An approach for assessment of CO 2 leakage using mechanistic modelling: CO 2 injection in deep saline aquifer of Lithuanian basin in presence of fault and fractures

. Injecting CO 2 into deep saline aquifers is a prominent strategy for carbon capture and storage (CCS) to mitigate greenhouse gas emissions. However, ensuring the long-term integrity of CO 2 storage is crucial to prevent leakage and potential environmental hazards. This paper investigates the impact of presence of faults and fracture on CO 2 leakage volumes. Particular case of CO 2 injection into a deep saline aquifer for carbon capture and storage (CCS) applications is investigated. This paper explores the relationship between fracture permeability and the potential for CO 2 leakage.


Introduction
Carbon dioxide (CO 2 ) leakage is a pressing environmental issue that arises from various industrial processes, particularly those related to the extraction and storage of fossil fuels.The inadvertent release of CO 2 during these operations can have detrimental effects on both the environment and human health [1].CO 2 leakage can occur due to several factors, including inadequate well integrity, faults or fractures in underground storage reservoirs, and failures in transportation pipelines [2][3][4].In the context of carbon capture and storage (CCS), which involves capturing CO 2 emissions from power plants and industrial facilities and storing them underground, leakages can result from improper storage site selection, poor monitoring, or human error during injection or storage operations [5].
The injection of CO 2 into deep saline aquifers offers significant potential for large-scale and long-term storage of carbon dioxide.These aquifers, characterized by their high storage capacity and widespread distribution, are considered one of the most promising geological formations for CO 2 storage [6].Potential places for CO 2 sequestration around the world are shown in Fig. 1.Different aspects of CO 2 storage in Baltic basin have been investigated from pore scale modelling to simulation based assessment of storage [7,8], showing significant CO 2 storage potential.The presence of faults and fractures in these reservoirs introduces challenges in maintaining the integrity of the storage system and preventing CO 2 leakage, see Fig. 2, which shows a conceptual picture of possible leakage during storage of CO 2 .Previous studies have also shown that fault and fracture networks can significantly impact the migration and containment of CO 2 within deep saline aquifers [2][3][4].
The consequences of CO 2 leakage are far-reaching and encompass environmental, economic, and public health impacts.Environmental consequences include the acidification of water bodies, ISSN ONLINE 2783-686X deterioration of soil quality, and negative effects on vegetation and biodiversity [5].The release of large quantities of CO 2 into the atmosphere can exacerbate climate change, contributing to global warming and further disrupting delicate ecosystems [6].Economically, CO 2 leakage can lead to substantial financial losses.Industries investing in CCS projects may face increased costs due to the need for additional monitoring and remediation efforts.Moreover, the potential damage to ecosystems and agricultural lands can have indirect economic consequences, affecting sectors dependent on these resources [5].From a public health perspective, CO 2 leakage can pose significant risks.High concentrations of CO 2 in the air can displace oxygen, leading to asphyxiation.Furthermore, the release of CO 2 may be accompanied by the release of other toxic gases or substances, intensifying health hazards for nearby communities.Therefore, addressing CO 2 leakage is crucial for achieving global climate change mitigation targets and ensuring the long-term viability of CCS as a viable solution.Possible leaks Prevention is essential to prevent the release of significant amounts of greenhouse gases into the atmosphere and to maintain public safety.Implementing robust monitoring systems and adopting stringent regulatory frameworks can help identify and rectify leaks promptly, minimizing their impact on the environment and human health [5].By addressing CO 2 leakage effectively, we can contribute to mitigating climate change, protecting ecosystems, and safeguarding public well-being.In this paper, we investigate possible scenarios for CO 2 leakage with the help of models when it's stored in deep saline aquifer formations.Models are used to investigate the impact of the presence of fault and fractures on CO 2 leakage.Particular case of deep saline aquifers in Lithuanian geology are investigated and findings are presented.
The paper is organized as follows: Firstly, aspects of CO 2 storage in deep saline aquifer and depleted hydrocarbon fields is discussed.Then a discussion on high level risk associated with the CO 2 storage are presented and way to mitigate these risks are also discussed.Next method used in this study for modelling is briefly presented followed by key results and conclusions.

CO2 storage in unconfined aquifers
In an unconfined aquifer, there is no confining layer restricting the vertical movement of fluids.This lack of a confining layer means that there is little resistance to the upward migration of injected substances, such as CO 2 .When CO 2 is introduced into the unconfined aquifer, its buoyancy causes it to tend to move upward within the geological formation.The buoyancy of CO 2 , combined with the absence of a confining layer, makes it prone to vertical migration, posing a risk of escape towards the surface (Fig. 3(a)).
To prevent the undesired upward movement of CO 2 and secure its containment within the targeted aquifer, it is crucial to have a caprock or another form of confining layer.A caprock serves as an impermeable barrier above the aquifer, inhibiting the vertical migration of fluids, including CO 2 .By providing a sealing layer, the caprock helps trap the injected CO 2 within the aquifer, preventing its escape and ensuring the success of carbon capture and storage (CCS) or other subsurface injection processes.

