Secure subsurface storage for future energy systems


Secure subsurface storage for future energy systems
Convener: Johannes Miocic | Co-conveners: Benjamin Emmel, Niklas Heinemann, Anja Sundal, Qi Li, Suzanne Hangx, Christopher YeatesECSECS, Katriona Edlmann
vPICO presentations
| Tue, 27 Apr, 09:00–12:30 (CEST)
Public information:
Please read the session materials for information on video chat rooms for the break out displays.

vPICO presentations: Tue, 27 Apr

Chairpersons: Johannes Miocic, Anja Sundal, Benjamin Emmel
Yuting Zhang, Samuel Krevor, and Chris Jackson

To limit global warming to well below 2oC, integrated assessment models have projected that gigaton-per-year-scale carbon capture and storage is needed by c. 2050. These scenarios are unconstrained by limiting growth rates or historical data due to the limited existing deployment of the technology. A new approach using logistic growth models identifies a coupling between storage resource base (pore space underground) and minimum growth rates necessary to meet global climate change mitigation targets (Zahasky & Krevor, 2020). However, viable growth trajectories consistent with carbon storage targets remain unexplored at the regional level. Here, we show the application of logistic modelling constrained by climate change targets and assessed storage resources for the European Union (EU), the United Kingdom (UK), and Norway. This allows us to identify plausible growth trajectories of CCS development and the associated discovered storage resource base requirement in these regions. We find that the EU storage resource base is sufficient to meet storage targets of 80 MtCO2/year and 92 MtCO2/year suggested in the European Commission climate change mitigation strategy to 2050, ‘A Clean Planet for All’. However, the more ambitious goals of 298 MtCO2/year and 330 MtCO2/year are likely to require additional storage resources based predominantly in the North Sea. Results for the UK indicate that all anticipated storage targets to achieve net-zero economy are achievable, requiring no more than 42 Gt of the storage resource base for the most ambitious target. Furthermore, the UK and the Norwegian North Sea may be able to serve as a regional CO2 storage hub. There are sufficient storage resources to support combined storage targets from the EU and the UK. The tools used here demonstrate a practical approach for regional stakeholders to monitor carbon storage progress towards future stated carbon abatements goals, as well as to evaluate future storage resource needs.

Zahasky, C., & Krevor, S. (2020). Global geologic carbon storage requirements of climate change mitigation scenarios. Energy & Environmental Science.

How to cite: Zhang, Y., Krevor, S., and Jackson, C.: Geologic carbon storage resource requirements of climate change mitigation targets in Europe, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-10327,, 2021.

Natalie Nakaten, Thomas Kempka, and Michael Kühn

The underlying study addresses the ambitious German Federal Government’s objectives for the transition to a new energy era by proposing the implementation of a low-carbon energy system, improving the electricity grid as well as solar and wind power initiatives. Hereby, the “Power-to-Gas-to-Power” (PGP) approach combines the storage of excess energy from renewable power sources in the form of synthetic hydrocarbons, and their subsequent utilisation in a closed cycle to produce low-carbon electricity [1]. Based on the availability of two adjacent subsurface storage formations for CO2 and CH4 [2], hydrogen gained from excess solar and/or wind power is transformed into methane by means of CO2 captured on-site. When required, electricity is regained in a combined cycle plant by burning the CH4, with CO2 cycled in a closed loop.

In a show case study for the two German cities of Potsdam and Brandenburg, the PGP process chain was quantified to a total process efficiency of about 26%, exhibiting costs of 20 eurocent/kWh [2]. These previous assessments referring to energy production and storage technologies economics of the year 2012, have shown that PGP is generally economically competitive compared to conventional storage technologies [2]. Further results show that PGP can compete with global cost bandwidths of hydropower and compressed air storage as well as with upper limit COEs for solar thermal power and photovoltaic. However, PGP is not competitive compared to fossil fuel-based as well as onshore/offshore wind-based energy production [3]. However, cost trends related to energy production and storage technologies significantly correlate with fuel and commodity prices, CO2 emission charges as well as technology improvements that have been rapidly changing in the past few years. Thus, the purpose of the present study is to update the previously published PGP costs and elaborate a general overview on the current status of PGP on the global energy market.

[1] Kühn, M. (2013): System and method for ecologically generating and storing electricity. - Patent WO 2013156611 A1:

[2] Streibel, M., Nakaten, N. C., Kempka, T., Kühn, M. (2013): Analysis of an Integrated Carbon Cycle for Storage of renewables. - Energy Procedia, 40, pp. 202-211. DOI:

[3] Kühn, M., Nakaten, N., Kempka, T. (2020): Geological storage capacity for green excess energy readily available in Germany. - Advances in Geosciences, 54, 173-178. DOI:

How to cite: Nakaten, N., Kempka, T., and Kühn, M.: Power-to-Gas-to-Power is a competitive excess energy subsurface storage technology, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-2975,, 2021.

Alan Bischoff, Ludmila Adam, David Dempsey, Andrew Nicol, Mac Beggs, Michael C. Rowe, Kate Bromfield, Matthew Stott, and Marlene Villeneuve

Novel technologies to store hydrogen in geological formations can substantially enhance New Zealand’s renewable energy market and help mitigate climate change impacts. New Zealand already supplies about 80% of its electricity demands from renewable sources, mostly geothermal, hydro and wind power. However, over 60% of the country’s net energy consumption still comes from fossil fuels. In New Zealand, extensive production and large-volume (>50,000,000 Nm3) storage of green hydrogen will be essential to buffer diurnal and seasonal shortage of hydro and wind power generation in a future energy mix dominated by renewable sources. Geological storage, technology in use since the 1970’s, is currently considered the best large-scale option for hydrogen storage globally.

Here we present preliminary results of an ongoing study into the feasibility of storing hydrogen in sedimentary and volcanic rocks across New Zealand. The country’s varied geology and diverse cultural communities provide a unique setting to evaluate the technical capacity, socio-environmental aspirations, and costs-benefits of hydrogen geo-storage for future domestic and export markets. We draw our investigation upon a substantial legacy dataset of petroleum exploration drillholes and seismic reflection surveys coupled with information from sedimentary and volcanic outcrops to determine the most suitable geological formations for hosting large-volumes of hydrogen nationwide. Four possible types of hydrogen geo-storage are considered: (i) construction of artificial rock caves, (ii) injection of hydrogen into sedimentary rocks and aquifers, (iii) utilisation of depleted natural oil and gas reservoirs and infrastructure; and (iv) hydrogen storage in highly porous and permeable volcanic rocks, the last of which would be a world first.

New Zealand has an extensive installed petroleum infrastructure, including 2,500 km of high-pressure gas pipelines and 17,960 km of gas distribution network to support the development of new hydrogen energy enterprises. Multiple depleted or depleting petroleum fields (e.g. Ahuroa, Kapuni and Maui) contain excellent reservoirs and efficient seal rocks confined in large (>25 km2) geological structures that offer scope for hydrogen storage. Porosity and permeability in commercial reservoirs vary from 5 to 25% and often up to several thousand millidarcys (mD), respectively, with high values of up to 9900 mD reported in sandstones of the Maui field. Studies in volcanic reservoirs on Banks Peninsula, Oamaru and offshore Taranaki Basin demonstrate that large sections of volcanoes (up to 1 km3) frequently have porosities of ca 50% and permeabilities above 100 mD, which may provide opportunities for storing hydrogen at relatively shallow (ca 100 m) depths.

Further technical assessment is ongoing to determine microbiological activity, chemical stability of rock targets, and geological modelling in hydrogen-rich reservoirs. This technical assessment will be complemented by community consultation to develop pathways for acceptance of hydrogen geo-storage in the country. Mātauranga Māori (native indigenous knowledge) has real potential to guide renewable energy investments towards a long-term vision that prioritises intergenerational well-being and prosperity for the wider New Zealand society. This convergence of thinking, integrating scientific knowledge, industry aspirations, and societal necessities will provide a novel approach for sustainable growth of the hydrogen industry in New Zealand and abroad.

How to cite: Bischoff, A., Adam, L., Dempsey, D., Nicol, A., Beggs, M., Rowe, M. C., Bromfield, K., Stott, M., and Villeneuve, M.: Underground hydrogen storage in sedimentary and volcanic rock reservoirs: Foundational research and future challenges for New Zealand, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-3496,, 2021.

