ERE1.9 | Redeploying existing oil and gas technology and modelling to benefit the development of sustainable energy resources

ERE1.9

EDI
Redeploying existing oil and gas technology and modelling to benefit the development of sustainable energy resources
Co-organized by EMRP1/GI6/SSP1
Convener: Paul Glover | Co-conveners: Holger Class, Sebastian Bauer, Thomas Kempka, Qian WangECSECS, Kai LiECSECS
Orals
| Mon, 24 Apr, 14:00–18:00 (CEST)
 
Room -2.16
Posters on site
| Attendance Mon, 24 Apr, 10:45–12:30 (CEST)
 
Hall X4
Orals |
Mon, 14:00
Mon, 10:45
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 or modelling 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.

The session also includes modelling of geological subsurface utilisation in terms of chemical or thermal energy storage as well as hydrocarbon production and storage are required to ensure a safe and sustainable energy supply.

Orals: Mon, 24 Apr | Room -2.16

Chairpersons: Thomas Kempka, Kai Li, Paul Glover
14:00–14:05
14:05–14:35
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EGU23-3408
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ERE1.9
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solicited
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On-site presentation
Andrew Kingdon, Matthew Arran, Mark Fellgett, Shahin Jamali, Henning Knauer, and Kevin Mallin

Deep geothermal heat represents a massive opportunity to provide low-carbon district heating for towns and cities. Space heating represents a large percentage of total energy use in Northern Europe; nearly 40% of all UK energy use (BEIS, 2022) is for heating, predominantly from natural gas. Global pressures on the international gas market and the urgent need to decarbonise the heating system to deliver NetZero highlight the need for identifying renewable heat sources to replace gas.

However, finding reliable high temperatures requires drilling to several-kilometres depth. Achieving sustainable heat supply, without depletion, means that wells must intersect deep permeable strata which are impossible to detect from the surface. Well prognosis is therefore heavily reliant on data from legacy drilling. Drilling is always an expensive process and any operational issues can impose significant additional costs, as rigs capable of drilling such boreholes have rental rates of many €1000s per day. Even when the drilling is completed, financial returns are slow and reaching profit takes years. Therefore, reassuring investors requires de-risking such projects through mitigating avoidable additional costs.

Digital data from wells penetrating many kilometres are needed for understanding subsurface processes. Only small numbers of deep geothermal wells have been drilled, so the best alternatives are legacy hydrocarbon exploration boreholes; these are good analogies for geothermal wells as they rely on permeability at depth. Such legacy hydrocarbon data are increasingly openly available through National Data Repositories (NDR) and/or Geological Survey Organisations. 

The EU Horizon programme funded OptiDrill project (101006964) is using legacy well data to optimise the drilling process, by linking drilling parameters with petrophysical data to understand the constraints upon the drilling processes. This will allow causes of interruptions to drilling and unnecessary down-time to be assessed and hopefully eliminated.

NDR archives have been trawled for modern drilling and logging data that admits optimal analysis. An Isolation Forest machine-learning algorithm was used to analyse Measurement-While-Drilling derived Rate-of-Penetration data and geophysical log data, identifying zones of anomalous responses quickly and without supervision. Examination of newly available daily drilling reports (DDR) data, from the NDR, allows these anomalous responses to be associated with breaks in drilling operations and their causes to be understood. This allows both refinement of the anomaly-detection algorithm for the identification of drilling problems, and differentiation between problems caused by drilling or geological issues and those caused by operational and logistical difficulties (e.g. procurement delays). Where drilling issues are identified these can be used to develop remediation strategies for future wells drilled in similar conditions, through revised drilling programmes and optimised well designs that minimise avoidable drilling operations such as unnecessary round trips etc.

How to cite: Kingdon, A., Arran, M., Fellgett, M., Jamali, S., Knauer, H., and Mallin, K.: Optimising the drilling process for geothermal wells using legacy oil field data and machine learning, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-3408, https://doi.org/10.5194/egusphere-egu23-3408, 2023.

