ERE1.8 | Redeploying existing oil and gas technology to benefit the development of sustainable energy resources
EDI
Redeploying existing oil and gas technology to benefit the development of sustainable energy resources
Co-organized by EMRP1/ESSI4/GI5/SSP1
Convener: Paul Glover | Co-conveners: Thomas Kempka, Anne Pluymakers, Marina FacciECSECS
Orals
| Tue, 16 Apr, 14:00–15:45 (CEST), 16:15–18:00 (CEST)
 
Room 0.96/97
Posters on site
| Attendance Wed, 17 Apr, 10:45–12:30 (CEST) | Display Wed, 17 Apr, 08:30–12:30
 
Hall X4
Posters virtual
| Attendance Wed, 17 Apr, 14:00–15:45 (CEST) | Display Wed, 17 Apr, 08:30–18:00
 
vHall X4
Orals |
Tue, 14:00
Wed, 10:45
Wed, 14:00
Geoscience underpins many aspects of the energy mix that fuels our planet and offers a range of solutions for reducing global greenhouse gas emissions as the world progresses towards net zero. The aim of this session is to explore and develop the contribution of geology, geophysics and petrophysics to the development of sustainable energy resources in the transition to low-carbon energy. The meeting will be a key forum for sharing geoscientific aspects of energy supply as earth scientists grapple with the subsurface challenges of remaking the world’s energy system, balancing competing demands in achieving a low carbon future.
Papers should show the use of any technology that was initially developed for use in conventional oil and gas industries, and show it being applied to either sustainable energy developments or to CCS, subsurface waste disposal or water resources.
Relevant topics include but are not limited to:
1. Exploration & appraisal of the subsurface aspects of geothermal, hydro and wind resources.
2. Appraisal & exploration of developments needed to provide raw materials for solar energy, electric car batteries and other rare earth elements needed for the modern digital society.
3. The use of reservoir modelling, 3D quantification and dynamic simulation for the prediction of subsurface energy storage.
4. The use of reservoir integrity cap-rock studies, reservoir modelling, 3D quantification and dynamic simulation for the development of CCS locations.
5. Quantitative evaluation of porosity, permeability, reactive transport & fracture transport at subsurface radioactive waste disposal sites.
6. The use of petrophysics, geophysics and geology in wind-farm design.
7. The petrophysics and geomechanical aspects of geothermal reservoir characterisation and exploitation including hydraulic fracturing.
Suitable contributions can address, but are not limited to:
A. Field testing and field experimental/explorational approaches aimed at characterizing an energy resource or analogue resources, key characteristics, and behaviours.
B. Laboratory experiments investigating the petrophysics, geophysics, geology as well as fluid-rock-interactions.
C. Risk evaluations and storage capacity estimates.
D. Numerical modelling and dynamic simulation of storage capacity, injectivity, fluid migration, trapping efficiency and pressure responses as well as simulations of geochemical reactions.
E. Hydraulic fracturing studies.
F. Geo-mechanical/well-bore integrity studies.

Orals: Tue, 16 Apr | Room 0.96/97

Chairpersons: Anne Pluymakers, Paul Glover
14:00–14:05
Invited Presentation
14:05–14:25
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EGU24-12486
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solicited
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On-site presentation
Suzanne Hangx

Though global energy needs continue to grow, fossil fuels, and their associated CO2 emissions, are increasingly being opposed as our main source of energy. Instead, to achieve net zero greenhouse gas emissions goals, we are currently transitioning to more sustainable sources of energy, such as solar and wind power and geothermal energy, coupled with storage of waste, such as CO2. However, these new technologies come with their own challenges, as they continue to rely on (re-)use of the subsurface landscape. The intermittency of solar and wind power will require storage of renewably generated electricity. Hydrogen fuel has been marked as a potential energy carrier, enabling us to store large quantities of energy for prolonged periods of time, such as required to supply large industries or communities during winter months. To store this hydrogen fuel, the subsurface offers the largest storage space available, such as in (offshore) depleted hydrocarbon fields, but reproduction of the stored fluid is crucial. Geothermal energy production will require the extraction of hot fluids from depth and will often be performed in populated areas, close to the consumers, meaning that phenomena such as surface subsidence and induced seismicity are highly undesirable. The safe storage of CO2 for thousands of years also entails fluid injection, but containment is of vital importance to keep the CO2 out of our atmosphere. So though we have a vast history of exploitation of the subsurface through the oil and gas industry, which we can and should build upon, these new sustainable energy developments also pose their own, new challenges. While fluid production changes the physical equilibrium of the system, these new uses will also impact the chemical equilibrium through the injection of new fluids. Furthermore, containment and safety play an even bigger role than before to ensure the longevity of these new subsurface operations. In this contribution, I will outline what the challenges are that we are facing and how geoscientists can contribute to solving these challenges, across all areas from rock physics, geochemistry and hydrology, to sedimentology, structural geology and policy.

How to cite: Hangx, S.: Same same but different: the scientific challenges when re-using the subsurface for sustainable energy developments, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-12486, https://doi.org/10.5194/egusphere-egu24-12486, 2024.

Carbon Capture and Underground Storage
14:25–14:35
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EGU24-2177
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On-site presentation
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Laurent De Windt, Irina Sin, Camille Banc, Anélia Petit, and David Dequidt

This study is based on unique field data on a 3-year pilot test during which air containing 8 mol% O2(g) was injected as a cushion gas into a natural gas reservoir, a carbonate-cemented sandstone aquifer located in the Paris Basin (France) [1]. The oxygen was fully depleted several months after injection completion, meanwhile CO2(g) was detected around 2–6 mol%; the pH decreased from 8 to 6, while reducing conditions shifted to mildly oxidizing ones with increasing concentration of sulfates in equilibrium with gypsum. After the test completion, the long-term evolution of the aquifer was assessed by a 15-year survey. The pH gradually returned to its near initial state and sulfates were reduced by 2 to 3 times. Data on the release of trace metals (Ba, Cu, Pb, Zn) during and after the test were also available.

Multiphase reactive transport models were developed on these field data using the HYTEC reactive transport code in 2D-reservoir configurations [1]. At the short-term scale, modeling focused on the gas-water-rock reactive sequence during the air injection: 1/ depletion of the injected O2(g) due to pyrite oxidation, 2/ leading to acidity production and dissolved sulfates, 3/ acidity buffering by calcite dissolution, 4/ followed by gypsum precipitation and CO2(g) exsolution. At the long-term scale, the modeling tackled with the progressive return to the baseline chemistry of the deep aquifer that was 1/ mostly driven by transport processes and 2/ to a lesser extent, slow water/rock chemical interactions.

These field-based models developed at short and long-term could be used as a workflow for other gas storage facilities, e.g. biomethane, compressed air, and CO2.

[1] Sin, I., De Windt, L., Banc, C., Goblet, P., Dequidt, D. (2023). Assessment of the oxygen reactivity in a gas storage facility by multiphase reactive transport modeling of field data for air injection into a sandstone reservoir in the Paris Basin, France. Science of The Total Environment 869, 161657.

How to cite: De Windt, L., Sin, I., Banc, C., Petit, A., and Dequidt, D.: Short and long-term multiphase reactive transport processes during a pilot test of air injection into a sandstone gas storage facility, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-2177, https://doi.org/10.5194/egusphere-egu24-2177, 2024.

14:35–14:45
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EGU24-8973
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ECS
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On-site presentation
Evgeniia Martuganova, David F. Naranjo Hernandez, Daniela Kühn, and Auke Barnhoorn

Decarbonisation of the European economy represents one of the current challenges to both society and the energy sector. The advancement and further application of carbon capture and sequestration (CCS) technologies are crucial components of the EU’s effort to become climate-neutral by 2050. The success of CCS depends heavily on understanding the present-day stress field to anticipate reservoir and cap rock response to fluid injection. Despite its importance, many proposed carbon storage sites in the North Sea are located in areas with little to no borehole stress data available, presenting a significant challenge.

Within the ACT project SHARP Storage framework, we have addressed this gap by generating a comprehensive earthquake bulletin for the North Sea, revealing spatial clusters of seismic events with the majority of earthquakes with ML < 4. Focal mechanisms of earthquakes are excellent indicators of crustal dynamics, which are essential for assessing the present-day stress field. Therefore, to improve the understanding of the in-situ stress conditions, we created a comprehensive workflow to evaluate focal mechanisms based on data from the North Sea (Kettlety et al., 2023). First, we developed a routine for the seismological bulletin to aggregate the recorded earthquakes from international seismological centres. The following step included retrieval of the waveforms from data centres and quality control routines, which included dead channels check, exclusion of files with significant recording gaps and low signal-to-noise ratio, and corrections of errors in the station XML files. Then, a subset of data traces with sufficient quality was selected for moment tensor computations using a Bayesian bootstrap-based probabilistic inversion scheme (see Heimann et al., 2018). Using existing focal mechanism solutions for the North Sea region, we calibrated our processing routine and then applied it to selected earthquakes (after 1990, M > 3.5) to expand the existing focal mechanisms database.