Wolfgang Weinzierl, Merlin Ganzer, Dennis Rippe, Stefan Lüth, and Cornelia Schmidt-Hattenberger

Seismic and geoelectric/electro-magnetic methods are used as complementary tools for the identification of fluid/gas effects in underground storage and production scenarios. Both methods generally have very different resolution. Seismic tends to be acquired by much more dense geometrical layouts and the geoelectric or electro-magnetic acquisition being a potential field method shows information integrated over spatial distances. These inherent scale and design dependent differences require spatial tuning in joint inversion approaches and careful matching in independent interpretations of both methods. We present results matching seismic and electrical resistivity tomography (ERT) results from two repeat surveys acquired during CO2 storage operations at the Ketzin pilot site in Germany. The approach is based on data acquired in 2009 and 2012, at different stages of total injected CO2 volume. Volumes of injected mass are obtained from the averaged acoustic impedance change (seismic) in the vicinity of the injection well and compared to volumes inferred from the ERT cross-well acquisition. The results are compared radially with increasing distances from the injection location. Seismically derived masses of injected CO2 are used as a benchmark for a threshold-driven workflow analyzing the electric resistivity model. The cross-well ERT results have been obtained in a quadrant of the seismic survey acquisitions. Assuming radial symmetry for the ERT makes it possible to compare individual mass balances in the near-vicinity of the injection well. Archie's equation is used to obtain saturations from the tomographic geoelectric models. The sensitivities of parameters relevant in determining the mass of injected CO2 is analyzed. Variations in saturation exponent n, baseline resistivity R0, and porosity Φ enable specifying applicable ranges of the parameters and determining the investigation radii compared to the seismic derived benchmark. This is done for individual threshold levels for saturations derived from the ERT field data. Seismically and ERT obtained masses match comparatively well and subtle variations of the sensitive parameters are capable in explaining differences for individual investigation volumes. Applicable investigation radii lie between 20-100 m. A 10% in- or decrease of the mean parameters is able to match the seismic derived mass in this range. Above a threshold of 10% for the saturations, the derived mass decreases more rapidly showing a larger deviation from the seismic derived mass. Both methods underestimate the total injected mass. This is not surprising as there are both fluid related processes and structural heterogeneities not accounted for in either. Results of surface-downhole measurements support the findings and show applicability of the developed approach. The threshold-based approach may support the monitoring concept of a CO2 storage site and provides a basis for quantitative evaluation of its containment, as investigated in the frame of the EU project SECURe.


How to cite: Weinzierl, W., Ganzer, M., Rippe, D., Lüth, S., and Schmidt-Hattenberger, C.: Mass Balance Threshold Matching of Geoelectric and Seismic Data – A case study from Ketzin, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-13964,, 2021.

Peder Eliasson, Anouar Romdhane, Romina Gehrmann, Joonsang Park, and Hanbo Chen

Geophysical monitoring is essential for CO2 storage projects and mandatory Measurements, Monitoring, and Verification (MMV) plans. Various geophysical methods can be used to estimate, from measured data, selected properties (e.g. velocity, density, and resistivity) of the subsurface. Accurate knowledge of those properties in turn makes it possible to quantify important reservoir parameters such as CO2 saturation and pore pressure, giving the operator valuable information for predictable CO2 injection and storage.

A combination of seismic and non-seismic technologies is usually part of the CO2 monitoring plan throughout the project lifecycle (pre-injection, injection, and post-injection phases). The EM4CO2 project investigates whether marine Controlled Source Electro-Magnetics (CSEM) can be a cost-efficient complement to seismic in such monitoring plans. The main focus of the project is on demonstrating sufficient sensitivity of the technology and on further developing CSEM for time-lapse applications in areas with potentially interfering infrastructure. While improved data processing, imaging, and inversion techniques is often the subject of large research efforts, less attention is usually paid to developing better survey design strategies (rather relying on conventional methods). The work described here relates to the development and demonstration of new strategies for optimization of 4D survey design. Such optimization could decrease the large costs associated with acquisition of geophysical data (in this case CSEM), which could otherwise be a hurdle when proposing large-scale CO2 storage as a means to mitigate climate change.

Conceptually, survey design aims at selecting the data acquisition that optimally resolves the subsurface model parameters of interest while maintaining the cost as low as possible. In other words, it consists of finding the best trade-off between data value and data collection cost. In this work, the CSEM survey design strategy is based on the analysis of the eigenvalue spectrum of the data misfit Hessian. A Python notebook was implemented for interactive prototyping and testing of various optimization strategies. A few examples of survey design are given for a model of the Sleipner storage site, showing how well a given regular survey can be decimated without significant loss of information. The main part of the work is, however, focused on survey optimization for potential CO2 storage in the Smeaheia formation at about 1000 m depth below the sea surface, offshore Norway. This study shows how to determine the most valuable electric field components, most important frequencies, and source/receiver positions to use for reliable monitoring of a target region of choice. Initial results indicate that measuring the vertical component in addition to the horizontal electric field adds relevant information, and that lower frequencies (0.1-0.5 Hz) carry more information than higher (0.75-5 Hz) about the target depth. It is also clear that the method identifies sources and receivers distributed mainly above the target region as the most important.

How to cite: Eliasson, P., Romdhane, A., Gehrmann, R., Park, J., and Chen, H.: Optimal CSEM survey design for CO2 monitoring at Smeaheia offshore Norway, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-14804,, 2021.

Eike Marie Thaysen, Sean McMahon, Gion J. Strobel, Ian B. Butler, Bryne Ngwenya, Niklas Heinemann, Mark Wilkinson, Aliakbar Hassanpouryouzband, Christopher I. McDermott, and Katriona Edlmann

Zero carbon energy generation from renewable sources can reduce climate change by mitigating carbon emissions. A major challenge of renewable energy generation is the imbalance between supply and demand. Subsurface hydrogen storage in porous media is suggested as a large-scale and economic means to overcome these energy imbalances. However, hydrogen is an electron donor for many subsurface microbial processes which may have important implications for hydrogen recovery, gas injectivity and corrosion.

We reviewed the state-of-the-art literature on the controls on the three major hydrogen-consuming processes in the subsurface: methanogenesis, homoacetogenesis, and sulphate reduction, as a basis to develop a hydrogen storage site selection tool. Sites with low temperature (<70°C), zero to moderate salinity (0-0.6 M) and close to neutral pH values provide the best growth conditions for most of the hydrogen-consuming methanogens, homoacetogens and sulphate reducers. Conversely, fewer strains are adapted to more extreme conditions (high temperature and pressure, increased salinity and acidic or alkaline pH), favouring hydrogen storage in these sites.

Testing our tool on 42 depleted gas and oil fields of the British and Norwegian North Sea and the Irish Sea showed that seven of the fields may be considered sterile with respect to hydrogen-consuming microorganisms due to either temperatures >122 °C or salinities >5 M NaCl. Only three fields can sustain all of the major hydrogen-consuming processes, due to either temperature, salinity or pressure constraints in the remaining fields. We calculated a potential microbial growth in the order of 1-17*107 cells ml-1 for these fields. The associated hydrogen consumption is negligible to small (<0.01-3.2 % of the stored hydrogen). Our results will advance a faster transition to a lower carbon energy supply by helping inform decisions about where hydrogen can be stored in the future.

How to cite: Thaysen, E. M., McMahon, S., Strobel, G. J., Butler, I. B., Ngwenya, B., Heinemann, N., Wilkinson, M., Hassanpouryouzband, A., McDermott, C. I., and Edlmann, K.: Site Selection Tool for Hydrogen Storage in Porous Media, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-8883,, 2021.

Christropher Yeates, Cornelia Schmidt-Hattenberger, and David Bruhn

Designing low-cost infrastructure networks for transport of hydrogen represents a key step in the adoption and penetration of hydrogen technology in a low-carbon energy future.

For hydrogen distribution, network design amounts to creating pipeline systems in which supply is matched to demand through a transportation system that respects multiple constraints (technical, social, environmental) and minimizes cost. This can equate to recycling pre-existing pipelines or building new ones, but also involves the placement of carefully chosen supply nodes.

In a multi-level distribution network, supply nodes may assume many roles from large-capacity geological storage facilities, to local relay nodes addressing the end customers.

Finding minimum-cost pipeline network designs in which supply node locations are already chosen is itself a well-studied combinatorial optimization problem (Cayley’s formula predicts  possible spanning trees for  nodes) for which multiple heuristic and exact methods are known [1].

Allowing the supply node to take any position within the network renders the problem significantly more complex as the minimum-cost network topology (the specific connections to between nodes) will potentially change for each new supply node position.