14:35–14:45
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EGU23-8407
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ERE1.9
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ECS
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On-site presentation
Daniela Navarro-Perez, Quentin Fisher, Piroska Lorinczi, Samuel Allshorn, and Carlos Grattoni

Geothermal reservoir characterisation benefits from the oil and gas petrophysics experience in areas such as porosity and permeability estimation, rock-fluid interactions etc.. Permeability is the crucial parameter in assessing water transmissibility with geothermal reservoirs. Permeability impairment is a key worry due to rock-fluid interactions within the reservoir life cycle management. The laboratory techniques help in recreating the reservoir conditions and determining formation damage. Uncertainty increases for tight geothermal reservoirs (permeability < 1 mD), which often contain significant amounts of clay that reacts with water or ionic species during hydraulic fracturing used in Enhanced Geothermal Systems.

Clay-bearing sandstones are complex reservoirs since their clay minerals actively interact with water, causing formation damage by clay swelling and migration mechanisms. Core flooding experiments study the clay minerals' behaviour in different water conditions - e.g. salinity, electrolytes species, pH, and temperature - helping to understand the impact of clays on reservoir quality and identifying optimal conditions to reduce formation damage.

A multi-salinity experiment was undertaken to study the clay effect of three tight clay-bearing sandstones, samples A, B and C, of different reservoir provenance. Sample A has a core porosity of 18%, gas permeability of 1.28 mD, and 15.5%v/v of XRD clay minerals and kaolinite as the primary group. Sample B has a core porosity of 20.2%, gas permeability of 0.56 mD, and 37%v/v of XRD clay minerals and chlorite as the primary group. Sample C has a core porosity of 18.8%, the gas permeability of 1.95 mD, and 36.3%v/v XRD clay minerals and mica as the primary group. The experiment consisted of flooding brine with constant inflow at different salinities and monitoring the rock resistance, pressure drop, and outlet brine conductivity. High- and low-salinity batteries were flooded, ranging from 200,000-75,000 and 50,000-0 ppm NaCl respectively, at a constant room temperature of 21⁰C. In addition, the brine permeability was measured in steady- and unsteady-states techniques, and pore size distribution was NMR scanned at each run per battery.

Permeability impairment increased in all samples. Samples A (kaolinite) and C (mica) show a staggered increase in the salinity range. In contrast, sample B (chlorite) shows a peculiar upside-down trend in the low-salinity range. Clay migration was detected in the last brine runs since fines grain were released in the outflow. NMR T2 distribution shows a bimodal pore distribution for samples B and C, and the pore-throat connectivity rearranges as salinity decreases in both samples, indicating a clay swelling mechanism. The cation-exchange capacity (CEC) of samples A and C resulted in 3.7 and 3.6 meq/100g, respectively, and sample B was 71.5 meq/100g. CEC values are directly related to the clay mineral content. The highest CEC (sample B) relates to the upside-down permeability impairment with clay swelling. This investigation contributes to the geothermal reservoir characterisation in understanding how the water salinity controls the clay effect in tight clay-bearing sandstone reservoirs.

How to cite: Navarro-Perez, D., Fisher, Q., Lorinczi, P., Allshorn, S., and Grattoni, C.: Multi-salinity core flooding study in clay-bearing sandstones, a contribution to geothermal reservoir characterisation, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-8407, https://doi.org/10.5194/egusphere-egu23-8407, 2023.

14:45–14:55
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EGU23-16369
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ERE1.9
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On-site presentation
Dimitra Teza, Ryan Santoso, Nora Koltzer, Denise Degen, Tony Bennett, and Florian Wellmann

Coaxial Deep Borehole Heat Exchanger (DBHE) provides an alternative way to extract geothermal energy by circulating a working fluid without producing geofluids or performing injection processes. It can be used to avoid induced seismicity issues caused by injection operations in hydrothermal doublets or to repurpose damaged or non-productive wells. A detailed numerical model is required to accurately capture as well the thermo-hydraulic processes within the DBHE and the cooling effects in the surrounding reservoir. This numerical model is often high dimensional. For a real-time monitoring purpose and optimization study, a direct numerical simulation with this model is computationally intractable.

