ERE4.1

To limit global warming to well below 2^oC, 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. https://doi.org/10.1039/D0EE00674B

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, https://doi.org/10.5194/egusphere-egu21-10327, 2021.

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, https://doi.org/10.5194/egusphere-egu21-3496, 2021.

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, https://doi.org/10.5194/egusphere-egu21-13964, 2021.

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, https://doi.org/10.5194/egusphere-egu21-14804, 2021.

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. https://doi.org/10.1287/opre.51.2.228.12786

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, https://doi.org/10.5194/egusphere-egu21-16457, 2021.

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.

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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, https://doi.org/10.5194/egusphere-egu21-533, 2021.

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, https://doi.org/10.5194/egusphere-egu21-7008, 2021.

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, https://doi.org/10.5194/egusphere-egu21-12191, 2021.

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, https://doi.org/10.5194/egusphere-egu21-10495, 2021.

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, https://doi.org/10.5194/egusphere-egu21-12754, 2021.

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, https://doi.org/10.5194/egusphere-egu21-10952, 2021.

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, https://doi.org/10.5194/egusphere-egu21-15, 2021.

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, https://doi.org/10.5194/egusphere-egu21-10063, 2021.

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.

REFERENCES

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, https://doi.org/10.5194/egusphere-egu21-1990, 2021.

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, https://doi.org/10.5194/egusphere-egu21-2478, 2021.

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.

References

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, https://doi.org/10.5194/egusphere-egu21-9127, 2021.

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, http://doi.org/10.1007/s12665-016-6265-2

[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, http://doi.org/10.1063/1.4946832

[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, http://doi.org/10.1002/ghg.2043

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, https://doi.org/10.5194/egusphere-egu21-1656, 2021.

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, https://doi.org/10.5194/egusphere-egu21-15482, 2021.