with pre-equilibrated solutions obtained from the reaction of CO2 and Ca(OH)2, with the same pH as natural seawater. This was achieved with a pilot plant working with tons of seawater, while small-scale laboratory experiments were carried out by adding sodium bicarbonate to artificial seawater solutions. If the increase in the overall carbon concentration in the final mixture does not exceed a critical threshold (about 1000-1500 μmol/L), the resulting bicarbonate-rich solutions are found to be stable for over three months.

Study Reviews Reservoir Engineering Aspects of Geologic Hydrogen Storage

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 23943, “Reservoir Engineering Aspects of Geologic Hydrogen Storage,” by Johannes F. Bauer, Mohd M. Amro, SPE, and Taofik Nassan, SPE, Technical University Bergakademie Freiberg, et al. The paper has not been peer reviewed. Copyright 2024 International Petroleum Technology Conference. Reproduced by permission. _ Safe and effective large-scale storage of hydrogen (H2) is one of the greatest challenges of the global energy transition and can be realized only through storage in geological formations. The aim of the study detailed in the complete paper is to address and discuss the reservoir engineering aspects of geological H2 storage (GHS). The study is based on two sources: first, a comprehensive literature review and, second, experimental and numerical work performed by the authors’ institute. H2 Pressure/Volume/Temperature (PVT)/Phase Behavior The definition of the PVT/phase behavior of reservoir fluids is crucial in GHS because thermodynamic properties significantly affect safety and effectiveness. The properties of H2 are widely known and modeled, but its reaction with other gases, such as in-situ gases like natural gas in depleted gas reservoirs (DGR), currently is under investigation. Although the ideal gas law can account for H2 behavior at low pressure, accurate depiction of its thermodynamic properties requires more-sophisticated equations of state (EOS), especially when it is mixed with other gases such as methane. Most commercial reservoir simulators use EOS packages that can model the complex properties of these mixtures, mostly within required reliability. In most instances, calibration is still required if experimental PVT data are available. Reservoir Engineering of GHS. GHS projects must meet three crucial technical benchmarks for underground storage: capacity (storage volume), injectivity/productivity (rate of injection/withdrawal in relation to wellhead pressure), and containment integrity (prevention of leakage). Economic sustainability requires that projects must adhere to these standards, which may vary according to the selected geological formations. Although various subsurface structures can store H2, only specific formations such as salt caverns (SCs), saline aquifers (SAs), and depleted gas/oil reservoirs (DGRs and DORs), fulfill the requirements. While the complete paper discusses all three of these formation types in detail, this synopsis will concentrate on SCs. GHS in SCs. SC storage typically involves up to three wells for one cavern with a volume of up to 500,000 std m3, providing a delivery rate of 8,500–17,000 std m3/day. Working gas accounts for up to 65% of the total gas, while water should be kept to a minimum. SCs usually allow between six and 12 operating cycles per year, each lasting approximately 10 days for withdrawal periods. SCs offer high H2 purity and sealed storage. The storage capacity of caverns in Germany is determined by their volume and pressure limitations while avoiding any negative geomechanical effects. These caverns can range in depth from 500 to 2000 m, with heights of up to 400 m. Approximately 30 to 50% of the total stored volume is used as cushion gas to maintain production pressure. Estimating the capacity of these caverns relies on their geometry and thermodynamics, resulting in relatively lower uncertainties when compared with storages in porous media.

Bioreaction coupled flow simulations: Impacts of methanogenesis on seasonal underground hydrogen storage

Assessing microbial risks is key to feasible hydrogen storage in geological formations. This work quantitatively analyses the impacts of bio-methanation on hydrogen storage performance. Fine-scale flow simulations, coupled with the bio-methanation reaction, are presented to analyse its impact on the storage performance. Based on the reported rates in literature, methanogenesis may slightly degrade the recovery performance of hydrogen but is considered minor compared with the issue of gas mixing. The impacts of methanogenesis on a time scale of months (330 days) becomes observable in the system configured here, when the methanation rate is above 1746 nano molality per hour. The assumed methanation rate is two times greater than the rate reported from the Olla filed. Validated scaling theory generalises findings for gravity-dominated scenarios. But viscous-dominated flows see complications from property variations due to pressure changes at high rates. This study provides definitions of “target properties” (e.g., acceptable methanogenesis rates) for screening hydrogen storage projects.