We propose a heuristic algorithm that finds good solutions in a reasonable amount of time based on a back-and-forth between:

- Repositioning optimally the supply node, while maintaining the same connections to the supply node (reduces cost)

- Optimizing the network topology, assuming a fixed supply node position (also reduces cost)

The algorithm stops once no further cost reductions for the network design are found. The algorithm output is found to be sensitive to the initial guess of the supply node position, the initial guess of the connections to the supply node, and to the specific “path” of the back-and-forth taken to reach the given local minimum. As such, a good initial guess for a “housing polygon”, i.e. the nodes to which supply node is directly connected to, is crucial in finding the minimum-cost solution, and in the shortest time possible. We attempt to make this initial guess with a machine learning algorithm, with features describing the geometrical distribution of node capacity, as well as elementary network concepts.

Finally, an example is provided on a model hydrogen network comprised of typical elements and realistic cost-functions.


[1]: Brimberg J, Hansen P, Lin K, Mladenovi N, Breton M, Brimberg, J (2003) An oil pipeline design problem. Operations Research, 51(2):228–239.

How to cite: Yeates, C., Schmidt-Hattenberger, C., and Bruhn, D.: A method for simultaneous minimal-cost supply node location and network design in pipelined infrastructure., EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-16457,, 2021.

Dario Sciandra, Víctor Vilarrasa, Iman Rahimzadeh Kivi, Roman Makhnenko, Christophe Nussbaum, and Dorothee Rebscher

We are performing a series of coupled hydro-mechanical (HM) simulations to model CO2 flow through Opalinus Clay at the Mont Terri rock laboratory in the CO2 Long-term Periodic Injection Experiment (CO2LPIE). CO2LPIE aims at inter-disciplinary investigations of the caprock sealing capacity in geologic CO2 storage in a highly monitored environment at the underground laboratory scale. Numerical modeling allows us to gain knowledge on the dynamic processes resulting from CO2 periodic injection and to assist the experimental design. The cyclic injection parameters (i.e., the period and the amplitude) have to be optimized for the field experiment and therefore different values are taken into account. Opalinus Clay is a claystone with nanoDarcy permeability that contains well developed bedding planes responsible for its anisotropic HM behavior. The hydraulic anisotropy is defined by a permeability parallel to the bedding planes being three times the one perpendicular to it. Additionally, the drained Young’s modulus is measured to be 1.7 GPa parallel and 2.1 GPa perpendicular to bedding. Excavation reports by swisstopo document a SSE-dip of 45° for the bedding planes at the experiment location. CO2 injection generates a mean overpressure of 1 MPa into the brine that propagates into the formation. The differential pressure between CO2 and formation water, i.e., capillary pressure, is lower than the entry pressure and thus, CO2 diffuses through the pores but does not advect in free phase. The liquid overpressure distribution is distorted by the hydraulic anisotropy, preferentially advancing along the bedding planes, as the associated permeability is higher than the one perpendicular to the bedding. The pore pressure buildup induces a poromechanical stress increase and an expansion of the rock that leads to a permeability enhancement of up to two orders of magnitude. The cyclic stimulation propagates trough the domain faster and with a lag time and an attenuation, both of which increase with distance from the source with, their values being dependent on permeability, porosity and stiffness of the rock. As a result of the model orthotropy, the attenuation and the lag time change with direction, i.e. they are higher in the direction perpendicular to the bedding and lower in the direction parallel to the bedding. Given the very low permeability of Opalinus Clay, the overpressure generated requires a long time to diffuse into the rock. Furthermore, the amplitude attenuation dissipates quite rapidly, so monitoring wells should be placed as close to the injection well as possible. The study of amplitude attenuation and time lag is necessary to determine how they can be utilized to evaluate the evolution of the HM properties as the rock is altered by the acidic nature of CO2-brine mixture Comparison between field data and numerical simulations will be a useful asset to fill the gap.

How to cite: Sciandra, D., Vilarrasa, V., Rahimzadeh Kivi, I., Makhnenko, R., Nussbaum, C., and Rebscher, D.: Coupled HM modeling assists in designing CO2 long-term periodic injection experiment (CO2LPIE) in Mont Terri rock laboratory, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-8982,, 2021.

Bastien Dupuy, Benjamin Emmel, and Simone Zonetti

More than 750 wildcat wells have been drilled in the Norwegian North Sea since 1966. Some of these wells could pose a risk for the environment, climate, and future H2 and CO2 storage projects by being preferred leakage paths for subsurface- and stored- gases (e.g., CH4, CO2 and/or H2). To ensure well integrity, these wells were secured by cement framing the well casing, and by building cement plugs at crucial positions in the well path before abandoning the well. However, in an early stage of exploration the geology of the subsurface was relatively uncertain, and the requirements for plug placing and how to abandon a well were not established and regulated. We analysed data relevant for the quality of a Plugging and Abandonment (P&A) work done on old exploration wells (1979 to 2003) from the Troll gas and oil field in the Norwegian North Sea. The data were extracted from public available well completion reports and the webpage of the Norwegian Petroleum Directorate. The dataset was analysed regarding their availability, plausibility and evaluated towards the present P&A regulations and geological knowledge for offshore Norway. Based on 12 criteria including reporting to the authorities, volumetric assessment of used cement quantities, position and length of the plugs in relation to reservoir- cap-rocks petrophysical conditions, and verification of the cementing job, a final P&A ranking of 31 exploration wells was established.

Parts of this data were used to build realistic numerical models of P&A'ed well to simulate electromagnetic responses using the finite element software COMSOL Multiphysics. Taking advantage of a dedicated implementation of low frequency ElectroMagnetics (EM), including effective formulations for thin electrical layers, it was possible to study the response of well components to external EM fields, both for the purpose of well detection and well monitoring. Results from the numerical models can be used as benchmark models in a realistic field scale well integrity monitoring approach.

In our presentation we will show results from the TOPHOLE project including realistic field distributions for different representative well configurations, examples of well detection and monitoring signals, and the ranking evaluation results.

Acknowledgments: This work is performed with support from the Research Council of Norway (TOPHOLE project Petromaks2-KPN 295132) and the NCCS Centre (NFR project number 257579/E20).

How to cite: Dupuy, B., Emmel, B., and Zonetti, S.: Evaluating the well integrity of old exploration wells as a risk factor for future storage projects – an example from the Troll field in the Norwegian North Sea, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-10856,, 2021.

Logan Brunner, Bogdan Orlic, Al Moghadam, and Jan ter Heege

With increasing CO2 emissions from fossil fuels alongside the push for more sustainable energy systems, the subsurface as a valuable asset for various sustainable energy applications has gained interest. Two primary drawbacks for the use of assets and infrastructure in transition to sustainable energy are (1) the large costs associated with new subsurface infrastructure (e.g. wells, platforms and pipelines), and (2) the detailed integrity assessment of existing infrastructure required for reuse. The concept of reusing existing infrastructure is particularly attractive as it has the potential to facilitate cost-efficient access to the subsurface for sustainable energy applications. Wells are a crucial component for reuse since they generally have a long history of mechanical loads and exposure to formation fluids prior to reuse. A common threat to well integrity is the development of fractures in the cement surrounding the well, or microannuli, at the casing-cement or cement-formation interface that may promote upward migration of fluids. This migration is often difficult to assess with conventional logs but may enable fluid communication from the storage reservoir to the overburden. Such communication is a threat for safe and efficient subsurface energy or CO2 storage.

A methodology has been developed to model and assess the risk of well microannuli over the entire lifetime of a well (i.e. the drilling, completion, operation, abandonment, and post-abandonment phases). The basis of the assessment is a numerical model (DIANA finite element tools), in which a cross-section of the well, cement, and geology is modelled at a given depth. Deterministic parameters are incorporated to enable sensitivity analyses of results. Stochastic variables represent parameters that are uncertain but can be incorporated using a distribution of values, which are sampled using the Monte Carlo method. Probabilities of the microannulus aperture are analyzed using a Bayesian belief network approach. The results vary depending on the choice of values for the deterministic parameters, based on potential strategies of energy operators that can be modified to achieve a proper mix of risk-reduction and financial costs.

The methodology has been evaluated in the SECURe project, where it was applied to a Polish shale gas well and a (hypothetical) CO2 injection well in the offshore Netherlands, and in the REX-CO2 project, where it has been integrated into a tool designed to screen wells for suitability of reuse for CO2 storage. As the approach can handle different operations and fluids, its potential exceeds these use cases. Further application in subsurface energy projects can help in addressing well integrity issues and in advising and decision-making for potential reuse of wells.

This work is part of two projects, SECURe and REX-CO2, which have received funding from the European Union’s Horizon 2020 (grant agreement number 764531) and the ERA NET Cofund ACT (project number 299681), with financial contributions made from ADEME (FR); RVO (NL); Gassnova and RCN (NO); UEFISCDI (RO); BEIS, NERC, and EPSRC (UK); and US-DOE (USA). The contents of this publication reflect only the author’s view and do not necessarily reflect the opinion of the funding agencies.