The newly computed focal mechanism solutions provide valuable insight into the present-day stress field in areas outside the main hydrocarbon provinces and improve the risk assessment of ongoing and future CCS projects. Furthermore, we will release our processing workflow as an open-source package and a new focal mechanisms database of the North Sea to establish a standard processing routine that can be readily utilised for similar seismological studies.

How to cite: Martuganova, E., Naranjo Hernandez, D. F., Kühn, D., and Barnhoorn, A.: Assessing earthquake focal mechanisms in the North Sea for risk mitigation of large-scale CO2 injections, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-8973, https://doi.org/10.5194/egusphere-egu24-8973, 2024.

14:45–14:55
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EGU24-9206
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ECS
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On-site presentation
Hongyu Yu, Bei Wang, Honn Kao, Ryan Visser, and Malakai Jobin

From 2005 to 2020, Canada achieved a 9.3% reduction in green house gas emission (69 Mt CO2 eq), meanwhile British Columbia witnessed a 5% increase (3.0 Mt CO2 eq) from 2007 to 2019. Exploiting unconventional oil and gas resources in northeast British Columbia (NEBC) has become the province’s second-largest source of greenhouse gas emissions. In pursuit of a cost-effective and seismic risk-aware approach for carbon emission reduction, this study evaluates the CO2 geological storage capacity in NEBC with a focus on repurposing existing injection wells for carbon storage.

We particularly emphasize the Montney and Debolt formations. These formations are the main targets of a diverse array of injection wells, including those for hydraulic fracturing, enhanced hydrocarbon recovery, and wastewater disposal. Three trapping mechanisms in the NEBC area are examined: physical and solubility trapping for wastewater disposal wells in the Debolt Formation, and physical and mineral trapping for hydraulic fracturing and enhanced recovery wells in the Montney Formation. Furthermore, we incorporate an assessment of seismic hazards, informed by the latest insights into injection-induced seismicity in NEBC, as a potential indicator of CO2 leakage risk.

Our findings underscore the favorable conditions of the Debolt Formation with lower seismicity hazard and a substantial CO2 storage capacity (19.3 Gt; ~284.4 years of CO2 emissions in BC). Depleted oil and gas reservoirs within the Montney Formation are also deemed suitable for CO2 storage, estimated at 1671.8 Mt (approximately 24.5 years), particularly in the Upper Montney due to its higher storage capacity and lower seismic risk.

Overall, this research offers an assessment of CO2 geological storage potential at the formation-scale in NEBC. The emphasis on well suitability and seismic risks effectively bridges the gap between the regional-scale geological assessments and site-scale engineering evaluations. It paves the path for future studies on addressing more practical topics related to the choices of project sites and injection strategies.

How to cite: Yu, H., Wang, B., Kao, H., Visser, R., and Jobin, M.: Storage potential of CO2 by repurposing oil and gas-related injection wells in the Montney Play, northeast British Columbia, Canada, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-9206, https://doi.org/10.5194/egusphere-egu24-9206, 2024.

14:55–15:05
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EGU24-1739
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ECS
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Virtual presentation
Ayberk Uyanik

Revealing the thermal structure of subsurface is crucial for various projects including geothermal energy exploitation, CCS and hydrocarbon exploration. For instance, temperature is one of the key physical underground parameters governing the type of Geothermal systems, whether injected CO2 remains in supercritical fluid stage and the depth of Golden Zone at where the hydrocarbon accumulations occur. Thus, understanding the temperature and geothermal gradient change in 1D-2D-3D sense indicates sweet spots and helps geoscientists to build more robust models to reduce the risks.

Based on this concept, this study aims to demonstrate the outcomes of a game-changer method which is the conversion of interval velocities into temperatures, thermal conductivities and heat flows by the help of recently proposed empirical relationships. As a case study, Northern Arabian Plate, SE Turkey is selected due to the neglection of thermal conditions in the area. Therefore, oil & gas industry-wide accepted methodologies have been applied to better understand thermal behaviour of the subsurface and how it has been controlled by regional tectonic edifices including large-scale thrust and strike slip faults.

In terms of methodology, as the first step, dynamic bottom hole temperatures of the wells have been converted into static ones by the help of “Temperature Analyser” web application. The converted temperature measurements have been used to generate regional temperature and geothermal gradient maps for every 500 meters. On the other hand, for 3D temperature models, seismic velocities have been converted into temperature cubes after calibration with the converted BHT measurements. Generated temperature cubes have been reflected on seismic sections to display lateral and vertical variations in temperature behaviour. It also allows the detection of meaningful temperature anomalies corresponding to possible fluid content.

The results reveal that abrupt temperature increase on maps directly coincides with the locations of oil producing fields. The same behaviour was noted globally both for hydrocarbon and geothermal fields. The change in temperature trend is also dominated by regional tectonics of the focus area. Large thrust fault systems act as boundaries for thermal anomaly regions while sinistral Mosul Fault Zone displaces and separates high temperature zones in a NW-SE sense. This movement can be easily associated with the Northern slip of the Arabian Plate since the continental collision occurred in the Miocene.

 

Based on these observations, the workflows and results of this study can be used for detailed investigation of subsurface geology, thermal conditions, and their effect on potential reservoirs for geothermal and CO2 storage. Workflows used to generate thermal models might allow the development of more efficient sustainable energy projects not only for the Northern sector of the Arabian plate but also for the other regions of the World.

How to cite: Uyanik, A.: Conversion of Interval Velocities into Thermal Models: A Game Changer Method for Subsurface Energy Exploitation Projects , EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-1739, https://doi.org/10.5194/egusphere-egu24-1739, 2024.

15:05–15:15
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EGU24-4657
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ECS
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On-site presentation
Debanjan Chandra, Barbara Perez Salgado, and Auke Barnhoorn

Porous reservoir rocks like sandstones have gained utmost important in the last decade as a potential sink for CO2. Most of the targeted reservoirs are depleted oil and gas fields, which has caprocks to ensure the containment of the injected CO2. Injecting CO2 into porous reservoirs increase the pore pressure, which therefore reduces the effective horizontal and vertical stresses. Depending on the pre-injection stress-condition and permeability of the reservoir, utmost care should be taken to define the upper limit of CO2 injection pressure, in order to prevent any permanent damage to the reservoir which can lead to leakage or induced seismicity. Lab-scale experiments provide key insights to the deformation behavior of reservoir rocks under different stress-conditions, which can be upscaled to understand reservoir scale processes. To simulate the stress perturbation caused by CO2 injection operations, we have subjected porous reservoir rocks (coreplugs) collected from different depths of offshore North Sea under cyclic axial loading and unloading with a confining pressure increment from 10-50 MPa between each cycle. The P and S wave velocities along the axial direction of the coreplugs were recorded in every 10 s to assess the change in wave properties during deformation. It was observed that during each loading cycle, wave velocities are highest at the elastic-plastic transition zone, which can be attributed to the compression of pores and closure of microcracks perpendicular to the loading direction. The wave velocities decrease sharply after the onset of plastic deformation, which can be attributed to the formation of microcracks in the coreplug due to increasing load. The static and dynamic Young’s modulus (E) of the coreplugs during each cycle of increasing confinement show linear increase. Plugs with lower porosity shows higher E with steeper increment at higher confining pressure. The correlation between the wave properties and mechanical response of the reservoir rocks under cyclic loading reveal that constant monitoring of wave velocities during CO2 injection can act as an efficient tool for monitoring stress-state of the reservoir, facilitating safer CO2 storage operations.

How to cite: Chandra, D., Salgado, B. P., and Barnhoorn, A.: Wave velocities as a proxy to forecast deformation during cyclic loading-unloading in porous reservoir rocks, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-4657, https://doi.org/10.5194/egusphere-egu24-4657, 2024.

15:15–15:25
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EGU24-9509
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ECS
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Virtual presentation
Qian Wang, Glover Paul, and Lorinczi Piroska

In the development of hydrocarbon fields, it is becoming known that CO2 injection (which is sometimes done to improve hydrocarbon production) can cause pore blockage and wettability alteration by the promotion of asphaltene deposition. In hydrocarbon reservoirs, the result is poor oil recovery performance during carbon dioxide (CO2) injection. If CO2 is being injected into a legacy hydrocarbon reservoir (i.e., one that still contains residual oil) the same process will occur. Once again, the ability of fluid (this time supercritical CO2) to flow will be impeded, but it is also possible that asphaltene deposition will also reduce the overall pore volumes in which CO2 could otherwise be stored. In this work, the residual oil distribution and the permeability decline caused by organic and inorganic precipitation after miscible CO2 flooding and water-alternating-CO2 (CO2-WAG) flooding have been studied by carrying out core-flooding experiments at high pressures and temperatures in an artificial three layer system. For simple CO2 injection during CCUS operations, flooding experimental results indicate that the low-permeability layers retain a large oil production potential even in the late stages of production, which could impede CO2 emplacement and provide significant heterogeneity, while the permeability decline due to asphaltene precipitation is more significant in high-permeability rocks. In contrast, we found that CO2-WAG can reduce the influence of heterogeneity on the oil production, but it results in more serious reservoir damage, with permeability decline caused by CO2–brine–rock interactions becoming significant. In addition, miscible CO2 flooding has been carried out for rocks with similar permeabilities but different wettabilities and different pore-throat microstructures in order to study the effects of wettability and pore-throat microstructure on formation damage. Reservoir rocks with smaller pore-throat sizes and more heterogeneous pore-throat microstructures were found to be more sensitive to asphaltene precipitation, making these less attractive for CCUS reservoirs. However, rocks with larger, more connected pore-throat microstructures became less water wet due to asphaltene precipitation to pore surfaces, ultimately leading to a lower pore volume in which CO2 can be stored. Taken together, there may be a case for not simply injecting CO2 in CCUS operations, but alternating the CO2 injection with injection of water in order to stabilise CO2 flow and reduce formation damage by asphaltene precipitation.