FIRST EXPERIENCE IN THE ZONAL FORECAST OVER THE MOSCOW ARTESIAN BASIN FOR THE IMPLEMENTATION OF CCS PROJECTS

Link for citation: Novikov D.A., Fomina (Sadykova) Ya.V., Yurchik I.I., Derkachev A.S., Chernykh A.V., Dultsev F.F., Maksimova A.A., Nikitenkov A.N., Knyazev A.G. First experience in the zonal forecast over the Moscow artesian basin for the implementation of CCS projects. Bulletin of the Tomsk Polytechnic University. Geo Аssets Engineering, 2023, vol. 334, no. 10, рр. 119-139. In Rus. The relevance of the investigation is caused by a substantial increase in greenhouse gas emissions all over the world, which is the most essential ecological problem causing climate change, glaciers melting, and atmospheric pollution. The most efficient method to reduce emissions is long-term carbon dioxide capture and storage in geological formations. Since the enterprises emitting carbon dioxide are highly concentrated in the European part of the Russian Federation, it is reasonable to arrange carbon dioxide storage facilities within the boundaries of the Moscow artesian basin. The goal of investigation was to make a zonal forecast of the outlooks for the implementation of CCS projects at the territory of the Moscow artesian basin, to reveal the geological structures that are promising for carbon dioxide storage, and evaluate the potential capacity of traps for carbon dioxide capture and storage. The objects of investigation are water-bearing and waterproof horizons of the lower aquifer in the Moscow artesian basin. Methods. A system of criteria for the zonal forecast of hydrogeological structures is proposed to implement the projects aimed at geological capture and storage of carbon dioxide in deep aquifers, relying on the actual international and Russian normative basis on the burial of carbon dioxide, industrial wastewaters, toxic wastes, arrangement and monitoring of underground storage facilities. Evaluation system includes eight groups of criteria: general hydrogeological, structural-tectonic, lithological, hydrodynamic, geothermal, hydrogeochemical, environmental, and resource-related. Within each group of criteria, two and more parameters affecting evaluation of the suitability of a territory for CCS project implementation are distinguished. Results. Evaluation of the potential of the Moscow artesian basin from the viewpoint of its suitability for long-term CO2 storage has been carried out for the first time. The forecast over the proposed criteria allowed us to map the lands with different degrees of prospective viability. The structures of medium promise include 16 geological structures with the initial CO2 capture and storage capacity of 150,6 billion tons in water-dissolved state and of 13,4 billion tons in the supercritical state. In addition, the regions of low and zero promise were distinguished. Analysis results allow us to pass to the local evaluation of the structures of medium promise in order to perform licensing and to assign the structures to the foundation of potential carbon dioxide storage facilities, which implies more detailed investigation of collectors and impermeable seal rocks, structural tectonic parameters, computer simulation of water–rock–gas interactions, and compulsory laboratory experiments.

A general review of CO2 sequestration in underground geological formations and assessment of depleted hydrocarbon reservoirs in the Niger Delta

This paper investigates the viability of CO2 storage in geological formations, including depleted hydrocarbon reservoirs applying 3-dimensional seismic and well data of the Niger Delta region as a case study for CO2 sequestration, which represents an essential initiative for the reduction of greenhouse gas emissions. Different theoretical and experimental studies from literature on CO2 sequestration in geological formations across the world, including the Niger Delta, are reviewed. The Niger Delta basin has a high potential for CO2 sequestration, and this indication is shown through the review of research papers undertaken outside and within the basin, which reveal the presence of massive hydrocarbon fields, lateral continuity of reservoir, reservoir-seal pairs, faults, and traps, developed hydrocarbon fields, appropriate reservoir depth. The gaps identified from the review of various research studies are analyzed to form the basis of a future research investigation for capturing, removing, and storing CO2 in depleted hydrocarbon reservoirs and other geological formations. The authors deduced that accurate injection pressure, rate, and depth estimation are critical factors for CO2 sequestration and need to be thoroughly investigated.