How to cite: Brunner, L., Orlic, B., Moghadam, A., and ter Heege, J.: Assessing wells for reuse: a probabilistic approach to well integrity using a numerical model and Bayesian belief network, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-8219,, 2021.

Frédérique Rossillon, Vivien Esnault, and Eléonore Roguet

The European ERA-ACT REX-CO2 project aims to develop a tool to assess the compatibility of existing wells for CO2 sequestration. Indeed, the reuse of existing wells for storage in depleted reservoirs is an attractive medium-term solution for geological sequestration of CO2.

The mechanical integrity of the wells is a critical point in term of storage durability. A variety of flow paths that could lead to a migration of the stored CO2 to surrounding geological layers or the surface have been identified. Among those, operational feedback shows that a likely leakage route are along the interfaces of the well structure. These potential flow path can be generated by the debonding of the cement sheath from the steel casing or surrounding rocks. One ambition of REX-CO2 project is to ultimately predict the wells integrity as a function of the variations in undergone mechanical loadings. In order to reach this objective, it appears relevant to characterize the mechanical strength of these interfaces.

IFPEN work consists in carrying out mechanical tests on bimaterial specimens to study cement/steel or cement/rock interfaces in different configurations representative of downhole conditions. Two types of tests are performed allowing the characterization of the bonding in two different stress states: the pull-out test and the push-out test. Combined with simulations, these results can either be used directly or feed a damage interface models. The authors are currently running an extensive parametric study, to explore the impact of various downhole conditions, such as pressure or environment, and to CO2 exposure.

The presentation focuses on the mechanical testing methodology. The pull-out test is a tension test performed on a cylinder made of two materials. In this case, the stress pattern is obvious, the interface is loaded in tension. This test is difficult to carry out perfectly due to the weak and scattered behaviour in tension, and finding proper gluing solutions. The push-out test, commonly used in the literature, consists in pushing a plug (steel or rock) into a cement ring to measure the bonding resistance. Despite other push-out tests, a surrounding steel ring ensures the cement confinement and avoid radial cracks. FEM analysis shows stress pattern is more complex than a pure shear at the interface, as often assumed in the literature. An analysis of loading curves enables to understand the different damage stages of the interfaces.

How to cite: Rossillon, F., Esnault, V., and Roguet, E.: Experimental study of cemented interfaces for applications in CO2 storage re-using depleted oil and gas reservoirs, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-12401,, 2021.

Meiheriayi Mutailipu and Qiang Yao

Countries in the world now are trying best to conserve energy and reduce emissions, at the meantime, efficient actions are taken to tackle with global warming. Emission reduction of main greenhouse gas CO2 can be achieved efficiently via CO2 geological storage, in terms of CO2 saline aquifer storage. The gas–liquid–solid interactions such as interfacial tension determines the injectability, sealing capacity and safety of this scheme. In order to better predict the storage capacity to evaluate the storage safety, this work aims at carrying out the numercial modelling work on the interfacial tension of CO2–water/brine binary system under the reservoir temperatures and pressures condition. 

A linear relationship between the increase in average interfacial tension and molality was observed and it is a function of the ionic type. Finally, modified empirical correlations based on experimental data in the literature, using only few regression coefficients with a relatively low error for most of the experimental data in the literature, were presented to estimate the CO2–water/brinebinary system interfacial tensions under wide range of temperatures, pressures, and the ionic strength.



How to cite: Mutailipu, M. and Yao, Q.: Prediction of the interficial tension for CO2-Water/Brine binary system based on the linear fitting method, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-533,, 2021.

Kaisaerjiang Aihemaiti, Jianmei Cheng, Shiyi Wang, Ruirui Zhao, and Xiaoli Ma

Abstract: CO2 storage in saline aquifers is one of the most effective ways of geological carbon sequestration. In order to better understand brine-CO2-rock interaction in carbonate reservoirs, 4 series of autoclave experiments with the carbonate rock powder samples with injection of super critical CO2 have been performed. Two core samples were collected from the TC1well at the depth of 4030m (Lianglitage Formation) and 5100m (Qiulitage Formation), and another two samples from corresponding formation  and with varing mineral content were collected from the Yijianfang outcrop and Xiaoerbulake outcrop in Tazhong-Uplift, Tarim Basin, China. The experimental conditions simulate the environment of the reservoir around 4000m depth at the Tazhong Uplift with 25Mpa and 120 degree, where the brine water is CaCl2 type with TDS equal to 135g/l. The FESEM,EDS, XRD, ICP-OES analysis have been performed to examine the mineral chemical composition, morphology and water solution change. The results show that, in all cases after the injection of CO2, with CO2 dissolution, pH shows a decrease at the beginning days of the experiments and start to rise, becomes stable at the end of the experiment. Where as, with the dissolution of the minerals results in continuous increase in electrical conductivity. The SEM analysis demonstrates the dissolution of the calcite and dolomite resulted in a rough surface structure and the sharp edges of calcite and dolomite are dissolved. Also, it is able to observe the formations of new micropores and formation of secondary minerals such as ankerite. In the fluid analysis, Ca2+ is the dominant dissolved cation and originated from calcite and dolomite dissolution. The concentration of Ca2+will first increase sharply and then decreases, whereas concentration of Mg2+ will increase slowly, which means calcite dissolution take places faster than dolomite dissolution. Numerical modeling has been applied to validate the experimental observations with corrected reaction rate. These results can be used for numerical calculation of mineral trapping over long period. This study is helpful for implementation of carbon sequestration plan in Tarim Basin, China.

How to cite: Aihemaiti, K., Cheng, J., Wang, S., Zhao, R., and Ma, X.: Experimental study on brine-CO2-rock interaction in carbonate formations of Tazhong-Uplift, Tarim Basin China, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-7008,, 2021.

Stéphane Polteau, Farhana Huq, Craig Smalley, Viktoriya Yarushina, Ingar Johansen, Christian Schöpke, Line Øvrebø, and Ebbe Hartz

Routine measurements of formation pressure while drilling reservoirs can indicate the presence of internal barriers to vertical fluid movement when there is a sudden shift in the pressure data. However, pinpointing the location of a barrier is often not possible since the density of pressure measurements is low and irregular. The aim of this contribution is to show how the Strontium isotopic system can help characterize the fluid connectivity and pinpoint the precise location of low permeability barriers in reservoir units and sedimentary sequences. As an example, we use a 25 m thick interval within the Middle Jurassic Hugin reservoir unit of the Langfjellet oil discovery on the Norwegian Continental Shelf. The location of the barrier is constrained by the upper and lower pressure measurements and could correspond to any of the several layers of silt, shale or coal layers in this interval. In this study, we collected every 2-4 m a total of 40 samples from a 110 m long cored section of a technical side-track well over the available. Each sample was prepared and analyzed using the SrRSA method (Strontium Residual Salt Analysis), which measures the 87Sr/86Sr ratio in salt residue that precipitated in the pore space after the core dried out. The 87Sr/86Sr is a natural tracer because the ratio is not affected by mass fractionation. The 87Sr/86Sr in rocks is mostly acquired by water-rock interactions during diagenesis and evolves through mixing and equilibration of different water bodies, unless low-permeability barriers prevent equilibration. Therefore, the SrRSA patterns observed in the well represent a 1D snapshot of the fluid dynamics at the time of oil filling, which is a frozen image of competing equilibrium vs disequilibrium conditions. The SrRSA data follow a smooth trend of content values at 0.713 and display a sudden jump to lighter 0.709 values near the top of the 25 m thick interval that suggests the presence of a potential barrier. The lithological core log shows that the SrRSA step change corresponds to a coal-shale unit, which is interpreted to represent the barrier. The SrRSA data further demonstrate the reservoir unit at Langfjellet does not contain any other barriers to fluid flow, since pressure equilibration could have masked a possible compartmentalization. This study shows that the SrRSA method is a powerful tool that should be routinely applied for the characterization of fluid connectivity of storage units.

How to cite: Polteau, S., Huq, F., Smalley, C., Yarushina, V., Johansen, I., Schöpke, C., Øvrebø, L., and Hartz, E.: Characterization of Fluid Connectivity in Reservoirs using Strontium Isotopes, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-12191,, 2021.