How to cite: Wang, Q., Paul, G., and Piroska, L.: Quantifying flow reduction during injection of CO2 into legacy hydrocarbon reservoirs for CCUS, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-9509, https://doi.org/10.5194/egusphere-egu24-9509, 2024.

15:25–15:45
Coffee break
Chairpersons: Marina Facci, Thomas Kempka
16:15–16:20
Geothermal Energy
16:20–16:40
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EGU24-14959
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solicited
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On-site presentation
Hannes Hofmann, Julie Friddell, Ingo Sass, Thomas Höding, Katrin Sieron, Max Svetina, Monika Hölzel, Robert Philipp, György Márton, Balázs Borkovits, Klára Bődi, Alen Višnjić, Tomislav Kurevija, and Bojan Vogrinčič

TRANSGEO is a regional development project that aims to explore the potential for producing sustainable geothermal energy from abandoned oil and gas wells in central Europe.  Composed of 11 partner organizations and 10 associated partners in 5 countries, TRANSGEO is developing a Transnational Strategy and Action Plan to address this technical and economic opportunity.  Our primary objective is to support rural communities and industries in the energy transition by providing tools and information that highlight sustainable redevelopment priorities and opportunities.

To reach this objective and promote the switch from fossil fuels to green energy, TRANSGEO is developing reuse procedures for five different geothermal technologies and validating them via numerical modelling, to assess their performance in repurposing existing hydrocarbon infrastructure and determine the optimal reuse conditions and configurations.  The five geothermal technologies are Aquifer Thermal Energy Storage, Borehole Thermal Energy Storage, Deep Borehole Heat Exchangers, Enhanced Geothermal Systems, and Hydrothermal Energy production.  The modelling studies focus on reference sites in our study areas, the North German Basin, the South German Molasse Basin, the Vienna Basin, and the Pannonian Basin.  Comparison of varying wellbore and reservoir parameters in the numerical modelling studies will provide input to a new online well assessment tool which will be available publicly to determine well suitability and guide planning for future reuse projects.  The online tool will be informed by a database of abandoned wells in Austria, Croatia, Germany, Hungary, and Slovenia and will include local reference data, such as geology, topography, heat demand, and utilities.  This will facilitate well reuse by matching candidate wells with local energy demand and heating networks.  Additional work on socio-economic and policy analyses will provide financial and liability information for the 5 different geothermal technologies, across the project countries.  Finally, the partnership will propose a legal policy and incentive framework to facilitate and expand reuse of abandoned wells for geothermal energy production and storage across central Europe.

TRANSGEO is co-funded by the European Commission’s Interreg CENTRAL EUROPE programme.

How to cite: Hofmann, H., Friddell, J., Sass, I., Höding, T., Sieron, K., Svetina, M., Hölzel, M., Philipp, R., Márton, G., Borkovits, B., Bődi, K., Višnjić, A., Kurevija, T., and Vogrinčič, B.: TRANSGEO - Transforming abandoned wells for geothermal energy production, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-14959, https://doi.org/10.5194/egusphere-egu24-14959, 2024.

16:40–16:50
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EGU24-3864
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ECS
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Highlight
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On-site presentation
Annelotte Weert, Francesco Vinci, David Iacopini, Paul van der Vegt, Stefano Tavani, and Kei Ogata

The West Netherlands Basin, which has a long history in exploration as a former prosperous hydrocarbon province, is currently a geothermal hotspot. Being exploited since the 1950’s, most of its oil and gas fields are now in their final phase of production. In the past decade, interest shifted to sustainable energy sources. The geothermal industry in the area is developing quickly, helped by the legacy of the hydrocarbon industry: a wealth of publicly available seismic and well data. Currently, the area has 14 realized, and at least 3 projects in the development phase, with the Late Jurassic Nieuwerkerk Formation being the main target.

Conversely to petroleum systems, in which anticlines are the preferential target for hydrocarbon exploration, synclines are the most suitable sites for geothermal exploration. They offer higher temperatures with respect to the limbs and anticlines, and possible remaining hydrocarbons are not expected to be located inside the central portions of the synclines.

The West Netherlands Basin is a former rift basin that developed during the Mesozoic in the framework of the North Sea rift, and subsequently inverted during the Late Cretaceous. The Nieuwerkerk Formation was deposited during the last major rifting phase. Thus, the thickest packages of its fluvial-deltaic deposits are fault-controlled and commonly located in the synclines. The heterogeneity of fluvial reservoirs causes lateral and vertical quality variations in porosity, permeability and net-to-gross ratios. With the hydrocarbon industry focussing on the stratigraphic highs, there is only limited well data available for the central portions of the synclines.

With reprocessed 3D seismic data, our study uses an image processing approach, coupling traditional amplitude mapping with seismic attributes. This will help to reconstruct the evolution of the fluvial architecture of the Nieuwerkerk Formation over time. By tying the seismic with well data, a better prediction of the quality of the sandy bodies per location can be made. These results can be implemented in de-risking geothermal well planning across fluvial reservoirs in inverted rift basins.

How to cite: Weert, A., Vinci, F., Iacopini, D., van der Vegt, P., Tavani, S., and Ogata, K.: From hydrocarbons to geothermal energy: a case study from the Dutch subsurface, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-3864, https://doi.org/10.5194/egusphere-egu24-3864, 2024.

Modelling and Simulation
16:50–17:00
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EGU24-18605
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On-site presentation
Claude Gout, Marie-Christine Cacas-Stentz, Adriana Traby, and Nathalie Collard

The dynamics of sedimentary basins is a complex combination of synchronous generally non-linear processes. In these natural systems, fluids migration and associated transfers play a fundamental role, even more so as they represent resources that are or may become essential for human societies. One way of assessing the potential of sedimentary basins is to model their past behaviour numerically.

Basin models have been developed since the 1990s for the needs of the oil industry, with the initial aim of assessing the thermal history, i.e. the maturation and expulsion of hydrocarbons from source rocks with variable kinetics and initial composition. These models are used for hydrocarbon prospect assessment in a wide range of sedimentary basins. They have evolved with the integration of the simulation of compaction mechanisms and fluid migration by Darcean single-phase or multi-phase flows. Still with an operational objective in mind, one of these models has been extended to simulate the transport of thermal energy and chemical elements in fluids, thereby helping to assess the geothermal and large-scale storage potential of a basin. The explicit representation of faults and unconformities, as well as the calculation of seal or reservoir formation fracturing as a function of fluid pressures, enables the plumbing system to be represented on a basin scale. In this network of drains, single- or multiphase fluids carrying compounds can interact with the rocks, according to the principles of reactive transport. Some of these simulations are being experimented using AI techniques. In these digital experiments, elements tracking could be a true added value for basin’s dynamics understanding.

A coupled simulation of this kind, combining conductive and advective thermal physics, mechanics (particularly of porous media), the hydraulics of multiphase fluids in porous media, chemistry of reactive transport and even the impact of bioactivity on basin’s fluids, representing geological processes in the subsurface on a large scale, makes it possible to quantify mass and energy transfers in the past. The result is a physically balanced model of the current spatial distribution of pressure, stress, temperature, mass, solid or fluid elements.

These results can be useful both in economic applications for first-order assessment of the resources of any sedimentary basin and in the scientific field for defining the boundary conditions of more specialised models. Initial experiments demonstrating the use of multiphysics models on a basin scale for CCS applications and geothermal energy assessment will be shown.

How to cite: Gout, C., Cacas-Stentz, M.-C., Traby, A., and Collard, N.: Modelling dynamics of sedimentary basins: using geological history to predict subsurface activities at large-scale, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-18605, https://doi.org/10.5194/egusphere-egu24-18605, 2024.

17:00–17:10
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EGU24-22365
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ECS
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On-site presentation
Waqas Hussain and Andrea Bistacchi

Seismic data integration plays a pivotal role in enhancing the capabilities of geological modelling

software. Our current research focuses on the improvement of seismic interpretation tools within the

PZero software in the framework of the Geosciences IR project lead by the Italian Geological

Survey GitHub - andrea-bistacchi/PZero. The objective is to seamlessly incorporate seismic data

into the geological modelling workflow, enabling more comprehensive and accurate models of

subsurface structures.

The initial phase of our work involved using various libraries to import and analyze seismic

datasets, either 2D or 3D within the PZero framework. We have successfully achieved the

importation of SEGY files into PZero, marking a significant milestone in our efforts. Integrating

seismic data is a crucial step that sets the foundation for constructing detailed geological models,

allowing us to enhance our understanding of subsurface geological features.