Hydrogen, carbon dioxide, and methane adsorption potential on Jordanian organic-rich source rocks: Implications for underground H2 storage and retrieval

Hydrogen (H2) storage in geological formations offers a potential large-scale solution suitable for an industrial-scale hydrogen economy. However, the presence of organic residuals can significantly influence the H2 storage efficiency, as well as cushion gas performance, such as CO2 and CH4, injected to maintain healthy reservoir pressure. Thus, the H2 storage efficiency and cushion gas selectivity were thoroughly investigated in this work based on H2, CO2, and CH4 adsorption measurements using, for the first time, actual organic-rich carbonate-rich Jordanian source rock samples (TOC = 13 % to 18 %), measured at 60 °C temperature and a wide range of pressure (0.1 – 10.0 MPa). Initially, the samples were characterized using various analytical methods. Results demonstrated that H2 adsorption capacities reached up to 0.47 mol/kg at 9.0 MPa. The measured adsorption of CO2 was four times higher than H2. An increase in TOC significantly decreased H2 adsorption compared to CO2 and CH4. Additionally, CO2 demonstrated preferential behavior as a cushion gas compared to CH4, attributed mainly to the calcite content and presence of carboxyl and sulfonyl groups. This study provides fundamental data for understanding H2 potential storage issues in an organic-rich rock formation and thus aids in the industrial implementation of an H2 supply chain.

Optimal Set of Criteria for the Zonal Forecast of the Potential for Carbon Dioxide Capture and Storage in Geological Formations

Geological criteria for the zonal evaluation of the RF territory potential for CO2 capture and storage are substantiated. The criteria of zonal forecast for the areas within the RF boundaries are proposed to arrange and monitor underground storage facilities are proposed on the basis of the international and Russian regulatory frameworks on the disposal of carbon dioxide, industrial wastewaters, toxic wastes, arrangement and monitoring of underground storage facilities for the purpose of implementing Carbon Capture and Storage (CCS) projects. The scheme of investigation of the geological structures is built up, and brief characterization of each parameter along with its significance degree in the evaluation system is presented.

Characterization of Aquifer Poroelastic Response to Impulse and Oscillatory Well Pressure Using Distributed Acoustic Sensing

AbstractThe storage of fluids in the subsurface is critical for a broad spectrum of applications including managed aquifer recharge, storage of liquefied carbon dioxide and hydrogen, geothermal heat extraction and exploitation of hydrocarbon. It is surprising then, that there has been relatively little measurement of the vertical distribution of poroelastic storage in geologic formations as compared with permeability. We present experiments in which fluid was injected into an important regional aquifer and the depth‐dependent strain response measured using fiber optic distributed acoustic sensing. The formation expansion and contraction in response to fluid injection were several 100 nanostrain. Strain, and the implied storage distribution, was highly localized in specific strata and demonstrated complex, hydromechanical behavior. This new window into fluid‐geomechanical coupling undermines some typically use models and observations currently in practice, but provides potential for complete representation and prediction of fluid storage in the subsurface.

Simulation case studies of aqueous formate solution for geological carbon storage

Carbon storage in geologic formations has been considered an important technology that reduces the carbon intensity of industrial processes based on fossil fuels. Carbon capture and storage (CCS) conventionally uses carbon dioxide (CO2) as a carbon carrier. However, various shortcomings of the conventional CCS are related to the physical properties of CO2, such as low carbon density at low to moderate pressure, low mass density, low viscosity, immiscibility with water, and corrosivity. In particular, CO2 injection often results in inefficient use of pore space in the formation under geophysical heterogeneities.This paper presents case studies of using aqueous formate solution as carbon-bearing water for geological carbon storage. Properties of aqueous formate solutions were measured. Experimental results showed that the formate solubility in 102,600-ppm NaCl + CaCl2 brine ranged from 30 wt% to 35 wt% between 25 and 75 °C. Viscosities of 30 wt% formate solutions in the brine were approximately 12 cp at 25 °C, 5 cp at 50 °C, and 3 cp at 75 °C with Newtonian behavior.Numerical reservoir simulations were performed for an aquifer and an oil reservoir. Simulation results consistently showed that the formate injection case resulted in more stable fronts of oil and water displacement. The more stable fronts yielded the oil recovery and carbon storage that were insensitive to the injectant breakthrough. This is a substantial advantage of using formate as a carbon carrier for controlling the risk of CCS associated with the permeability heterogeneities and their impact on the subsurface flow regime.The case study of enhanced oil recovery and carbon storage in an oil reservoir showed that the net present value (NPV) of the formate injection case would be equivalent to that of the CO2 injection case when the cost of CO2 electrochemical reduction (ECR) into formate was $269/t-CO2 for year 20. The breakeven cost of CO2 ECR for the formate injection case was $575/t-CO2 for year 20. Although the estimated CO2 ECR costs are sensitive to many factors, they are not unrealistically higher than the current costs of CO2 ECR reported in the literature.