Haimeng Shen, Xiaying Li, and Qi Li

Velocity anisotropy is particularly important in field applications of seismic monitoring or exploration [1]. We investigate the stress-dependent P-wave velocity anisotropy of sandstones with triaxial experiments and PFC based numerical simulation [2-3]. The sandstone sample was taken from the lower Shaximiao formation, Sichuan Basin, China [4]. The evolution of anisotropy is discussed with the ellipse least-squares fitting method. The results show that the P-wave velocity is affected by both the bedding plane and loading conditions. As confining pressure increases, the anisotropy magnitude decreases for each sample. The direction of anisotropy is along with the direction of the bedding plane. Under deviator loading, the anisotropy is strengthened for the sample with bedding parallel to the maximum principal stress. The direction of anisotropy reversal occurs in the sample with bedding normal to the maximum principal stress. And the anisotropy magnitude of that sample is reduced firstly and then improved. The P-wave velocity anisotropy is originated from preferred mineral orientation and aligned cracks in these samples. The stress has little effect on the mineral orientation. The evolution of P-wave velocity anisotropy is related to closing and reopening of microcracks.


Keywords: Velocity anisotropy; Anisotropy reversal; Triaxial experiment; PFC2D; Sandstone


[1] Li, X., Lei, X. & Li, Q. 2018. Response of Velocity Anisotropy of Shale Under Isotropic and Anisotropic Stress Fields. Rock Mechanics and Rock Engineering, 51, 695-711,

[2] Li, X., Lei, X. & Li, Q. 2016. Injection-induced fracturing process in a tight sandstone under different saturation conditions. Environmental Earth Sciences, 75, 1466,

[3] Shen, H., Li, X., Li, Q. & Wang, H. 2020. A method to model the effect of pre-existing cracks on P-wave velocity in rocks. Journal of Rock Mechanics and Geotechnical Engineering, 12, 493-506,

[4] Li, X., Lei, X., Li, Q. & Chen, D. 2021. Influence of bedding structure on stress-induced elastic wave anisotropy in tight sandstones. Journal of Rock Mechanics and Geotechnical Engineering, -,

How to cite: Shen, H., Li, X., and Li, Q.: Experiment and simulation of stress-dependent P-wave velocity anisotropy in sandstone, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-1485,, 2021.

Xiang Zhou, Yongsheng Tan, and Qi Jiang

In this study, in order to enhance heavy oil recovery in the heavy oil reservoir with a high-water-cut after water flooding process, experimental and numerical simulation studies are conducted. In the experimental studies, firstly, the properties of the heavy oil-CO2 system were measured under different saturation pressures at the reservoir temperature. Secondly, to mimic the high-water-cut condition in the real reservoir, water flooding process was conducted for each core; then four long core experiments insist of one CO2 huff `n` puff process and three CO2 flooding processes were implemented. The CO2 huff `n` puff process is conducted to compare the production performance with that in the CO2 flooding process to optimize the method. Regarding the CO2 flooding process, different gas (pure CO2, flue gas) and different production categories (constant production pressure, pressure depletion) were applied to study the heavy oil production performance in the heavy oil reservoir with high-water-cut. The experimental results indicate that, the CO2 flooding coupling with pressure depletion process is the best choice to reduce the water-cut and enhance the heavy oil recovery, which is 41.84% of the original oil in place and the water-cut reduced to lower than 70%. In the numerical simulation studies, the WinProp module in CMG is applied to simulate the properties of the heavy oil-CO2 system, which is generated by recombining CO2 into heavy oil, and high agreement simulation results were obtained. Then the results of the optimized experiment were history matched using GEM module. Finally, the upscaling studied was conducted. The CO2 flooding processes are carried out in the studied reservoir to maximum the heavy oil recovery factor. Moreover, the CO2 storage ratio is studied using GEM model.

How to cite: Zhou, X., Tan, Y., and Jiang, Q.: Enhanced heavy oil recovery and CO2 storage in a reservoir with high-water-cut: laboratory to field, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-10495,, 2021.

Chairpersons: Niklas Heinemann, Suzanne Hangx, Christopher Yeates
Firdovsi Gasanzade, Fahim Sadat, Ilja Tuschy, and Sebastian Bauer

Compressed air energy storage (CAES) in porous formations is one option to compensate the expected fluctuations in energy supply in future energy systems with a 100% share of renewable energy sources. Mechanical energy is stored as pressurized air in a subsurface porous formation using off-peak power, and released during peak demand using a turbine for power generation. Depending on share and type of renewable energy sources in the future, different storage capacities and storage power rates will have to be satisfied to compensate fluctuating nature of the renewable power supply. Therefore, this study investigates scenarios for subsurface compressed air energy storage using four potential future energy system development pathways. Because for CAES subsurface processes and power generation are strongly linked via reservoir pressure and flow rates, coupled power plant and geostorage model has to be developed and employed to evaluate potential operation conditions for such a storage technique.

In this study, a diabatic CAES is designed, with a three-stage compression and a two-stage expansion with heat recuperator in the power plant and a porous formation as a storage formation with 20 m thickness in an anticline trap structure at a depth between 700 and 1500 m. A withdrawal rate of 115 MW and a total stored energy of up to 348 GWh per year are derived from the future energy system scenarios. Scenario simulations are carried out by coupling the open-source thermal engineering TESPy code and the multiphase-multicomponent ECLIPSE flow simulator using highly fluctuating load profiles with a time resolution of one hour. In addition to the diabatic CAES, two adiabatic concepts are considered for the same geostorage configuration.

Results show that nine vertical storage wells are sufficient to deliver the target air mass flow rates required by the power plant during 98% of the year. Flow rate limitation occurs due to bottom hole pressure limits either during the injection or the withdrawal phases, depending on the specific load profile of the future energy systems, as well as the prior operation conditions. Thus, our scenario simulation shows that one porous media CAES site can cover all expected load profiles and balance the expected offsets between energy demand and energy supply up to the GWh scale. Balancing of the energy system at the national level can be achieved by up-scaling of the results obtained in this study.

How to cite: Gasanzade, F., Sadat, F., Tuschy, I., and Bauer, S.: Large-scale compressed air energy storage in porous media in a 100% renewable energy supply future, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-5148,, 2021.

Gabriella Elise Fuentes Tobin, Katriona Edlmann, and Niklas Heinemann

The role of hydrogen as a potential renewable energy storage vector is essential for carbon emission reduction and a corresponding low-carbon renewable energy supply and demand in the future. The geological storage of hydrogen is central to a steady transition from carbon emitting fuels to renewable energy resources as an off-grid energy supply, supporting intermittencies from renewable technologies. The depletion of gas reservoirs (DGRs) creates potential for hydrogen storage, whilst porous aquifers (PAs) and salt caverns (SCs) also provide the necessary conditions for potential hydrogen storage plays. However, the containment of hydrogen is challenging, and leakage from store has adverse economic and environmental consequences. 

This project has examined and investigated risks associated with the components required for subsurface storage in three geological scenarios, and their relevant influences on the assessment of the long-term security of hydrogen in the subsurface. The construction of a database using a Features Events, Process (FEP) model comprising all concomitant aspects of hydrogen storage enabled the identification of key factors contributing to hydrogen leakage from geological stores. Information on the geological storage of hydrogen is sparse, hence the various risks associated with geological storage facilities were drawn from other subsurface operations (Nuclear Waste Storage and CO2 storage) to develop a generic FEP database. The final database contains a comprehensive overview of risks involved in a hydrogen storage operation and forms the basis of an expert elicitation.

The identified risks were then incorporated within an expert elicitation exercise to quantify and analyse risks in terms of the severity of leakage extent, the probability of their occurrence over time, and those of high impact. Discrepancies in expert opinion emphasised high uncertainty risks that may contribute to leakage across the three subsurface storage facilities. The assessment of risks across three scenarios enabled comparisons of the confidence in their security to be made. A total of 12 risks were highly ranked in impact and uncertainty across two or more geological scenarios and were put forward for enhanced prevention, operation and monitoring strategies. 

How to cite: Fuentes Tobin, G. E., Edlmann, K., and Heinemann, N.: Features, Events and Processes of geological hydrogen storage: Which pose highest risk for leakage?  A three-scenario analysis: Depleted Gas Fields, Porous Aquifers and Salt Caverns., EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-12754,, 2021.