Soon, our research trajectory aims to develop advanced algorithms for stochastic simulation tailored

explicitly for modelling clastic sedimentary alluvial plains. The ongoing work includes developing

advanced stochastic simulation algorithms tailored for modelling clastic sedimentary environments,

relevant to both conventional energy resources and emerging sustainable energy storage solutions.

These advancements in seismic data integration and simulation within PZero will significantly

contribute to the field of reservoir modelling. They provide a robust framework for predicting the

behavior of subsurface energy storage systems, which is pivotal in the transition to a low-carbon

energy future.

How to cite: Hussain, W. and Bistacchi, A.: Advancements in Seismic Data Integration and Stochastic Simulation for Geological Modeling in PZero, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-22365, https://doi.org/10.5194/egusphere-egu24-22365, 2024.

Green Gas and Energy Storage
17:10–17:20
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EGU24-5508
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ECS
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On-site presentation
Mayukh Talukdar, Chinmaya Behera, Niklas Heinemann, Johannes Miocic, and Philipp Blum
To ensure system security and flexibility, storing excess renewable energy as hydrogen is considered an integral component of future energy systems. Cyclic underground hydrogen storage (UHS) with injection production cycles is planned to meet energy demand until new subsurface sites are prepared for storage. To avoid geomechanical risks caused by dynamic pressure fluctuations during cyclic storage, cushion gas is stored in such reservoirs. Cushion gas requirements for sites are still unknown. Therefore, in this study, we calculate the cushion gas requirement of various hydrogen storage sites using reservoir properties.
 
Hydrogen requires less cushion gas by volume than methane. Cushion gas volume in UHS sites varies with the initial reservoir pressure, gas flow rate, well tubing size, and erosional velocity. Cushion gas requirement decreases with increasing reservoir pressure, increasing gas flow, increasing well tubing size, and decreasing erosional velocity. In the studied sites, cushion gas volume ranged from a few % (0-5%) to 99% of the total gas volume. Shallow sites cannot store much hydrogen because of the high cushion gas %. On the other hand, sites deeper than 1100 m are unsuitable owing to insufficient structural trapping and enhanced biogeochemical reactions. Considering these factors, we report the optimum cushion gas volumes for various underground storage sites worldwide.

How to cite: Talukdar, M., Behera, C., Heinemann, N., Miocic, J., and Blum, P.: Cushion gas requirements for hydrogen storage in global underground gas storage facilities, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-5508, https://doi.org/10.5194/egusphere-egu24-5508, 2024.

17:20–17:30
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EGU24-16266
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ECS
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On-site presentation
Russier Emma, Géraud Yves, Hauville Benoît, Tarantola Alexandre, Beccaletto Laurent, and Diraison Marc

Geological characterization of the “Fonts-Bouillants” helium discovery - France

Russier E1,2, Géraud Y2, Hauville B1, Tarantola A2 ,Beccaletto Land Diraison M1

1 45-8 ENERGY, France

2 GeoRessources, University of Lorraine, France

3 BRGM, F-45060, Orléans, France

 

ABSTRACT

Helium is essential for the manufacturing of many of our daily commodities such as optical fibres, computers or cell phones (semiconductors and processors), medical use (MRI scanners) or in other more specific applications such as airlifts, leak detection, gas chromatography or diving. Nowadays, Europe imports 100% of its helium needs from overseas and is facing regular shortages, reason why 45-8 Energy embarked five years ago on helium exploration and production in Europe.

 

Helium is a noble gas mostly coming from the natural radioactive decay of Uranium and Thorium contained in the crust and the basement. Its migration and accumulation are strongly linked to a vector fluid that can be CO2, N2, CH4 or water. Helium and its vector fluids are then trapped and sealed in a rock reservoir.

 

The Fonts-Bouillants area is located at the southern edge of the Paris Basin at the vicinity of the French Massif Central and Limagne rift. The 45-8 Energy project aims to jointly produce He and CO2 from a gas which is naturally seeping through the major Saint-Parize fault (SPF).  Geological origin and migration pathway of He are therefore key questions to define the exploration guide, in particular to locate production wells to produce the seeping gas and process it. A multidisciplinary approach involving geology, geophysics, petrophysics and geochemistry has therefore been deployed.

 

Because geological context was hardly documented in this area, a wide range of geophysical data were acquired or reprocessed and coupled with field geology to build a regional geological model. The initial geological model was considerably updated and a hidden and thick Late Palaeozoic depocenter was especially highlighted below the Mesozoic series. Well data in nearby analogous basins as well as outcrops enabled rock collections to conduct petrophysical and geochemical characterization. The main reservoirs discovered currently are in Triassic and Jurassic sandstones, and fault like Saint-Parize fault acted as barrier and drain. 

Our outcrops petrophysical and geochemical study highlight the importance of Late Palaeozoic basin for the helium system:

  • As a potential rock source, with higher U-Th concentrations (3-13.5, 8-24 ppm) than typical crustal U-Th concentrations (1.8 and 7.2 ppm, [1]).
  • As a potential migration pathway and reservoir, with sandstones and conglomerates porosity higher than 20% and permeability higher than 100 mD.

 

Finally, gas sampling was performed in local natural springs, but also during well testing conducted in shallow boreholes which have encountered gas bearing reservoirs in the Mesozoic along the SPF. Helium generation system was modelled with geochemical data from the rocks and the fluids and from the volumetric capacity of the Palaeozoic basin.

 

Keywords: Helium exploration, Geophysics, Petrophysics, Geochemistry

Themes: Helium exploration

 

References:

[1] Krauskopf, K. B., & Bird, D. K. (1967). Introduction to geochemistry (Vol. 721). McGraw-Hill New York.

 

How to cite: Emma, R., Yves, G., Benoît, H., Alexandre, T., Laurent, B., and Marc, D.: Geological characterization of the “Fonts-Bouillants” helium discovery - France, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-16266, https://doi.org/10.5194/egusphere-egu24-16266, 2024.

Miscellaneous Hydrocarbon Developments
17:30–17:40
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EGU24-2449
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On-site presentation
Yen-Yu Chen and Ying-Ju Chang

Kerogen is typically categorized in three types: type I is associated with lacustrine, type II associated with marine, and type III associated with terrestrial sources, respectively. The Kerogen type is a crucial factor affecting oil-generative properties as it significantly influences the initiation and potential for hydrocarbon generation in source rocks. Geoscientists traditionally use Rock-Eval pyrolysis to determine kerogen types, maturity, and pyrolysis reaction temperature (Tmax), and calculate hydrocarbon potential, essential factors in assessing oil reserves and understanding the oil window. Such method, however, has insufficient resolution and is time-consuming. In this study, we employ a temperature-dependent infrared (IR) spectroscopy method to precisely determine kerogen type, maturity, and Tmax. Specifically, our IR spectroscopy is combined with a numerical analysis model developed for the analysis of various organic matter samples. Through measurements of the IR spectra of samples at different temperatures (Heating-FTIR), we determine the maximum sedimentary burial temperature and the pyrolysis Tmax of kerogen. By applying the conversion formula by Shibaoka & Bennett (1977), (R0)a=Ra+btI*exp(cTm), we derive a virtual vitrinite reflectance, which is strongly correlated with our IR spectroscopy results, with insights into the maturation. This Heating-FTIR technique is a valuable tool for petroleum geology, facilitating the assessment of oil potential and maturity. Future refinement of the numerical model and improvement of the instrumentation are required to apply this technique to broader fields, such as sedimentary temperature for ancient geothermal gradient with better understanding of the sedimentary history.

How to cite: Chen, Y.-Y. and Chang, Y.-J.: Evaluation of Oil Source Rocks Using Temperature-dependent Infrared Spectroscopy, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-2449, https://doi.org/10.5194/egusphere-egu24-2449, 2024.

17:40–18:00

Posters on site: Wed, 17 Apr, 10:45–12:30 | Hall X4

Display time: Wed, 17 Apr 08:30–Wed, 17 Apr 12:30
Chairpersons: Thomas Kempka, Marina Facci, Anne Pluymakers
Carbon Capture and Underground Storage
X4.140
|
EGU24-362
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ECS
Francyne B. Amarante, Juliano Kuchle, and Mauricio B. Haag

Global warming poses a major challenge that humanity will face during the 21st century, requiring a significant reduction in anthropogenic CO2 emissions to mitigate the escalating global temperature. Several governments worldwide, including Brazil, have committed to achieving net-zero CO2 emissions by 2050, which will be impossible without Carbon Capture, Utilisation and Storage (CCUS) deployment. Ranked 12th globally in CO2 emissions (and 1st in South America), Brazil is in the early stages of studying CCUS. At present, CCUS efforts in the country primarily revolve around enhanced oil recovery, with limited exploration of CO2 injection in alternative geological settings. A total of 31 sedimentary basins span Brazilian territory, encompassing an area of approximately 6.4 million km2, 75% of which is situated onshore. The potential for CO2 storage in saline aquifers is gaining attention globally, proving a successful and effective approach in various sites. In this work we combine the available surface (geological maps, roads, and gas pipelines) and subsurface data (seismic lines and borehole data) to assess the logistics and feasibility of utilizing saline formations in onshore intracratonic basins as CO2 sinks, aiming to enable Brazil to reach net-zero CO2 emissions by 2050. Previous studies indicate that the Parnaíba, São Francisco, Amazonas, and Paraná basins present saline formations with favorable characteristics for CO2 injection, such as adequate depths, porosity, and permeability. Building upon prior research, we introduce the onshore portion of Espírito Santo Basin to the list of potential sinks, where the target saline aquifer is the pre-salt Mucuri Formation. Results show that greenhouse gases emissions from industrial processes are notably higher in the southeast region of Brazil. Within this region, two formations exhibit considerable potential for carbon sequestration in saline aquifers: (i) the Mucuri Formation, located in the onshore Espírito Santo Basin, reaching 350 m of thickness and shallowest depths of about 950 m, and (ii) the Rio Bonito Formation, in the proximities of the São Paulo state, with over 100 m of thickness and shallowest depths of about 650 m. For large-scale projects, CO2 transport in the region can be accomplished using the available infrastructure and the available gas pipelines, while smaller-scale research projects can utilize trucks, rail, and ships. Brazil's untapped potential for CCUS presents a unique funding opportunity from the private sector, marking a crucial step toward sustainable and impactful climate action.