Mathematical Model of the Process of Non-Equilibrium Hydrate Formation in a Porous Reservoir during Gas Injection

Increasing the efficiency of natural gas storage in geological formations is possible by transferring gas from a free state to a gas hydrate state, since gas hydrates have a number of unique properties. For example, 1 m3 of methane hydrate contains 164 m3 of gas under normal conditions. It is possible to store a sufficiently large amount of gas in a small volume at a relatively low pressure. To study the regularities of the process of formation of underground gas hydrate gas storage, this article presents a mathematical model of the process of methane injection into a natural reservoir saturated with methane and water, accompanied by the formation of gas hydrate. Unlike previous works, the constructed mathematical model additionally takes into account a number of factors: the filtration flow of water, the real gas properties, the Joule–Thomson effects and adiabatic compression. The process of gas hydrate formation is considered as a non-equilibrium phase transition. Numerical solutions of the problem are constructed that describe the distributions of parameters (temperature, pressure, phase saturations) in a reservoir. Dependences are obtained that reveal the regularities of the process of non-equilibrium formation of gas hydrate in a natural reservoir during gas injection. The influence of gas injection pressure and temperature, as well as reservoir porosity and permeability, on the distributions of pressure, temperature, water saturation and hydrate saturation in the reservoir, as well as on the dynamics of changes in these parameters and the mass of gas hydrate formed in the reservoir over time, are analyzed.

Carbon capture and storage for long-term and safe sealing with constrained natural CO2 analogs

Carbon capture and storage for long-term sealing is one of the most promising approaches to mitigate global climate change. However, maximum capture amount and long-term safety of carbon dioxide storage in geological scenarios must be ensured. A case of a natural CO2 storage analog of the Huangqiao CO2-oil reservoir in the northern Jiangsu Basin, eastern China, is presented that can safely preserve carbon for millions of years, despite the mantle CO2-rich fluid having substantially altered the sandstone reservoirs. The calcite in the sandstone was significantly reduced by dissolution, thereby improving the CO2 storage capacity. Meanwhile, the mantle CO2-rich fluid advanced the precipitated calcite cement in the fractures of the mudstone caprock as it migrated upward, serving to self-seal the fractures and enhance the sealing capacity of CO2 storage. We numerically simulated artificial CO2 injection for 30 years in the depleted oil reservoir of Jurong near the Huangqiao CO2-oil reservoir; the maximum amount of CO2 injected into a single well can reach 5.43 × 106 t and increase the formation pressure by up to 95 bar. After injection, the saturation of gas-phase CO2 did not decrease remarkably over the following 300 years. No projected rapid CO2 leaked through fractures, owing to the self-sealing of fractures through calcite cement. This suggests that the depleted petroleum reservoir with an assemblage of sandstone reservoirs and overlying mudstone caprocks could be suitable for long-term and safe carbon capture and storage in geological formations.