In this study, we use a physics-based machine learning method to reduce the computational cost of the performed forward model run. The physics-based machine learning method here is based on the non-intrusive reduced-basis method which expresses a physical solution in a linear combination of basis functions and weights. It is a model-order reduction technique that is mathematically proven to produce physically consistent predictions. The structure of the physics is maintained in basis functions and a machine learning model is deployed to calculate the weight for each basis function.

We show the advantages of using the physics-based machine learning method by applying it to the planned coaxial DBHE in Eden (Cornwall, UK). The forward simulation is performed using the open-source simulator GOLEM, a finite-element (FE) based simulator that is built within the MOOSE framework. In this study we provide a running time comparison between the FE simulations and the physics-based machine learning simulations. We will also evaluate the accuracy of the physics-based machine learning predictions towards the FE solutions. Here, we would like to emphasize the significant computational speed-up that allow us to obtain new temperature and pressure state predictions in real-time context and to perform optimization with numerous iterations.

How to cite: Teza, D., Santoso, R., Koltzer, N., Degen, D., Bennett, T., and Wellmann, F.: Physics-based machine learning for modeling thermo-hydraulic processes in a coaxial deep borehole heat exchanger, considering an explicit reservoir-wellbore representation: A case study of Cornwall, UK , EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-16369, https://doi.org/10.5194/egusphere-egu23-16369, 2023.

14:55–15:05
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EGU23-14599
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ERE1.9
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ECS
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Highlight
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On-site presentation
Marina Facci, Eloisa Di Sipio, and Antonio Galgaro

The decarbonization of communities and their energy supply is considered as a contemporary priority path forward, although it poses many challenges. In this scenario, geothermal energy can cover a pivotal role in the energy transition and in a wider spread of renewable energies. Moreover, the possibility to reuse or modifying existing wells for geothermal purposes is becoming a hot and promising topic. In Italy, there are more than 8000 abandoned/inactive on-shore wells drilled for hydrocarbon exploration subsequently abandoned either for the end of the resource (exhausted well) or for sterility (barren well). This can represent a huge opportunity for geothermal energy exploitation. The drilled borehole available data, collected during the exploration activity, provide useful information about the sub-surface reservoirs, highly reducing the mining risk level, and allowing direct and low cost access to the sub-surface heat energy.

This work aims to analyse the feasibility of the retrofitting of abandoned oil and gas wells focusing on the Italian territory, proposing a selection methodology of wells starting from raw data collection. We want to evaluate which could be the best technical solutions for the retrofitting of an inactive oil&gas well considering the closed loop geothermal options, both coaxial and deep-U heat exchangers options. We decided to concentrate on the closed loop solution for the retrofitting because of its low environmental impact due to the absence of fluid exchange with the surrounding underground, despite the lower efficiency, compared to a system that involves the extraction of fluids from the subsoil.

A database, that collects data of wells drilled since the middle of 1900, provide by public information, is used, applying a first filter by considering the following discriminant parameters: the depth (more than 1000 m), the Bottom Hole Temperature (BHT), higher than 65°C, and the nearness of possible end-users. After this operation a set of 541 wells has been obtained.  A focus on the status of the well has been performed,  such as vertical or deviated and the availability of a litho-stratigraphic data to thermally characterize the rock formations around the well.  Then, the measured temperature data was analysed to figure out the distribution of geothermal gradient and to identify different situations in terms of temperature at national scale, that could be selected later as representative case studies of high, medium and low enthalpy geothermal plant.  Moreover, the Horner plot approach have been adopted for computing equilibrium temperature at depth after drilling, obtaining the real temperatures for each well. The proximity to possible heat stakeholders was then assessed using a GIS system.

How to cite: Facci, M., Di Sipio, E., and Galgaro, A.: Energy transition and Deep Geothermal solution role: a screening procedure for the retrofitting and reuse of ex Oil&Gas wells as deep closed-loop borehole heat exchangers in Italy, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-14599, https://doi.org/10.5194/egusphere-egu23-14599, 2023.