How to cite: B. Amarante, F., Kuchle, J., and B. Haag, M.: Towards net-zero: assessing the carbon storage potential of onshore saline aquifers in Brazil, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-362, https://doi.org/10.5194/egusphere-egu24-362, 2024.

X4.141
|
EGU24-12846
Jyh-Jaan Steven Huang, Yao-Ming Liou, Arata Kioka, and Tzu-Ruei Yang

In the context of Carbon Capture and Storage (CCS), the porosity of potential storage formations is a critical factor. Our study explores this aspect using computed tomography (CT) to assess how different scanning resolutions impact the accuracy of porosity measurements. We employed three CT systems - Geotek RXCT (resolution ~20-150 μm), Bruker 1272 (resolution ~5 μm), and DELab μCT-100 (resolution ~9 μm) - to scan sandstone cores of varying porosities. The aim was to identify an optimal scanning resolution that balances detail with practicality for CCS evaluations.

This research addresses the challenges in high-resolution CT scanning, such as denoising effects that can alter accuracy, and the complexities of thresholding segmentation across various systems. Additionally, we examined the partial volume effect, crucial for interpreting pore sizes and distributions accurately.

Our preliminary results suggest that scanning resolution significantly affects the perceived porosity. Different resolutions uncover diverse aspects of pore structure, highlighting the importance of choosing an appropriate resolution. Advanced image processing techniques, including effective denoising and accurate thresholding, are vital for reducing errors in porosity measurement.

The study provides valuable insights into the use of CT scanning for CCS applications, emphasizing the need for a balanced approach in resolution selection and sophisticated image processing. These findings are instrumental in enhancing the reliability of geological evaluations for potential CCS sites, contributing to the broader efforts in carbon storage and climate change mitigation.

How to cite: Huang, J.-J. S., Liou, Y.-M., Kioka, A., and Yang, T.-R.: Exploring the Relationship between CT Scanning Resolutions and Sandstone Porosity for CCS Applications, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-12846, https://doi.org/10.5194/egusphere-egu24-12846, 2024.

X4.142
|
EGU24-16404
Effects of Thermal Cycling on Sealing Ability of Sealant Surrounding Steel Pipe for CCS Applications
(withdrawn)
Anne Pluymakers and Kai Li
X4.143
|
EGU24-17184
Thomas Kempka and Michael Kühn

Natural gas storage is currently considered as one key pillar of the EU strategy to ensure security of energy supply. In view of CH4 storage, Oldenburg [1] demonstrated in a theoretical study that using CO2 as cushion gas instead of CH4 has the advantage of increasing natural gas storage capacities of geologic reservoirs by up to 30 %. This is due to CO2 undergoing a significant density change when its’ critical pressure is exceeded during CH4 injection. Kühn et al. [2] investigated a comparable scenario with CH4 gas storage in a closed cycle with CO2 in one reservoir to temporarily store and reuse wind and solar energy. However, the potential qualitative degradation of the stored CH4 due to mixing with the CO2 cushion gas has not yet been sufficiently addressed in terms of the impact of the modeller’s choice of diffusion coefficients. Hence, the present study focuses on a quantitative assessment of the mixing behaviour of CH4 and CO2 under consideration of dynamic binary diffusion coefficients in a reference numerical simulation benchmark [1,3]. The TRANSPORTSE numerical simulator [4,5] is used with dedicated measures to mitigate the initially high numerical dispersion, introduced by the benchmark’s relatively coarse grid discretisation. The simulation results show that the mixing region is substantially reduced if dynamic binary diffusion coefficients are applied instead of a global constant for both gas components. Consequently, it is demonstrated that previous numerical assessments of natural gas storage with a carbon dioxide cushion gas overestimate the simulated CH4-CO2-mixing area, and thus the calculated mixing losses. Hence, combined gas storage of CH4 and CO2 is more efficient than expected so far.

[1] Oldenburg, C. M. (2003) Carbon Dioxide as Cushion Gas for Natural Gas Storage. Energy Fuels 17(1), 240−246. https://doi.org/10.1021/ef020162b

[2] Kühn, M., Nakaten, N. C., Streibel, M., Kempka, T. (2014): CO2 Geological Storage and Utilization for a Carbon Neutral “Power-to-gas-to-power” Cycle to Even Out Fluctuations of Renewable Energy Provision. Energy Procedia, 63, 8044-8049. https://doi.org/10.1016/j.egypro.2014.11.841

[3] Ma, J., Li, Q., Kempka, T., Kühn, M. (2019) Hydromechanical Response and Impact of Gas Mixing Behavior in Subsurface CH4 Storage with CO2-Based Cushion Gas Energy & Fuels 33 (7), 6527-6541. https://doi.org/10.1021/acs.energyfuels.9b00518

[4] Kempka, T. (2020) Verification of a Python-based TRANsport Simulation Environment for density-driven fluid flow and coupled transport of heat and chemical species. Advances in Geosciences, 54, 67-77. https://doi.org/10.5194/adgeo-54-67-2020

[5] Kempka, T., Steding, S., Kühn, M. (2022) Verification of TRANSPORT Simulation Environment coupling with PHREEQC for reactive transport modelling. Advances in Geosciences, 58, 19-29. https://doi.org/10.5194/adgeo-58-19-2022

How to cite: Kempka, T. and Kühn, M.: Geologic CH4 storage with CO2 cushion gas: using dynamic binary diffusion coefficients instead of a global constant in numerical simulations is more precise and results in lower mixing losses, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-17184, https://doi.org/10.5194/egusphere-egu24-17184, 2024.

X4.144
|
EGU24-13835
|
ECS
Louey Tliba, Afif Hetnawi, Farad Sagala, Robert Menzel, Paul Glover, and Ali Hassanpour

In recent years there has been rapid development of nanoparticles (NPs). Nanoparticles can be used both as a probe into restricted spaces, such as the pores within a reservoir rock, and as tools for altering wettability or deliberately blocking pore throats to enhance fluid movement in less connected pores. Silica nanoparticles can have functional surfaces allowing them to react specifically to oils or water. Nanoparticles can be used to enhance oil production by releasing oil on mineral surfaces and improving fluid flow. However, they also have the potential for improving CO2 flow in CCUS reservoirs while enhancing the pore volume available for CO2 storage. In this paper we evaluate the performance of different non-functionalised and functionalised nanoparticles for enhancement of oil production, CO2 emplacement and gas flow. Different forms of silica NPs have been made, either unfunctionalized, or functionalised with branched amino-based polymer (hydrophilic) or a silane-based agent (hydrophobic). Their stability has been characterised using a range of laboratory methods. The microscopic performance of the nanoparticles has been measured using contact angle measurements. Their ability to enhance oil production and CO2 emplacement has been tested using imbibition and drainage experiments. 

The contact angles, measured in the presence of brine, no modified silica NPs, branched amino-based polymer (hydrophilic) modified silica NPs and silane-based agent (hydrophobic) modified silica NPs showed contact angle values of approximately 110°, 116°, 124°, and 136°, respectively. These results show that introduction of nanofluids led to a change in substrate wettability from water-wet to strongly water-wet. Notably amongst the tested nanoparticles the Silane-based NPs demonstrated the highest hydrophilic surface. The spontaneous imbibition tests conducted on various sandstone cores revealed that silane-based NPs yielded the highest oil recovery rates among the tested NPs. Specifically, these nanoparticles showed an approximate 12% and 50% enhancement in oil recovery compared to non-modified silica nanoparticle, and branched amino-based polymer (hydrophilic) modified silica NPs. In summary, nanofluids have been shown to substantially improve the wettability alteration of the rock surface from oil-wet to water-wet, which can lead to improve the volume and flow characteristics of legacy CCUS prospects. Our future plan is to investigate the enhancement of carbon dioxide (CO2) solubility in brine through the utilization of the prepared nanoparticles, with the objective of advancing carbon capture technologies.

How to cite: Tliba, L., Hetnawi, A., Sagala, F., Menzel, R., Glover, P., and Hassanpour, A.: Characterising functionalised nanoparticles for improving fluid flow for CCUS in legacy hydrocarbon reservoirs , EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-13835, https://doi.org/10.5194/egusphere-egu24-13835, 2024.