Investigation of supercritical CO2 mass transfer in porous media using X-ray micro-computed tomography

Understanding the mass transfer of CO2 into formation brine both qualitatively and quantitatively is important for improving the security of geologic carbon sequestration. In this study, quasi-dynamic X-ray micro-computed tomographic (MCT) imaging was used to track the time-evolution of supercritical CO2 (scCO2) clusters in a sandstone throughout brine injection. A cluster-matching workflow enabled the identification of depletion, merging, and snap-off of the scCO2 clusters, and subsequently the mass transfer coefficient of individual scCO2 clusters was found to range between 3.0×10−5 and 3.5×10−4 mm/s. The macroscopic average mass transfer coefficient was estimated as 1.4×10−4 mm/s. For application to geologic carbon sequestration, these values give an indication of the range of mass transfer coefficients that may be expected for similar state and flow conditions. With the macroscopic average mass transfer coefficient evaluated, we back-calculated the in-situ CO2 concentration field for brine, which provides quantitative insight of the distribution of dissolved CO2 in the sample. Despite slow injection rate (Ca = 10−7), mobilization of small scCO2 clusters was also observed, and was attributed to the combined effect of incomplete dissolution of snapped-off clusters and the reduction in the fluid–fluid interfacial tension (IFT) due to the high local CO2 concentration in brine accompanying scCO2 dissolution. This highlights the coupling of dissolution and mobilization processes and demonstrates the need to understand these interlinked dynamics to improve CO2 storage in geological formations.

Molecular dynamics simulation and machine learning for predicting hydrogen solubility in water: Effects of temperature, pressure, finite system size and choice of molecular force fields

Understanding hydrogen solubility in groundwater is critical for predicting the long-term performance of underground hydrogen storage in geological formations. Nevertheless, the effect of finite-size, force fields on hydrogen solubility were not investigated in previous molecular dynamics(MD) studies and available experimental data were limited to a narrow temperature range. This paper proposed a combined MD and machine learning(ML) methods to study hydrogen solubility over a wide temperature range of 273–433 K. Comparison of different models revealed that TIP4P/2005 water model and hydrogen model of Yang & Zhong (J.Phys.Chem.B,109(2005),11862–11864) was successful in reproducing the experimental results. A minimum value of hydrogen solubility presents at 330 K. Finite-size effects were quantified and suitable hydrogen and water models were identified. Eight ML models were developed based on density, temperature, pressure, and excess chemical potential. They justified that the pressure is the most influential variable, whereas temperature has a non-linear effect on hydrogen solubility.

Communicating leakage risk in the hydrogen economy: Lessons already learned from geoenergy industries

Hydrogen is set to play a part in delivering a net zero emissions future globally. However, previous research finds that risk perception issues are particularly challenging for emerging and potentially unfamiliar technologies. Hydrogen as a fuel falls into this category. Thus, while the hydrogen value chain could offer a range of potential environmental, economic and social benefits, it is imperative that the roll-out of hydrogen fits with societal expectations of how risk ought to be managed—and by whom. Communication and engagement are critical to ensure 1) communities and stakeholders are able to come to informed decisions on hydrogen and 2) developers, operators and regulators are able to respond to societal concerns and adapt practices appropriately.Within the hydrogen value chain, geological storage may be an important step, but could present challenges in terms of perceived safety. Lessons can be learned from international research and practice of CO2 and natural gas storage in geological formations [for carbon capture and storage (CCS) and power respectively] which may be relevant to hydrogen storage in salt caverns or porous sandstones. We draw on these analogues to present potential societal risk perception issues which may arise for geological storage of hydrogen. We argue that site-specific communication and engagement strategies, underpinned by broad-based principles covering the entire span of the project and a clear rationale for how hydrogen benefits the climate and the most vulnerable members of society under an energy crisis, will be critical to fostering societal support for geological hydrogen storage.