CO2 storage in confined aquifer
In a confined aquifer, there is a confining layer above the aquifer that prevents the CO 2 from migrating upward.CO 2 is injected into the aquifer, and it is trapped below the confining layer.(Fig. 3(b)).The pressure of the injected CO 2 may increase over time, and this may cause the CO 2 to migrate into adjacent rock formations.Therefore, monitoring and management of the CO 2 storage is important to ensure its safety and effectiveness.

CO2 storage in depleted hydrocarbon reservoirs
In a depleted oil or gas reservoir, CO 2 is injected into the formation through a well drilled into the rock.The CO 2 mixes with the residual oil or gas and reduces its viscosity, making it easier to extract.The CO 2 also displaces the oil or gas and occupies the pore space in the rock.The impermeable layers of rock surrounding the reservoir act as a cap, preventing the CO 2 from escaping to the surface.

Risk associated with CO2 sequestration in saline aquifers
Saline aquifers are underground water-bearing formations that contain high concentrations of salt and are unsuitable for human consumption or irrigation.They are considered a promising option for CO 2 storage because they have large storage capacity and are widely distributed.However, there are several specific risks associated with this type of storage, including:

Insufficient data on saline aquifers
Saline aquifers are typically not as well-studied as abandoned oil or gas fields, and therefore acquiring data to characterize these reservoirs can be costlier.In many cases, there may be limited or no existing data on the geology, fluid properties, and other parameters needed to build an accurate reservoir model.To obtain this information, exploration companies may need to conduct additional surveys and measurements, such as seismic surveys, well drilling, and geophysical logging.These methods can be expensive and time-consuming, particularly if the target reservoir is deep or located in a remote area.
Furthermore, saline aquifers may have different geological and hydrological properties than oil and gas reservoirs, requiring different approaches to reservoir characterization and modeling.For example, saline aquifers may be more porous and permeable than conventional oil and gas reservoirs, which can affect fluid flow and migration paths.

Cap rock integrity
In abandoned hydrocarbon fields, the existence of a seal is already demonstrated by the presence of the hydrocarbon reservoir itself.However, in the case of aquifers, it is not always obvious if there is a sealing layer that is preventing the water from escaping.
Analogies to hydrocarbon fields can be useful in identifying potential sealing layers, but they cannot always be relied upon to determine the presence or properties of a cap rock.In order to determine cap rock properties for an aquifer, it may be necessary to conduct tests and use modeling techniques to evaluate the sealing potential of the various layers present in the subsurface.

Geochemical issues
The chemical interactions between injected CO 2 and rocks and the formation water can have significant consequences for the success of CO 2 sequestration.The specific reactions that occur will depend on the unique geochemical conditions of the site, including the mineralogy and petrography of the reservoir and cap rocks.Geochemical experiments using physical samples of the rocks are the best way to predict these reactions accurately.However, it is important to note that some of these reactions can take a very long time to occur, making data collection and simulation challenging.Some potential reactions that can occur include corrosion of the reservoir rock matrix, leading to the compaction or collapse of the formation and the development of cracks and new migration paths through the cap rock.Dissolution of primary minerals and precipitation of secondary minerals may also occur, leading to injection problems if safe pore fluid pressure is likely to be exceeded.
Other potential reactions include the dissolution of components of the cap rock by CO 2 /water mixtures, leading to its collapse or failure as a seal, dehydration of the cap rock by reaction with the dry injected CO 2 , leading to shrinkage and the creation of new pathways through it for CO 2 , and dissolution of CO 2 into the pore fluid and transport out of the structure by natural or induced pore fluid flow.

Pore fluid pressure issues
The most common problems associated with pore fluid pressure are: 1.The fracturing of the cap rock, can occur when the pore fluid pressure in the reservoir exceeds the strength of the cap rock.This can lead to the creation of new fractures or the propagation of existing ones, which can potentially allow the CO 2 to escape from the reservoir.
2. The opening up of pre-existing but previously closed migration paths, can occur when the increased pore fluid pressure in the reservoir causes the cap rock to fail along pre-existing weaknesses such as faults.This can create new pathways for the CO 2 to migrate out of the reservoir and potentially reach the surface.
3. The breaching of the cap rock due to the high gas pressure in the CO 2 accumulation, can occur when the gas pressure exceeds the capillary entry pressure of the cap rock.Capillary entry pressure is the minimum pressure required to force a fluid into a porous material against the forces of surface tension.If the gas pressure exceeds this pressure, the CO 2 can pass through the cap rock and escape from the reservoir [10][11][12].