Fractures and Numerical Methods
X4.145
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EGU24-1674
|
ECS
Hager Elattar, Richard Collier, and Paul W.J. Glover

Abstract: Fractured carbonate reservoirs are of great importance in the oil industry due to their significant role in global oil reserves and complex nature, where the majority of these reservoirs are naturally fractured, making them complex and challenging for oil recovery. The detection and characterization of fractures are essential for understanding the reservoir's petrophysical properties and hydrocarbon recovery potential as they play a critical role in reservoir performance. In this paper we have used 3D seismic from the Razzak field in the Western Desert, Egypt, with a specific focus on the Alamein dolomite reservoir. The reservoir holds significance due to its prolific oil-bearing nature, and featuring widespread lateral distribution in the northern Western Desert. Additionally, its contribution to an active Mesozoic petroleum system emphasizes its importance. Using Petrel software, the Alamein top and visible faults were identified, leading to the creation of a structural map illustrating the WSW-ENE axes of the Alamein's structural culminations in the southern part of the horst block. Owing to an extensional force during the Jurassic period with a NE-SW orientation, resulting from rifting, was evident, marked by the formation of normal faults associated with the opening of the Neotethys in the NE-SW direction. In the interpretation of 3D seismic data for Alamein dolomite reservoir, only one major listric normal fault was identified. However, the presence of minor faults or fractures, not easily discernible with conventional seismic techniques, is plausible. To address this, volume attributes were applied to detect subtle changes in seismic properties: (i) the curvature operation calculated the dip and azimuth angles, aiding in identifying structural complexities like faults and fractures, (ii) the maximum curvature value highlighted areas of steeply dipping or folded structures, (iii) Edge detection emphasized sharp boundaries, yet no hidden fractures or minor faults were revealed. The variance attribute yielded limited information, but Ant tracking on the variance cube effectively identified hidden minor faults and fractures. Incorporating the Ant track attribute into FRACPAQ software provided an objective methodology for quantifying fracture patterns, revealing NW-SE-oriented fracture segments in contrast to the WSW-ENE orientation of the major fault. Consequently, seismic attributes will unveil concealed fractures, and the application of FRACPAQ will prove effective in furnishing data on fracture orientation and length statistics.

Key words: FracpaQ; seismic attributes; fractured carbonate; Razzak field

How to cite: Elattar, H.A., Collier, R., and Glover, P. W. J.: Using FracPaQ and seismic attributes to assess seismic scale fractures in carbonate reservoirs, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-1674, https://doi.org/10.5194/egusphere-egu24-1674, 2024.

How to cite: Elattar, H., Collier, R., and Glover, P. W. J.: Using FracpaQ and seismic attributes to assess seismic scale fractures in carbonate reservoirs, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-1674, https://doi.org/10.5194/egusphere-egu24-1674, 2024.

Geothermal
X4.146
|
EGU24-7761
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Highlight
Johannes Miocic, Jan Drenth, and Pieter van Benthem

To meet the climate targets outlined in the Paris Agreement, European Green Deal, and the goal of reducing dependence on fossil fuel imports per the REPower EU Action, decarbonizing and reducing energy consumption in the heating and cooling sector is imperative. This sector, a major contributor to household energy use, plays a pivotal role in achieving sustainable energy goals.

Geothermal energy, particularly through geothermal doublets, stands out as an ideal solution for supplying energy for space heating and cooling. However, the inherent risks associated with fluid exchange with the subsurface make it scientifically or politically challenging in certain areas. Addressing this concern, deep borehole heat exchangers function as closed-loop systems, eliminating fluid exchange with the subsurface.

In this study, we explore the feasibility of repurposing existing oil and gas wells in the Northern Netherlands as deep coaxial borehole heat exchangers to provide heat to local communities. Utilizing analytical solutions, we calculate the thermal power output of 365 gas wells suitable for retrofitting. These wells exhibit bottom hole temperatures exceeding 80°C, capable of delivering temperatures above 60°C or thermal powers exceeding 800 kW, depending on flow rate and inflow temperature.

Our analysis includes assessing the proximity of well locations to high-density heat demand neighborhoods within a 6 km radius, facilitating the provision of supply temperatures for future local heat district networks. Notably, heat loss from well to neighborhood generally remains below 2°C, ensuring sufficient heating power supply to nearby residential areas. Several well clusters demonstrate significant heat over-supply, suggesting the potential for transporting excess heat to more distant locations. In cases where heat supply from wells is too low, in particularly in neighbourhoods with very low building efficiency rating (<E), heat pumps can be utilised to supply the needed energy.

Our findings indicate that repurposing existing hydrocarbon wells as coaxial heat exchangers offers a viable option for providing low-carbon heating to numerous residential areas in the Northern Netherlands. However, the geographical distribution reveals that not all high heat demand neighbourhoods have well sites in proximity, underscoring the importance of implementing a diverse heat supply strategy.

How to cite: Miocic, J., Drenth, J., and van Benthem, P.: Reutilising hydrocarbon wells as deep heat exchangers to decarbonise heating in the Northern Netherlands , EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-7761, https://doi.org/10.5194/egusphere-egu24-7761, 2024.

X4.147
|
EGU24-17674
|
ECS
Marina Facci and Antonio Galgaro

Since the end of the XIX century, many wells have been drilled worldwide for both Oil & Gas exploration purposes. Most of them are now abandoned and subjected to mining closure because exhausted or sterile. In the new epoch of energy transition scenario, the possibility to adapt and reuse these existing boreholes to exploit geothermal energy seems very promising. In fact, considering that approximately 40% of the total costs for a new geothermal project are devoted to drilling activity, the possibility of repurposing abandoned oil and gas wells offers a wide range of applications and exploitation of underground heat uses. The drilled borehole available data (e.g., underground temperature, lithology) provide helpful information about the sub-surface reservoirs, reducing the mining risk level, and wells allow direct access to the sub-surface heat energy. However, to develop a commercially viable geothermal power/thermal generating system, one must consider several factors, i.e., available prospecting, drilling and reservoir technologies, energy costs in the area, and resource durability.

This research aims to analyze the potential and feasibility of deep closed-loop systems solutions for heat and power energy production in Italy, in areas characterized by both normal and anomalous geothermal gradients and the distribution of available abandoned oil and gas wells. A prominent result is the development of a workflow leading to the feasibility assessment of deep closed-loop systems development, based on the identification of suitable abandoned O&G wells through the geological and thermal underground characterization and wells construction characteristics (diameter, depth, borehole material). Furthermore, a sensitivity analysis of the main parameters affecting most of the retrofitting of abandoned wells for geothermal purposes is performed thanks to thermal FEM modelling.

Finally, identifying the possible end-users in a suitable case study area, this research work provides preliminary insights into the quantity of thermal energy and electric power that this technology could produce.

How to cite: Facci, M. and Galgaro, A.: Numerical sensitivity analysis of energy performance of geothermal deep closed loop heat exchangers derived from the reuse of abandoned oil and gas wells, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-17674, https://doi.org/10.5194/egusphere-egu24-17674, 2024.

Miscellaneous
X4.148
|
EGU24-20142
Xinle Li and Qilu Xu

With the advancement of exploration theory and technology, deep and ultra-deep carbonate rocks have gradually become an important new field for the development of oil and gas resources. High-quality carbonate reservoirs have become the focus of attention for oil and gas exploration and research in deep and ultra-deep fields. The Tarim Basin is the largest intracontinental oil and gas basin in China. The thick carbonate strata developed in the Lower Paleozoic are the main layers for oil and gas exploration, and the Ordovician carbonate strata are the main oil and gas producing layers. The predecessors have studied the tectonic evolution, sedimentary background and rock types of the Ordovician in the Tarim Basin. Combined with the analysis of the sedimentary thickness, lithology distribution and seismic profile structure of the Early Ordovician, it is believed that the Lower Ordovician sedimentary period inherited the Cambrian sedimentary pattern and transformed it into a gentle slope sedimentary background with a 'uplift-sag 'pattern, with obvious differentiation. Under the sedimentary background of the gentle slope of the Penglaiba Formation, the three paleo-uplifts of southwestern, northern and central Tarim are inherited geomorphological highs, and the inner gentle slope tidal flat facies is developed. The thickness of the stratum is obviously thinner, and it is mainly developed to represent the tidal flat environment. The periclinal part around the paleo-uplift is the middle gentle slope, which is characterized by dolomite and limestone interbeds. The proportion of granular rocks is high, which is a favorable development area for granular beaches. In this study, the deep drilling cores of the Lower Ordovician Penglaiba Formation in the central Tarim Basin were taken as the key research object, and the lithofacies, reservoir characteristics and dominant reservoir control factors of dolomite reservoirs were systematically analyzed by using macro-micro, qualitative-quantitative reservoir petrology analysis methods. Through research, it is clear that the rock types of the Lower Ordovician Penglaiba Formation in the central Tarim Basin are mainly crystalline dolomite and ( residual ) granular dolomite, and also contain a small amount of limestone, siliceous rocks and transitional rocks. There are various types of reservoir space, mainly including non-fabric selective dissolution pores, intercrystalline pores and various fractures. Combined with previous studies on the genesis and diagenetic evolution of the Lower Ordovician dolomite in the Tarim Basin, it is considered that the development of high-quality dolomite reservoirs in the Lower Ordovician Penglaiba Formation in the central part of Tarim Basin is controlled by many factors. It is the result of a combination of favorable sedimentary facies belts, short-term sea-level changes, exposure and dissolution, early dolomitization, and late tectonic hydrothermal adjustment and transformation.