15:05–15:15
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EGU23-10004
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ERE1.9
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ECS
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On-site presentation
Michał Wilkosz

In the past decades, boreholes were drilled all over the world for the purpose of hydrocarbon prospection. Data from these boreholes are a very valuable resource, that can be used in current geological, geothermal and hydrogeological studies. Since the process of drilling is both expensive and disturbing to the environment the possibility of incorporating data that already exists in the current studies is always worth consideration. However, in the case of older boreholes quality of data is not on par with modern standards which limits its usefulness, especially in the case of data from boreholes drilled in thin-bedded rock formations.

Resistivity logs are one of the main logs used both in hydrocarbon prospection and other applications such as geological, geothermal and hydrogeological studies. Resistivity logs measured by older generations of logging tools are characterized by significantly lower vertical resolution in comparison to logs measured by newer logging tools which affect the quality of the interpretation. However, the information averaged in the process of logging can be partially restored in the process of iterative inversion.

The focus of the presentation is on the utilization of open-source global optimization software in the process of inversion of resistivity well logs. Since inverse problems encountered in geophysics tend to be on the difficult side, relatively simple optimization schemas that often can be found in open-source software are not always giving good results. Therefore, in the presentation, a few methods that allow adapting those algorithms to the problem of inversion of well logs are discussed. The performance of the inversion procedure is validated on synthetic data and real data from the borehole where resistivity logs were measured by different generations of logging tools in the same depth intervals, which allows for comparison of the inversion results to logs measured by modern equipment.

 

The research was funded by the National Science Centre, Poland, grant number 2020/37/N/ ST10/03230.

How to cite: Wilkosz, M.: Adaptation of open-source global optimization software to the process of iterative inversion of resistivity well logs, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-10004, https://doi.org/10.5194/egusphere-egu23-10004, 2023.

15:15–15:25
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EGU23-543
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ERE1.9
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ECS
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Virtual presentation
Gagandeep Singh, Anjeeta Rani, William K. Mohanty, and Aurobinda Routray

Three-dimensional seismic data and well-log data analysis deliver complete information on the petrophysical characteristics of reservoir rock and its fluid content. The current study shows the combined interpretation of 3D seismic data and well log responses such as gamma ray, delay time (DT)- P wave and S wave, resistivity, neutron, density, and lithology logs from eight wells under the research area of Krishna-Godavari (KG) basin. The main target of the paper is focused on the prominent positive topographic features in the bathymetry data and on the porous and fractured/faulted hydrocarbon rocks. Fluid/gas migration characteristics like acoustic voids, chimneys, and turbid layers may be seen in the present mounds. Coherence, dip, curvature, and saliency attributes are used to enhance the discontinuities within the seismic volume. After then, well logs were used to identify the hydrocarbon-bearing zones. Finally, the seismic to well tie step was initiated, and the complete earth model of the given data was generated.

The goal of this paper is to describe the offshore KG basin reservoir areas, in a qualitative way using 3D seismic and well log data and its possible correlation with facies. The possible data and wells information are conjugated with other attributes, which are relatively recent methods in this field study, yet it is crucial to reducing geological uncertainty and predicting facies. The characterization of reservoirs using only the seismic volume (impedance dependent data) characteristics is difficult due to the shally environment of the area, which might obscure reservoir identification. As a result, combining a variety of techniques and data is important for better understanding geological settings and identifying meaningful geological features in the shally environment of the KG basin.

How to cite: Singh, G., Rani, A., Mohanty, W. K., and Routray, A.: Subsurface mechanical modeling of Krishna Godavari basin using petrophysical properties of the rocks by utilizing 3D seismic and well log data sets, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-543, https://doi.org/10.5194/egusphere-egu23-543, 2023.