Hydrogen Storage in Geological Formations—The Potential of Salt Caverns

Hydrogen-based technologies are among the most promising solutions to fulfill the zero-emission scenario and ensure the energy independence of many countries. Hydrogen is considered a green energy carrier, which can be utilized in the energy, transport, and chemical sectors. However, efficient and safe large-scale hydrogen storage is still challenging. The most frequently used hydrogen storage solutions in industry, i.e., compression and liquefaction, are highly energy-consuming. Underground hydrogen storage is considered the most economical and safe option for large-scale utilization at various time scales. Among underground geological formations, salt caverns are the most promising for hydrogen storage, due to their suitable physicochemical and mechanical properties that ensure safe and efficient storage even at high pressures. In this paper, recent advances in underground storage with a particular emphasis on salt cavern utilization in Europe are presented. The initial experience in hydrogen storage in underground reservoirs was discussed, and the potential for worldwide commercialization of this technology was analyzed. In Poland, salt deposits from the north-west and central regions (e.g., Rogóźno, Damasławek, Łeba) are considered possible formations for hydrogen storage. The Gubin area is also promising, where 25 salt caverns with a total capacity of 1600 million Nm3 can be constructed.

CO2 storage in carbonate rocks: An experimental and geochemical modeling study

Carbon dioxide storage in geological formations is one of the mature strategies developed for controlling global warming. This paper represents a comprehensive experimental and geochemical modeling study to analyze CO2-brine-rock interactions in a carbonate rock containing calcite and dolomite minerals. PHREEQC geochemical package has been applied for modeling the geochemical reactions in the studied porous media. Firstly, dynamic experiments are performed to calibrate the geochemical model. Then, static experiments are conducted to study the geochemical reactions in the CO2-brine-rock interaction system. This study contributes to analyzing the precipitation-dissolution and ion exchange mechanisms in the CO2-brine- carbonate rock reactions during carbon dioxide storage. The purpose of the present paper is providing a scientific basis to judge surface CO2 loading in carbonate reservoirs. Results of the present study show that brine-rock interaction increases the dissolution of carbon dioxide gas in the aqueous phase. It is also demonstrated that carbonate ions can attach to the minerals' surface through the ion exchange mechanism. Among the surface ion exchangers, >CaHCO3 contains the maximum amount of carbonate ion. At the high pressures, amount of the carbon dioxide stored on the minerals' surface is almost independent of the pressure variation.

Scaling analysis of hydrogen flow with carbon dioxide cushion gas in subsurface heterogeneous porous media

Subsurface hydrogen (H2) storage in geological formations is of growing interest for decarbonization. However, there is a knowledge gap in understanding the multiphase flow involved in this process, which can have a significant impact on the recovery performance of H2. Therefore, a full-compositional modeling study was conducted to analyze potential issues and to understand the fundamental hydrodynamic mechanisms of H2 storage. We performed a range of 2D vertical simulations at the decametre scale with a very fine cell size (0.1 m) to observe the detailed flow behaviour of H2 with carbon dioxide (CO2) as cushion gas in various flow regimes. Issues such as viscous instability, capillary bypassing, gas trapping and gravity segregation are analysed here. To generalize our calculations, we have validated and applied the scaling theory in the context of subsurface H2 storage. Since this study is focused on the hydrodynamic behaviour, three dimensionless groups, including aspect factor, capillary/viscous ratio and gravity/viscous ratio were identified to correlate recovery performance between various scales in a fixed heterogeneous system. It was found that H2 could infiltrate the cushion gas in the proximity of the injectors, meaning that CO2 is not displaced away from the injectors in a piston-like fashion. As a result, the purity of the back produced H2 is much degraded, particularly in a viscous-dominated scenario. On the other hand, the injected H2 mostly accumulates at the top forming a highly restricted mixing zone with CO2 in the gravity-dominated case. The recovery performance is therefore much improved in this case. Although the gas distribution can be significantly altered by capillary forces leading to bypassed zones, the recovery performance of H2 is hardly influenced. This is because the back-produced H2 recovery is not dependent on the sweep efficiency of the gas. H2 can be back produced following the same paths which were formed during injection.

Development of optimum СО2 transportation for its storage in geological formations

The sources of a large amount of carbon dioxide emissions into the atmosphere in Azerbaijan have been identified, the volume of burned hydrocarbons and the amount of waste calculated as well. The methods of centralized collection, transportation and disposal of waste from sources on the territory were studied as the main object of research work. The relevant geological formations existing in Azerbaijan were studied and their gas capacity specified by identifying geological formations for storage of accumulated CO2 gases in underground formations (underground gas storage). The study is based on global experience, real production facilities, new projects, modern technologies and equipment for CO2 collection.