Meisam Babaie, Ibrahim Bakoji, Rasool Erfani, and Amir Nourian

Methane (CH4) and carbon dioxide (CO2) and these greenhouse gases together represent 29 gigatons of emission per year, with a projection of 36 to 43 gigatons/year. At these levels in the atmosphere, these gases contribute to the global climate change. Innovative methods need to be developed that will decrease these emissions to zero. Plasma reforming of natural gas that converts CO2 and CH4 to hydrogen fuel can be an effective solution since it contributes towards reduction of two major greenhouse gases as well as producing clean hydrogen fuel. Plasma is an ionised gas consisting of a mixture of equal number of positively charged ions and negatively charged electrons produced by an electric field. Reforming with plasma is conducted using a dry reforming reaction, with plasma or catalyst and CH4 and CO2 are used to produce Syngas with other products such as hydrogen (H2). In this study, the applicability of non-thermal plasma for hydrogen production is discussed and the benefits and challenges are thoroughly investigated. The results of this work can help in developing the awareness of the industries and other relevant stakeholders towards the potential of plasma on hydrogen production and CO2 reduction.

How to cite: Babaie, M., Bakoji, I., Erfani, R., and Nourian, A.: Nonthermal Plasma for Hydrogen Production, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-16280,, 2021.

Hector Barnett, Mark T. Ireland, and Sanem Acikalin

The energy industry in the UK faces a challenge to decarbonize to support reaching net zero CO2 emissions by 2050. In nearly all scenarios emission reductions are characterized not only by energy demand reductions, but also the decarbonization of electricity and heating. The use of hydrogen as a replacement for natural gas is one proposed solution, where renewable hydrogen is either blended into the gas grid or used directly. To ensure continuity of supply large scale hydrogen storage will be needed to meet this demand.

Hydrogen has been stored in small volumes (<25GWh) in salt caverns at various locations onshore in the United Kingdom since 1959. These caverns store hydrogen for industrial usage. In order to meet the demand for energy related hydrogen storage an increasing number of new and potentially larger storage options will be needed. Engineering of larger salt caverns for a hydrogen energy system will require thick salt formations which are optimally located with respect to both the hydrogen production facility and the end use. The Permian and Triassic salts deposits of both the Southern North Sea and the East Irish Sea offer vast areas for potential cavern development. Previous studies have described the landscape of underground gas storage onshore and offshore the UK, but to date there have been few detailed geophysical and geological studies on the hydrogen storage potential offshore.

The identification of suitable storage sites requires an understanding of the subsurface geology including potential structural discontinuities which could compromise the integrity of storage sites and be pathways for leakage. This analysis of hydrogen storage sites will utilise extensive existing modern 3D seismic data and well data taken from the Southern North Sea. We describe the geological setting of the Permo-triassic salt in the SNS in relation to the potential to develop salt cavern storage and develop play risk assessment maps. These risk assessment maps form part of a play fairway analysis workflow in order to identify the optimal storage sites for hydrogen on the UCKS.

How to cite: Barnett, H., Ireland, M. T., and Acikalin, S.: Assessing the feasibility of large-scale hydrogen storage in salt caverns on the UKCS using 3D seismic data, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-10952,, 2021.

Wolfram Kloppmann, Frédérick Gal, Michaela Blessing, and Christine Fléhoc

There is evidence that the emission of 14C –free CO2 during volcanic emissions creates a bias for radiocarbon dating of volcanic events (Holdaway et al., 2018), showing that integration of “dead” carbon by vegetation can serve as indicator of geogenic gas emissions. We tested 14C activities and stable carbon isotope ratios of tree rings and herbal vegetation in the proximity of a natural gas seep in the French Subalpine chains where both methane (<90% in the main vent) and CO2 (<11%) are present (Gal et al., 2018). Wood samples were taken from two alder trees, at different distances and directions from the main gas vent. Grass leaves and roots (Carex sp.) were analysed for two spots with contrasting soil methane concentrations and fluxes within the zone of diffuse gas emanation around the main vent (Gal et al., 2019). Grass and wood samples show contrasting isotope compositions depending on their species, age, and position with respect to the gas seep, some with 14C activities significantly lower than present day values. This offers perspectives of using vegetation carbon isotopes as proxies for present and past gas emanations, including man-induced gas leaks, e.g. from gas storage or natural gas exploitation facilities.

This research was co-funded by the EU H2020 Programme (grant 764531 – SECURe “Subsurface Evaluation of Carbon Capture and Storage and Unconventional Risk”)

Gal F., Kloppmann W., Proust E., Humez P. (2018) Gas concentration and flow rate measurements as part of methane baseline assessment: Case of the Fontaine Ardente gas seep, Isère, France. Applied Geochemistry, 95, 158-171.

Gal F., Proust E., Kloppmann W. (2019) Towards a Better Knowledge of Natural Methane Releases in the French Alps: A Field Approach. Geofluids, 2019, 1-16.

Holdaway R. N., Duffy B., Kennedy B. (2018) Evidence for magmatic carbon bias in 14C dating of the Taupo and other major eruptions. Nature Communications, 9, 4110.

How to cite: Kloppmann, W., Gal, F., Blessing, M., and Fléhoc, C.: Carbon isotopes of vegetation as proxy of natural or anthropogenic gas seeps, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-2655,, 2021.

Ping Lu, Zunsheng Jiao, and Lifa Zhou

CO2 geological storage (CGS) technology is currently one of the best choices for large-scale low-cost CO2 emission reduction in the world, and the primary issue of CO2 geological storage is the optimization of the selection of favorable areas for CO2 storage. In view of the insufficient research on the optimization of favorable areas for CO2 geological storage in the Majiagou Formation in the Ordos Basin, this study aims to determine the boundaries of the CO2 geological storage area in the Ordos Basin by studying the temperature and pressure conditions, reservoir conditions, structural conditions, caprock conditions , and the salinity conditions of the formation water using a large amount of geological, drilling, geophysical and experimental laboratory data. After the regional boundary of the CO2 geological sequestration is determined, it can be optimized and CO2 geological sequestration can be conducted in the areas that have favorable reservoir conditions, are relatively close to CO2 emission sources, have a high degree of exploration, have an appropriate formation depth and have a small impact on the development of other mineral resources. The results show that (1) the areas suitable for the geological storage of CO2 in the Ordos Basin are located in the distribution area of the Majiagou Formation in the Tianhuan Depression, except for the missing areas in the central paleo-uplift. The ares to the east of the Baiyanjing-Shajingzi fault, to the north of the northern margin of the Weibei uplift, to the west of the Yellow River fault, and to the south of the Yimeng uplift are suitable for CO2 geological storage. (2) Based on the three aspects of technology, safety, and economic feasibility, it was determined that the Wushenqi-Jingbian-Yan'an karst slope area (I1) is the best CO2 geological storage area, and the Yulin-Mizhi karst basin area (I2) is a favorable area for the geological storage of CO2 in the Ordos Basin.


How to cite: Lu, P., Jiao, Z., and Zhou, L.: Optimal Selection of Favorable Areas for CO2 Geological Storage in the Majiagou Formation in the Ordos Basin, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-15,, 2021.

Joaquim Juez-Larre, Cintia Gonçalves Machado, Hamid Yousefi, and Remco Groenenberg

The Netherlands is seeking ways to integrate large amounts of renewable energy production capacity (wind/solar) into its energy system, in order to reduce CO2 emissions and decrease dependency on future energy imports. Currently the Netherlands uses underground gas storage (UGS) to provide flexibility to its natural gas system, and secure supply during the winter season. However, hydrogen is considered to be a potential candidate to substitute natural gas, because it is a versatile energy carrier that can be produced from renewable electricity and be used as a CO2-neutral fuel and feedstock. It can also be stored in large amounts underground. Storage of compressed hydrogen in salt caverns is a proven technology, with single-cavern storage capacities in the range of 10-100 million m3. Yet some studies on the future Dutch energy system suggest much larger volumes of hydrogen storage may be required (1 to 50 billion m3). This large storage capacity can only be practically achieved in depleted natural gas fields. UHS in gas fields is not yet a proven technology. Only some pilot projects have successfully injected small amounts of hydrogen in some available underground reservoirs. In order to make possible future development of UHS, screening methodologies are needed for the readily identification and characterization of potential underground candidates. In this study, we develop a methodology that allows assessing UHS performances of large portfolios of underground reservoirs. As a case study we use the entire portfolio of natural gas fields in the Netherlands, including three UGSs.