15:25–15:35
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EGU23-9686
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ERE1.9
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ECS
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Virtual presentation
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Zhen Li, Elena Chabab, Erik Spangenberg, Judith Schicks, and Thomas Kempka

The Canadian Mackenzie Delta (MD) is a river-mouth depocentre and the second-largest Arctic delta. It exhibits high resources of prospected sub-permafrost gas hydrates (GHs), mainly consisting of thermogenic methane (CH4) at the Mallik site, which migrated from deep source rocks. The objective of the present study is to confirm the sub-permafrost GHs formation mechanism proposed by Li et al. (2022a), stating that CH4-rich fluids were vertically transported from deep overpressurized zones via geologic fault systems and formed the present-day GH deposits in the shallower Kugmallit Sequence since the Late Pleistocene. Given this hypothesis, the coastal permafrost began to form since the early Pleistocene sea-level retreat, steadily increasing in thickness until 1 Million years (Ma) ago. Observations from well-logs and seismic profiles were used to establish the first field-scale static geologic 3D model of the Mallik site. A framework of equations of state to simulate the formation of GHs and permafrost (Li et al., 2022a, 2022b) has been developed and coupled with a numerical simulator for fluid flow as well as the transport of chemical species and heat in previous studies. Here, numerical simulations using the proven thermo-hydro-chemical simulation framework were employed to provide insights into the hydrogeologic role of the regional fault systems in view of the CH4-rich fluid migration and the spatial extent of sub-permafrost GH accumulations during the past 1 Ma. The simulated ice-bearing permafrost and GH interval thicknesses, as well as sub-permafrost temperature profiles, are consistent with the respective field observations, confirming our previously introduced hypothesis. In addition, simulation results demonstrate that the permafrost has been substantially heated to 0.8–1.3 °C, triggered by the global temperature increase of about 0.44 °C (IPCC, 2022) and further accelerated by Arctic amplification from the early 1970s to the mid-2000s. Overall, the good agreement between simulations and observations demonstrates that the present modeling study provides a valid representation of the geologic controls driving the complex permafrost-GH deposit system. The model’s applicability for predicting GH deposits in permafrost settings can provide relevant contributions to future GH exploration and exploitation activities.

References

IPCC, 2022: Climate Change 2022: Impacts, Adaptation, and Vulnerability. Contribution of Working Group II to the Sixth Assessment Report of the Intergovernmental Panel on Climate Change [H.-O. Pörtner, D.C. Roberts, M. Tignor, E.S. Poloczanska, K. Mintenbeck, A. Alegría, M. Craig, S. Langsdorf, S. Löschke, V. Möller, A. Okem, B. Rama (eds.)]. Cambridge University Press. Cambridge University Press, Cambridge, UK and New York, NY, USA, 3056 pp., doi:10.1017/9781009325844.

Li, Z., Spangenberg, E., Schicks, J. M. & Kempka, T. Numerical Simulation of Coastal Sub-Permafrost Gas Hydrate Formation in the Mackenzie Delta, Canadian Arctic. Energies 15, 4986 (2022a). https://doi.org/10.3390/en15144986

Li, Z., Spangenberg, E., Schicks, J. M. & Kempka, T. Numerical Simulation of Hydrate Formation in the LArge-Scale Reservoir Simulator (LARS). Energies 15, 1974 (2022b). https://doi.org/10.3390/en15061974

 

How to cite: Li, Z., Chabab, E., Spangenberg, E., Schicks, J., and Kempka, T.: Geologic Controls on the Genesis of the Arctic Permafrost and Sub-Permafrost Methane Hydrate-bearing System in the Beaufort–Mackenzie Delta, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-9686, https://doi.org/10.5194/egusphere-egu23-9686, 2023.