How to cite: Li, X. and Xu, Q.: Development characteristics and controlling factors of deep dolomite reservoirs of Lower Ordovician in Tazhong area, Tarim Basin, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-20142, https://doi.org/10.5194/egusphere-egu24-20142, 2024.

X4.149
|
EGU24-800
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ECS
Varun Dev Jamwal and Ravi Sharma

Despite constituting two-thirds of the sedimentary rock volume, shales are a few of the least understood rocks. The varied depositional processes and environments give rise to complexity and anisotropy in them. Understanding unconventional resources like shales becomes crucial given their abundance in the petroleum systems and reservoirs and their potential suitability for sub-surface carbon and radioactive waste storage. Therefore, paramount significance lies in understanding the petrophysical and rock physical characteristics of shales to develop feasibility models for the sustainable use of these rock types.
 
This investigation focuses on the Barren Measures and Raniganj Formation shales in the Damodar Valley of Eastern India, which are primarily rich in clays, carbon, and iron and are of fluvio-lacustrine origin. These relatively shallow formations can be good sites for storage and sequestration as they are overlain by shaley and clayey formations acting as traps. The anisotropy in shales is even more challenging as its imponderables range from a micro to a macro scale. This changes even further with factors like organic-hosted porosity and maturity. The inherent anisotropy in shales necessitates a multiscale examination. These multiscale discontinuities, coupled with parameters like organic matter and maturity, impact the elastic properties of the rocks, as evidenced by the ultrasonic evaluations.
 
In this study, acoustic characterization of samples was conducted using a benchtop ultrasonic wave propagation setup. The samples were clustered based on their colour and observed megascopic properties. Some sandstones were also included in the study to contrast sandstones with respect to shales. The wave velocities were determined for samples subjected to progressive heating up to 200°C (gas window), and the consecutive changes in the elastic parameters and resultant wave velocities of the rock were studied. Inputs from other methods utilizing different physics, such as FE-SEM, XRD were integrated to refine our interpretation. Notable changes were seen in wave velocities, especially in clusters with elevated organic content, while the density and Vp cross plots gave a good correlation with an R2 value of around 0.7.
This study advances our understanding of the impact of temperature on the elastic properties of shales, an aspect less explored than factors like stress and pressure. Thoroughly characterizing these parameters through acoustic methods provides critical insights into shale's storage capacity, carbon sequestration potential, and additional hydrocarbon recovery, specifically with respect to the Damodar Valley shales, aiding India to offset the projected peak of 4 GT CO2 emissions to achieve the carbon neutral goal promised at COP 26 and fulfilling UN Sustainable Development Goals.

How to cite: Jamwal, V. D. and Sharma, R.: Ultrasonic Evaluation of Shales vis-à-vis Temperature: A Case Study from Permian Damodar Valley Basin, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-800, https://doi.org/10.5194/egusphere-egu24-800, 2024.

Posters virtual: Wed, 17 Apr, 14:00–15:45 | vHall X4

Display time: Wed, 17 Apr 08:30–Wed, 17 Apr 18:00
Chairpersons: Marina Facci, Anne Pluymakers, Thomas Kempka
Carbon Capture and Underground Storage
vX4.18
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EGU24-86
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ECS
hongyan li and youlu jiang

Carbon capture and storage technology is a necessary means to achieve the temperature control goal of 1.5 degrees Celsius under the background of peak carbon dioxide emissions and carbon neutrality. The storage of carbon dioxide in oil and gas reservoirs has the advantages of high safety, large storage capacity, and less additional cost. The reservoir-caprock configuration can provide favorable space for the storage of carbon dioxide geological bodies. To make clear the distribution range of geological bodies suitable for carbon dioxide sequestration, taking the middle-south section of the eastern sag of Liaohe as an example, based on the model of the ratio of mud to ground and caprock effectiveness division, the control factors of caprock sealing were analyzed by entropy weight method combined with TOPSIS method, and the effective thickness of reservoir was determined by clarifying the relationship between reservoir lithology, physical properties, oil content and electricity. The results show that the lower limit of the effective caprock mud-to-ground ratio in the sand-mud interbedding sequence is 70.6%, and the sealing ability of caprock is mainly affected by the thickness of the fault and the thickness of the caprock single layer; The two sets of caprocks in the Shahejie Formation and Dongying Formation are relatively stable, with good fault-caprock configuration sealing, and the fault juxtaposition thickness in the Shahejie Formation is characterized by "thick in the north and thin in the south"; The effective reservoirs of the Dongying Formation are distributed in the whole region, the effective reservoirs of Es1 are distributed in the north of Rongxingtun, and the distribution range is smaller than that of the Dongying Formation, while the effective reservoirs of Es3 are mainly distributed in Huangyure area at the northern end of the study area, and the distribution range is further reduced. According to the reservoir-caprock configuration, carbon dioxide storage types can be divided into three types: shallow storage type, deep storage type, and multi-layer storage type. The lower caprock is well sealed and the lower effective thick reservoir controls the deep enrichment of carbon dioxide; The lower caprock is poorly sealed, and the effective thick reservoir in the middle or upper part controls the multi-layer enrichment of carbon dioxide; The lower caprock is poorly sealed, the upper caprock is well sealed, and the upper effective thick reservoir controls the shallow enrichment of carbon dioxide. The relationship between the effective thickness of the reservoir and the sealing ability of the caprock determines the vertical distribution series of carbon dioxide.

How to cite: li, H. and jiang, Y.: Study on Reservoir-caprock Configuration for Carbon Dioxide Sequestration in oil and gas reservoirs , EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-86, https://doi.org/10.5194/egusphere-egu24-86, 2024.

vX4.19
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EGU24-3199
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ECS
Omar Mohammed-Sajed, Fraidoon Rashid, Paul Glover, Richard Collier, and Piroska Lorinczi

Recent years have seen the growth of new techniques that combine conventional stratigraphic and observational approaches to characterizing the type, scope, extent, timing and effects of diagenetic processes with petrophysical measurements of their rock microstructure. These Quantitative Diagenetic (QD) techniques can be used to predict post- and pre-dolomitisation porosities and permeabilities as well as trace the pathway of the diagenetically evolving rock through different stages of diagenesis that may turn a low-quality carbonate reservoir into a high-quality reservoir, or vice versa. While these new QD techniques are becoming useful for the characterization of hydrocarbon reservoirs, they are also extremely useful in the characterization of carbonate reservoirs for prospective CCUS use. This paper will briefly explain some of the main approaches to QD including dolomitisation prediction, petrodiagenetic pathways, reservoir quality fields, and Fracture Effect Index (FEI), before examining how they can be used to ensure that the prospective CCUS target reservoir is sufficiently well characterized that effective reservoir modelling can take place, and that the volume, flow and trapping of CO2 in the reservoir can be effectively monitored. Dolomitisation is known to be affected by the presence of CO2, with CO2 dissolving in aqueous pore fluids to form carbonic acid that directly affects porosity through dissolution and indirectly by affecting the dynamics of the dolomitisation process itself. There are two current QD methods for predicting the change in porosity upon dolomitisation. One is affected by both the direct and indirect effects, while the other is only sensitive to the indirect effects. Both the direct and the indirect effects can be plotted on a petrodiagenetic pathway. The presence of fractures is also a key aspect of how injected CO2 will flow in a CCUS reservoir. The QD parameter FEI describes the change in permeability of a rock concomitant upon a unit change in fracture porosity (i.e., what increase in flow results from a given increase on fracture porosity). This varies depending upon the degree to which fractures are connected and can be extremely useful in predicting the flow of CO2 within a fractured legacy carbonate CCUS prospect. In summary, QD approaches have the potential to provide those who need to characterise and model carbonate CCUS prospects with new and useful tools.

 

How to cite: Mohammed-Sajed, O., Rashid, F., Glover, P., Collier, R., and Lorinczi, P.:  Using Quantitative Diagenesis to characterise and understand carbonate CCUS prospects, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-3199, https://doi.org/10.5194/egusphere-egu24-3199, 2024.

Miscellaneous
vX4.20
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EGU24-8307
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ECS
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Wurood Alwan, Paul Glover, and Richard Collier

Digital rock models are becoming an essential tool not only for the modelling of fundamental petrophysical processes, but in specific key applications, such as Carbon Capture and Underground Storage (CCUS), geothermal energy exploration, and radioactive waste storage. By utilizing advanced imaging and simulation techniques, digital rocks provide indispensable insights into the porous structures of geological formations, crucial for optimizing CO2 storage, enhancing geothermal reservoir characterization, and ensuring the secure containment of radioactive waste. This abstract aims to present new advances using digital rocks to study these pressing environmental and energy challenges.