In a first stage of our study, we conducted a nodal analysis of the Inflow Performance Relationship (IPR) and the vertical flow performance (outflow) curves, in order to obtain a first order estimate of the potential UHS performance for each field (e.g. rates of injection/withdrawal, working/cushion gas volumes and ranges of working pressures). Results show that withdrawal performances of wells in an UHS can be 2-3 times higher than those in an UGS. High bottom-hole drawdowns and erosional velocities in the production tubing may however significantly restrict the potential flow of hydrogen. Furthermore, the working gas volume of an UHS may contain up to four times less energy than that of an UGS, if operated at the same ranges of working pressures. Secondly, we used Eclipse 300, and the geological Petrel model of some of the best candidates, to conduct a more detail analysis of their potential UHS performances and the controlling factors. For that we ran consecutive injection/withdrawal cycles at different timescales (daily-weekly-monthly), and distinct working pressure ranges and types of cushion gas (e.g. nitrogen/hydrogen). Results allow to determine the efficiency of the different operational strategies and the number of wells required to match the expected future demands of hydrogen in the Netherlands. They also show the degree of hydrogen mixing with the residual and cushion gas during each cycle. Therefore our analytical/numerical modelling approach provides a good methodology to quantify and rank potential UHS reservoir candidates, and a means to classify the potential storage capacity of the entire portfolio.

How to cite: Juez-Larre, J., Gonçalves Machado, C., Yousefi, H., and Groenenberg, R.: Combining analytical and numerical modelling of gas flow in depleted natural gas fields to identify potential Underground Hydrogen Storage (UHS) sites in the Netherlands, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-10063,, 2021.

Victor Vilarrasa and Francesco Parisio

Geologic carbon storage is needed to reach carbon neutrality and eventually achieve negative emissions. In the classical concept of storing CO2 in deep sedimentary aquifers, supercritical CO2 has a lower density than the resident brine. CO2 is therefore buoyant and the safety and effectiveness of the storage concept rely on the caprock sealing capacity to prevent CO2 leakage. To reduce the risk of CO2 leakage and widen the CO2 storage options, we propose an innovative concept that consists in injecting CO2 in reservoirs where the temperature and pressure of the resident brine are above the critical point ( 373.95 ºC and 22.064 MPa for pure water). At such conditions, which can be found at depths between 3 to 5 km in volcanic areas, CO2 is denser than the resident water and thus, sinks. The sinking tendency reduces the risk of CO2 leakage to the surface even in case of damaged or absent caprock. CO2 storage in supercritical reservoirs can potentially become an additional option to the existing storage concepts aimed at significantly reduce CO2 emissions. We estimate that every 100 wells drilled into supercritical reservoirs could store between 50 to 500 Mt/yr of CO2.



Parisio, F. and Vilarrasa, V. (2020). Sinking CO2 in supercritical reservoirs. Geophysical Research Letters, e2020GL090456.

How to cite: Vilarrasa, V. and Parisio, F.: A novel CO2 storage concept that reduces the leakage risk, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-1990,, 2021.

Iman Rahimzadeh Kivi, Victor Vilarrasa, and Roman Makhnenko

Global warming brought upon by anthropogenic CO2 emissions into the atmosphere is causing significant impacts on the Earth and represents one of the major concerns of the current century. To be controlled, it is widely accepted that huge amounts of CO2 at the gigatonne scale have to be captured and injected back into the underground in a process known as Carbon Capture and Storage (CCS). As CO2 is less dense than the in-situ brine, it tends to flow upward out of the storage reservoir by buoyancy and the injection overpressure. A laterally-extensive and thick non-fractured caprock possessing low permeability and high entry capillary pressure is commonly expected to keep CO2 within the host reservoir. However, the potential risks of CO2 leakage through the intact caprock need thorough assessment. This contribution brings together experimental observations and numerical simulations to inspect the sealing capacity of an intact shaly caprock and render an in-depth understanding of the governing flow mechanisms. Reproducing the subsurface conditions of CO2 intrusion and flow through the caprock, breakthrough experiments are conducted on Opalinus Clay as a representative caprock for CO2 storage. The adopted approach consists of injecting supercritical CO2 into the caprock sample lying between two permeable porous disks, all initially saturated with brine. Supplementary experiments are also performed to characterize the pore structure and hydromechanical properties of the specimen. The extracted properties are used to parameterize a two-phase flow model in deformable porous media and simulate the breakthrough experiment carried out on Opalinus Clay to make a mechanistic interpretation of the experimental observations. Simulation results reveal three concomitant CO2 flow mechanisms into and through the caprock: molecular diffusion, bulk volumetric advection, and transported CO2 dissolved in the advected brine. It is inferred that the high entry pressure and low effective permeability prevents free phase CO2 penetration deep into the caprock. The drainage path is followed by the imbibition of brine back into the pores from the downstream until recovering the initial state of being completely saturated with brine. While the contribution of brine advection to CO2 transport is found to be negligible, we find that CO2 flow through the caprock is mainly governed by molecular diffusion, whose effects on the potential leakage of CO2 during geological time scales have to be taken into account.

How to cite: Rahimzadeh Kivi, I., Vilarrasa, V., and Makhnenko, R.: A mechanistic interpretation of potential CO2 leakage through shaly caprocks, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-2478,, 2021.

Andrey Afanasyev and Elena Vedeneeva

We present a recent extension of the MUFITS reservoir simulator for numerical modelling of multicomponent gas injection into saline aquifers. The extension is based on the compositional module of the simulator that implements a conventional cubic equation of state (EoS) for predicting phase equilibria of reservoir fluids [1]. Now, the module is supplemented with a new library of EoS coefficients for accurate modelling of CO2, N2, CH4, H2, O2, H2S, and other hydrocarbon components solubility in NaCl brine. In general, we follow the approach proposed by Søreide and Whitson [2] for modelling aqueous solutions, which involves a different and dependent on brine salinity binary interaction coefficients for aqueous and non-aqueous phases. However, we also use several published modifications to the EoS coefficients that were originally proposed in [2] to improve prediction of the mutual solubilities.

The extension is validated against 3-D benchmark studies of pure supercritical CO2 injection into saline aquifers. Also, we consider two more complicated injection scenarios to demonstrate potential applications of the new development. First, we simulate impure CO2 injection into a saline aquifer. We show that even a small amount of air (N2 and O2) in the injected gas results in a significantly more rapid spreading of the gas plume. Second, we consider a 3-D study of CO2 injection into subsurface natural gas storage aiming at the cushion gas substitution with supercritical CO2. The mechanical dispersion in the porous medium is accounted for an accurate modelling of CO2 and CH4 mixing. We simulate the propagation of CO2 in the storage by modelling several seasons of natural gas (CH4) injection and extraction.

The authors acknowledge funding from the Russian Science Foundation under grant # 19-71-10051.


1. Afanasyev A.A., Vedeneeva E.A. (2020) Investigation of the efficiency of gas and water Injection in an oil reservoir. Fluid Dyn. 55(5), 621-630.

2. Søreide I., Whitson C.H. (1992) Peng-Robinson predictions for hydrocarbons, CO2, N2, and H2S with pure water and NaCl brine. Fluid Phase Equil. 77, 217-240.

How to cite: Afanasyev, A. and Vedeneeva, E.: Compositional modelling of impure gas injection into saline aquifers with the MUFITS simulator, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-9127,, 2021.

Qi Li, Miao He, Michael Kühn, Xiaying Li, and Liang Xu

Injecting fluid into the formation is an effective solution for improving the permeability and production of a target reservoir. The evaluation of economy and safety of injection process is a challenging issue faced in reservoir engineering [1-2]. As known, the relative magnitude and direction of the principal stresses significantly influence the hydro-mechanical behavior of reservoir rock during fluid injection. However, due to the limitations of current testing techniques, it is still difficult to comprehensively conduct laboratory injection tests under various stress conditions, e.g. triaxial extension stress states [3]. To this end, a series of numerical simulations were carried out on reservoir rock to study the hydro-mechanical changes under different stress states during fluid injection. In this modelling, the saturated rock is first loaded to the target stress state under drainage conditions, and then the stress state is maintained and water is injected from the top end to simulate the reservoir injection process. Particular attention is paid to the difference in hydro-mechanical changes under triaxial compression and extension stresses. This includes the difference of the pore pressure propagation, mean effective stress, volumetric strain, and stress-induced permeability. The numerical results demonstrate that the differential stress will significantly affect the hydro-mechanical behavior of target rock, but the degree of influence is different under the two triaxial stress states. The hydro-mechanical changes caused by the triaxial compression stress states are generally greater than that of extension, but the difference decreases with increasing differential stress, indicating that the increase of the differential stress will weaken the impact of the stress state on the hydro-mechanical response. This study can deepen our understanding of the stress-induced hydro-mechanical coupling process in reservoir injection engineering.