Method
In Lithuania's Baltic Basin, research is still in its early stages regarding the long-term fate of geological CO 2 storage [7,8].This study focuses on the deep saline aquifers, Syderiai of the Baltic Basin (shown in Fig. 4) and aims to demonstrate the effect of Fault and fracture on CO 2 injection.Lithuanian Basin has a number of deep saline aquifers and depleted hydrocarbon reservoirs in onshore and offshore settings.A detailed ranking of these subsurface storage sites has been analyzed and presented in [7,8].The focus of this paper is on the deep saline aquifer.The largest in terms of storage are two onshore deep saline aquifers Syderiai and Vaskai.In this study we focus on Syderiai aquifer only.High level geological models are built using mechanistic modelling approach whereby average properties are used to make a layer cake model.Geology of the region is represented using simple gaussian distribution.The models are then infused with high permeability faults and fractures to test various leakage scenarios based on the magnitude of fault and fracture permeability.The methodology employed in this study aimed to develop a mechanistic model of the Syderiai deep saline aquifer within the Lithuanian basin, which has been shows to have a significant representative storage volume [7].The model was constructed based on key geological parameters, including average permeability, porosity, net-to-gross ratio (NTG), and aquifer thickness.The primary focus of this research was to address the issue of leakage in the deep saline aquifer resulting from the injection of carbon dioxide (CO 2 ).
To investigate the relationship between CO 2 leakage volume and fracture permeability, a box model was created.The box model comprised of a fracture network and a top seal layer, see Fig. 5.We assumed there was no CO 2 present in the deep saline aquifer when we started simulation.Additionally, Python programming language and relevant libraries were utilized for the implementation of the model and the calculation of leakage volumes from fractures.Simulations are conducted using T-navigator simulation software [13].

Result
The results of our study indicate a clear dependence of CO 2 leakage volume on fracture permeability.An initial observation reveals a positive correlation, as the leakage volume of CO 2 tends to increase with higher levels of fracture permeability.This finding aligns with the expectation that greater permeability provides enhanced pathways for fluid movement, resulting in a higher potential for CO 2 migration.As fracture permeability continues to increase, the sealing effects become more pronounced, leading to a subsequent decrease in CO 2 leakage volume.Fig. 5, shows simulation results on a synthetic case where faults and fractures are present and CO 2 is injected and it can be seen that CO 2 migration is not fast enough to leak through the fracture network due to the distance between injection wells and the fractures present in the system.

Conclusions
This paper tests the leakage volumes using different fracture configurations and fracture permeability values.Optimal conditions for minimizing leakage were identified.Investigations were made for the temporal dynamics of CO 2 leakage volumes.Analysis was carried out to look at factors such as cap rock degradation through geochemical reactions and pressure differentials, to understand how the leakage volume evolved over time.

Fig. 1 .
Fig. 1. Figure showing suitable storage regions of the world for CO2 storage, modified from [9]

Fig. 5 .
a) Permeability distribution grid block for 1000 md fracture, b) soluble CO2 in water for 1000 md fracture after 100 year

Shankar
Lal Dangi received B.Tech.degree in petroleum engineering from Rajasthan Technical University, Kota, Rajasthan, India, in 2018.He has technical knowledge in the oil and gas industry.His area of research includes hydrogen and CO2 storage, AI/ML, numerical modelling.Dr. Shruti Malik earned her Ph.D. degree from Indian Institute of Technology, Roorkee, India.She is working as a post-doctoral researcher in the Department of Mathematical Modelling, Kaunas University of Technology (KTU), Lithuania, supported by a research grant from Research Council of Lithuania.Her work is focused on blending the digital rock physics with AI & ML techniques to assess the impact of CO2 & H2 storage on the subsurface reservoirs.Pijus Makauskas is a Ph.D. researcher at the department of Mathematical Modelling in Faculty of Mathematics and Natural sciences at Kaunas University of Technology.His area of research includes subsurface modelling, Machine learning and AI, Geothermal, CO2 and Hydrogen storage, numerical modelling of subsurface flows and reservoir simulation.Viltė Karaliūtė is a bachelor's student at Department of Mathematics and faculty of Natural Sciences at Kaunas University of Technology, Kaunas, Lithuania.Dr. Ravi Sharma received a master's degree in applied Geophysics from the University of Roorkee in 1999.He received his MS and Ph.D. in Petroleum Engineering from Colorado School of Mines, USA, in 2015.He has extensive work experience in various roles with the hydrocarbon energy industry.His research interest includes experimental and modelling methods in rock physics and petrophysics for storage, flow, and the associated elastic and geo-mechanical property determination, integrated reservoir (convention and unconventional) characterization, ML & AI applications in geosciences and petroleum engineering.Dr. Sharma is an active member of AGU, IEEE, SEG, SPE, AAPG, SPG, and SPWLA, an Associate Editor of the Journal of Applied Geophysics and Geohorizons, and a guest editor of Frontiers in Earth science.Dr. Mayur Pal received Ph.D. degree in computational engineering from Swansea University, Wales, UK in 2007.After finishing his Ph.D. Mayur Pal worked at Shell International Exploration and Production B.V. Research Centre in Rijswijk followed by Maersk Oil Research and Technology Centre.He also held positions as head of enhanced oil recovery team and head of asset in North Oil Company, Qatar.He is currently Prof. at Department of Mathematical Modelling at KTU, Kaunas, Lithuania.His research interest includes, subsurface flows, multiscale modelling, discrete fracture network modelling, enhanced oil recovery, CCUS, data science and machine learning applications to solve problems in engineering and sciences.