Estimating the physical properties of rocks, a crucial and time-consuming process in both the characterisation of hydrocarbon, geothermal and CCUS resources, has seen a shift from traditional laboratory experiments to the increasingly prevalent use of digital rock physics. A key requirement of many forms of pore structure image analysis is that they require binary images showing pore-space vs. non-pore space (mineral phases). These are typically obtained by thresholding grey scale SEM or X-ray tomographic images to separate the two phases. In this paper, we have adapted a 2D process-driven MATLAB model to generate synthetic porous media images, laying the foundation for simulating authentic SEM images. The objective of the computational framework outlined in this study is to train a machine-learning model capable of predicting various types of porosity. Drawing inspiration from recent advances in machine learning applied to porous media research, our approach involves the development of deep learning models utilizing Convolutional Neural Networks (CNN). Specifically, we aim to quantitatively characterize the inner structure of the 2D porous media based on their binary images through the implementation of these CNN models. This framework consists of: (i) Generating synthetic porous media images through a process-driven model, (ii) training a neural network that takes a labelled synthetic image as input and gives two types of porosity as output, (iii) whereupon the trained model can be applied to provide types of porosities for new images that are not in the training database. The generated data are divided into training, validation, and testing datasets. The training dataset optimizes CNN parameters for accuracy, the validation dataset aids in hyperparameter selection and prevents overfitting, and the testing dataset evaluates the predictive performance of the trained CNN model.

This research not only advances the understanding of fundamental geological processes but also plays a crucial role in optimizing the utilization of renewable energy sources such as geothermal and contributing to the effective management of carbon capture and storage initiatives.

How to cite: Alwan, W.S., Glover, P. W. J., and Collier, R.: Using machine learning to discriminate between mineral phases and pore morphologies in carbonate systems, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-8307, https://doi.org/10.5194/egusphere-egu24-8307, 2024.

How to cite: Alwan, W., Glover, P., and Collier, R.: Using machine learning to discriminate between mineral phases and pore morphologies in carbonate systems, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-8307, https://doi.org/10.5194/egusphere-egu24-8307, 2024.

vX4.21
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EGU24-3700
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ECS
BaiZHi Li, Nengwu Zhou, and Shuangfang Lu

Successful exploration of Permian shale gas in the Hongxing area has broadened shale gas exploration in the Sichuan Basin; however, the target layer is newly discovered, and reservoir research, which is key to shale gas exploration and development, is limited, thus restricting the screening and evaluation of the section containing the shale gas target layer. In this study, using organic carbon, whole-rock mineral analysis, scanning electron microscopy, low-temperature nitrogen adsorption, and other experimental methods, and by systematically identifying different lithofacies, we clarified the organic‒inorganic composition and microscopic pore structure characteristics of Permian shales in different phases of the Hongxing area and revealed the main factors controlling high-quality reservoirs and favorable lithofacies types for exploration. The results show that the shale in the study area mainly features six types of lithofacies: high-carbon siliceous shale (RS), high-carbon mixed shale (RM), high-carbon calcareous shale (RC), high-carbon muddy shale (RCM), low-carbon muddy shale (LCM), and low-carbon calcareous shale (LC). Organic pores are mainly present in RS, RM, RC, and RCM, while inorganic pores are dominant in LC and LCM. The pores are dominantly micropores, some mesopores are present, and very few macropores are present. Among them, the degree of micropore development is mainly affected by organic matter (abundance, maturity, and type), that of mesopores is mainly affected by clay minerals, and that of macropores is mainly affected by siliceous and clay minerals. There are obvious differences in the pore structure of different lithologies. The RS has the highest pore volume and specific surface area, with average values of 13.8×10-3 cm3/g and 21.57 m2/g, respectively, and its pore morphology is ink-bottle type, with pore diameters mainly <10 nm. The storage space of RM, RC, RCM, and LCM is moderate, with low-carbon argillaceous shale (LM) having the lowest.

How to cite: Li, B., Zhou, N., and Lu, S.: Characteristics and factors controlling Permian shale gas reservoirs in the Hongxing area, Sichuan Basin, China, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-3700, https://doi.org/10.5194/egusphere-egu24-3700, 2024.

vX4.22
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EGU24-7216
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ECS
Wei Fan and Xiankun Yang

The changes in land use/cover are essential aspects of studying the impact of human activities on the Earth's surface and global transformations. In this study, utilizing the ESRI Global Land Cover data (ESRI land cover 2020) and the China Land Cover Data (CLCD), along with historical imagery from Google Earth, a comparative analysis scheme for land use classification results was designed. The CLCD dataset was updated, leading to the creation of a land use dataset for the Pan-Pearl River Basin spanning from 1985 to 2020. This dataset was then employed for the analysis of land use changes in the Pan-Pearl River Basin over the past 35 years.The results indicate:(1) Among the seven land use types, the most significant changes in area occurred in the following order: build -up land, cropland, forest land, grassland, shrubland, waterbody, and barren. Notably, there was a substantial increase in the areas of build-up land and forest land, while cropland, grassland, and shrubland experienced significant decreases. The waterbody’area showed a slight overall increase trend.(2) The major land use types undergoing changes varied among sub-basins, with the intensity of land use change ranked as follows: Pearl River Delta region(1.9%) > Coastal rivers in southern Guangdong and western Guangxi(0.20%) > Dongjiang River Basin(0.13%) > Hanjiang River Basin(0.12%) > Xijiang River Basin(0.10%) > Beijiang River Basin(0.08%) > Hainan Island region(0.02%).(3) Within the sub-basins of the Pan-Pearl River Basin, the most significant increase was observed in the area of built-up land, exhibiting a continuous expansion trend with a total increase of 12184 km2. This increase was primarily due to the conversion of cropland, forest land, and waterbody. The most significant decrease occurred in cropland, with a total reduction of 10435 km2, mainly transitioning to built-up land and forest land. The phenomenon of built-up land encroaching on cropland was particularly prominent, especially in the Pearl River Delta region. Forest land also showed a decreasing trend, mainly attributed to cultivation and the encroachment of built-up land. The reduction in grassland area was more pronounced in the Xijiang River Basin, primarily transforming into forest land, cropland, and built-up land. The study reveals that the rapid development of socio-economics and industry, coupled with an increase in residents' consumption levels, serves as the primary driving force behind land use changes in the Pan-Pearl River Basin. Additionally, land use and management policies play a crucial role as driving factors in the region's land use changes. This research aims to provide a scientific basis for formulating policies related to the region's land resources and land management, holding significant importance for preserving ecological balance and fostering sustainable development in the basin.

How to cite: Fan, W. and Yang, X.: Land Use Change Characteristics in the Pan-Pearl River Basin in China from 1985 to 2020, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-7216, https://doi.org/10.5194/egusphere-egu24-7216, 2024.

vX4.23
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EGU24-3696
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ECS
Song Bo, Haitao Xue, and Shuangfang Lu

          It is pivotal to predict the overall composition of subsurface oil and gas reservoirs to assess their fluidity, phase behavior, and recovery potential. Recognizing the significance of n-alkanes as key constituents of mature oil and gas, this study conducted a thermal simulation experiment of gold tube hydrocarbon generation on the source rock of Gulong Sag. The experiment included comprehensive analysis and measurement of the n-alkanes components in a representative sample. Subsequently, an empirical regression evaluation formula was established to evaluate the n-alkanes composition at various maturity stages. Furthermore, a chemical dynamics model for the formation of individual n-alkanes single molecule components was developed and calibrated based on the principles of chemical kinetics. Combined with the stratigraphic burial history and thermal evolution history of the target area, the distribution and evolution characteristics of n-alkanes components in different evolutionary stages of geological conditions can be quantitatively evaluated and predicted. Moreover, the phase behavior of n-alkanes components can be determined based on the evolution characteristics of these components. Experimental results indicate that the methane yield continues to increase with temperature under both heating rates. Additionally, the yield of n-C to n-C initially reaches its maximum with the temperature increase, and subsequently decreases. Furthermore, the hydrocarbon generation characteristics of n-alkanes follow a Gaussian distribution trend. The kinetic results demonstrate that the activation energy of n-alkanes falls within the range of 190-280 kJ/mol, while the distribution of pre-exponential factors is uneven. By considering the geological conditions, it has been determined that the light component in the Gulong Sag is currently experiencing a favorable generation period, whereas the heavy component has reached its peak formation stage, with some undergoing cracking. The oil and gas produced under these geological conditions exist as single-phase unsaturated fluids within volatile reservoirs. The evaluation value of the experimental regression formula, along with the predicted value from the dynamic model, aligns well with the experimental data, providing a solid foundation for the geological application of the model. Therefore, this research serves as a stepping stone towards furthering our understanding of hydrocarbon composition prediction, as well as evaluating phase behavior, mobility, and recovery of underground oil and gas in conjunction with geological conditions. 

How to cite: Bo, S., Xue, H., and Lu, S.: Simulation experiment evaluation and chemical kinetics prediction of the composition of n-alkanes components, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-3696, https://doi.org/10.5194/egusphere-egu24-3696, 2024.

vX4.24
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EGU24-13736
The formation mechanism and enrichment patterns of H2S in Es4 of Dawangzhuang area, Chezhen Sag
(withdrawn)
Dai Han, Chunmei Dong, and Pengjie Ma