Keywords: Reservoir injection; Subsurface flow; Hydro-mechanical coupling; Stress state; Triaxial experiment modelling

[1] Li, X., Lei, X. & Li, Q. 2016. Injection-induced fracturing process in a tight sandstone under different saturation conditions. Environmental Earth Sciences, 75, 1466,

[2] Yang, D., Li, Q. & Zhang, L. 2016. Propagation of pore pressure diffusion waves in saturated dual-porosity media (II). Journal of Applied Physics, 119, 154901,

[3] Xu, L., Li, Q., Myers, M., Tan, Y., He, M., Umeobi, H.I. & Li, X. 2021. The effects of porosity and permeability changes on simulated supercritical CO2 migration front in tight glutenite under different effective confining pressures from 1.5 MPa to 21.5 MPa. Greenhouse Gases: Science and Technology,

How to cite: Li, Q., He, M., Kühn, M., Li, X., and Xu, L.: Investigation of the effect of stress states on hydro-mechanical behaviors of reservoir rock under fluid injection, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-1656,, 2021.

Aliakbar Hassanpouryouzband, Katriona Edlmann, and Mark Wilkinson

To enable a fast transition of the global energy sector towards operation with 100% renewable and clean energy technology, the geological storage of hydrogen in depleted gas fields or salt caverns has been considered as a strong candidate for the future energy storage required for limiting global warming to well below 2 °C, as agreed under the Paris Agreement. As such, understanding the impact of injected hydrogen on the geochemical equilibrium in these storage reservoirs is critical. Here, using our bespoke high pressure/temperature batch reaction vessels we investigate the potential effects of hydrogen injection into 3 different sandstones reservoirs.  These experiments were conducted at reservoir temperature and at different injection pressures from 1 to 20 MPa with salinities from 0 to 10 weight% over different time periods from 1 to 8 weeks.  Our experiments reveal that there is no hydrogen-associated geochemical reaction for the selected sandstones. Although changing reservoir pressure slightly affected the mineral dissolution equilibria at ppm level for hydrogen injection scenarios, the fluctuations of mineral dissolution in water associated with pressure change have a negligible influence on the efficiency of geological hydrogen storage.  Therefore, based on the analysis of water chemistry before and after the mentioned experiments, we demonstrate that from geochemical point of view geological storage of hydrogen in these sandstone reservoirs is safe and we don’t expect any hydrogen loss due to geochemical reactions. 

How to cite: Hassanpouryouzband, A., Edlmann, K., and Wilkinson, M.: Geochemistry of Geological Hydrogen Storage in Sandstone Reservoirs, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-9894,, 2021.

Jonathan Scafidi, Laurent Schirrer, Isabelle Vervoort, and Niklas Heinemann

UK natural gas demand is 2-4 times that of electricity and characterised by seasonal differences in demand of almost triple in the winter with larger spikes during extreme cold weather events. This makes any decarbonisation effort reliant on its ability to handle these large changes in demand. Conversion of the gas supply to hydrogen is the most promising solution. To facilitate this, large-scale underground storage will be required in the order of 150 TWh or 40 days’ worth of supply.

Subsurface gas storage in porous rocks requires a proportion of the gas to remain in the reservoir to maintain the pressure required for the minimum economic flow rate from the wells. This is called the cushion gas requirement. In the case of a hydrogen storage reservoir the use of a cheaper cushion gas, such as CO2 or N2, is the subject of much research.

We investigate the possibility of using natural gas within a partially depleted gas reservoir as cushion gas. We will present the results of a compositional simulation of seasonal hydrogen storage over a 20 year period in a closed reservoir. The study shows that natural gas has potential as a cushion gas, in this case achieving greater than 95% hydrogen recovery factors with minimal amounts of mixing in the reservoir. Use of natural gas as cushion gas also reduces the risk of water coning which can lead to loss of hydrogen.

Although these results are promising, the study highlights several key areas that need further investigation to improve the reliability of future simulations. These include defining relative permeability curves for hydrogen, refinement of how simulators handle viscosity equations, and a greater understanding of hydrogen well engineering. All of these factors will influence estimates of the hydrogen capacity of a porous rock reservoir.

How to cite: Scafidi, J., Schirrer, L., Vervoort, I., and Heinemann, N.: Compositional simulation of hydrogen storage in a depleted gas field, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-7738,, 2021.

Yongsheng Tan, Qi Li, Liang Xu, Xiaoyan Zhang, and Tao Yu

The wettability, fingering effect and strong heterogeneity of carbonate reservoirs lead to low oil recovery. However, carbon dioxide (CO2) displacement is an effective method to improve oil recovery for carbonate reservoirs. Saturated CO2 nanofluids combines the advantages of CO2 and nanofluids, which can change the reservoir wettability and improve the sweep area to achieve the purpose of enhanced oil recovery (EOR), so it is a promising technique in petroleum industry. In this study, comparative experiments of CO2 flooding and saturated CO2 nanofluids flooding were carried out in carbonate reservoir cores. The nuclear magnetic resonance (NMR) instrument was used to clarify oil distribution during core flooding processes. For the CO2 displacement experiment, the results show that viscous fingering and channeling are obvious during CO2 flooding, the oil is mainly produced from the big pores, and the residual oil is trapped in the small pores. For the saturated CO2 nanofluids displacement experiment, the results show that saturated CO2 nanofluids inhibit CO2 channeling and fingering, the oil is produced from the big pores and small pores, the residual oil is still trapped in the small pores, but the NMR signal intensity of the residual oil is significantly reduced. The final oil recovery of saturated CO2 nanofluids displacement is higher than that of CO2 displacement. This study provides a significant reference for EOR in carbonate reservoirs. Meanwhile, it promotes the application of nanofluids in energy exploitation and CO2 utilization.

How to cite: Tan, Y., Li, Q., Xu, L., Zhang, X., and Yu, T.: Saturated carbon dioxide nanofluids enhanced oil recovery in carbonate reservoir cores using nuclear magnetic resonance, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-6762,, 2021.

Manab Mukherjee, Anamita Sikdar, and Santanu Misra

Adsorptive gas transport (such as CO2) in subsurface through coal matrix alters the dimension of pores and cleats and results in reduction of coal formation permeability. We propose thermal-cracking could be a potential method to increase the coal-permeability. We tested a number of coal samples from Bansgara colliery, India and compared the permeability and strength of the air-dried vs. thermally-cracked samples. Samples were heated at 280°C for 36 hours and then quickly chilled to produce thermal-cracks mostly along the bedding planes, which were confirmed by microscopic study. We tested the mechanical strength keeping the bedding planes perpendicular (α=90°) and parallel (α=0°) to the loading directions.

The peak compressive strengths of air-dried samples from room to 15 MPa confinement were noted as 14-44 MPa and 12-37 MPa for α=90° and 0° conditions, respectively. The mechanical behavior of the thermally-cracked samples, interestingly, was not straight forward. The peak compressive strengths of thermally-cracked samples were comparable to those of air-dried samples when α=90°. Interestingly, when α=0°, the peak-strength dropped by 82% at room pressures and 67% at 15 MPa confining pressures with respect to the air-dried samples under similar conditions.  The stress strain profile of the deforming coal samples showed initial shallow slopes indicating pore closure, and then a steep slope in the elastic limit. Most of the samples were brittle and failed at the yield point. Few samples showed slight ductile signatures and plastic flow at higher confinements. Axial splitting was observed in samples at low confinements. At higher confinements, fracture pattern was more dominated by shear cracks as compared to tensile cracks. Our results also show that porosity of the samples increases by 30-35%. Gas permeability (N2 used as a probing gas) of the thermally cracked samples at 6.5 MPa confining pressure and 1 MPa pore pressures are 1.31 and 4 md for α=90° and 0° conditions, respectively. Permeability of air-dried samples at similar experimental conditions are 0.2 and 0.7 md for α=90° and 0° conditions, respectively.

We interpret that the loading sub-parallel thermal-cracks further opened and connected each-other during loading and therefore failed at lower stresses when α=0°. The interconnected pore and cleat network also resulted in permeability enhancement. Interlocking network of coal matrix resist the deformation of coal, and thermal cracks penetrate in coal matrix to reduce the entanglement of macerals in coal and lower its mechanical strength. In contrary, under α=90° loading conditions, the horizontal thermal cracks closed due to perpendicular load rather than opening further, and thus in those samples the strength reduction is less prominent. We conclude that thermal-cracking is a prospective method in enhancing the subsurface coal-permeability of deep-seated coal seams from micro to millidarcy. However, it must be ensured that the load imparted by the wellbore (injecting or recovery wells) on thermally cracked coal reservoir should act perpendicular to its bedding.

How to cite: Mukherjee, M., Sikdar, A., and Misra, S.: Compressive strength and permeability of thermally-cracked coals: implications for gas storage and transport in subsurface coal seams, EGU General Assembly 2021, online, 19–30 Apr 2021, EGU21-15482,, 2021.