15:35–15:45
Coffee break
Chairpersons: Holger Class, Qian Wang
16:15–16:35
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EGU23-11350
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ERE1.9
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ECS
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solicited
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On-site presentation
Miftah Hidayat, Jan Vinogradov, Mohammad Sarmadivaleh, Stefan Iglauer, David Vega-Maza, and Jos Derksen

Measurements of the zeta potential using streaming potential method are frequently used to characterise flows in subsurface settings owing to a broad range of applications of this petrophysical property; examples include CO2 geological storage, hydrocarbon reservoirs, geothermal sources and freshwater aquifers. Many experimental studies of the zeta potential have been carried out covering a wide range of parameters including different rock mineralogy, brine concentration and composition, and temperature to understand the impact of each parameter. The capability of the streaming potential method to be used on intact rock samples, single-/ and multi-phase flows, wide range of salinity, pressure and temperature makes the method suitable for representation of typical subsurface conditions. However, none of previous studies reported high multi-phase measurements at high pressure conditions typical for deep reservoirs. To adequately represent subsurface conditions of carbon geological storage sites, the minimum experimental pressure of 7.38 MPa and minimum temperature of 31 °C, consistent with the supercritical-CO2 (scCO2), need to be used. Obtaining stable measurements of the streaming potential under these conditions is extremely challenging. We report a detailed design of a high-pressure experimental system and experimental protocol for multi-phase streaming potential measurements that were carried out on scCO2-sandstone-brine systems at temperature of 40 °C, pressures ≤10 MPa and with a variety of aqueous solutions.

The obtained results demonstrate for the first time that the multi-phase zeta potential correlates with the measured scCO2 residual saturation and rock’s wetting state interpreted from other parameters. Moreover, our results unambiguously identify for the first time the polarity and likely magnitude of the scCO2-brine interfacial zeta potential. Our findings improve the current understanding of the complex wetting behaviour of scCO2 and provide important experimental data for numerical (surface complexation, molecular dynamics), analytical (DLVO) or combined models.

How to cite: Hidayat, M., Vinogradov, J., Sarmadivaleh, M., Iglauer, S., Vega-Maza, D., and Derksen, J.: New Insights into Underlying Mechanisms of CO2 Wettability and Residual Saturation from Laboratory Measurements of Multi-Phase Zeta Potential in Supercritical CO2-Rock-Brine Systems, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-11350, https://doi.org/10.5194/egusphere-egu23-11350, 2023.

16:35–16:45
16:45–16:55
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EGU23-9593
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ERE1.9
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On-site presentation
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Kejian Wu

One of the main challenges in soil science lies in the passage from heterogeneous soil structure to a quantified multi-scale 3D model. Here a new approach to quantify the microbial distribution relating to soil pore structure is presented. Characterising 3D microbial soil structural in digital porous media is not found and most soil process models tend to assume a homogenous spatial distribution of microbes. We measured the in situ spatial distribution of bacteria in arable soils across scales from sub-micrometers to metres and here we describe further progress to quantify and explicitly model the 3D microbial distributions, based on a stochastic Bayesian approach to predict spatial variation in the underlying bacterial intensity measure. A 3D higher order Multi-Markov chain model is introduced to model complex geometry of real soil structure and associated microbial distribution. In this study, Markov random fields are used to construct multiscale 3D Pore Architecture Models (PAM). The binary structure of PAM has been successfully used to predict multiphase flow behaviour in porous media such as hydrocarbon bearing reservoir rocks, we explore further to use such a new multi-components scheme in modelling pore structure incorporating with microbial spatial distribution, the multicomponent Markov chain model, which is a stationary multiple higher order Markov chain. The models parameterisation is based on high resolution SEM images of soil that have been prepared in a manner that preserves the microbial community information in situ. Based on the quantified 3D multiscale soil structure associated with microbial distribution components, the accurate reactive flow of microbial degradation can be simulated to predict environmental impact of microbial activates in the field. A variety of examples of structures and bacterial distribution created by the models are presented.

How to cite: Wu, K.: A new 3D multicomponent markov chain model incorporating multi-scale soil structure with microbial distribution, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-9593, https://doi.org/10.5194/egusphere-egu23-9593, 2023.

16:55–17:05
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EGU23-1627
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ERE1.9
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On-site presentation
Ziwei Bian, Zena Zhi, Xiangchun Zhang, Yiqian Qu, Lusha Wei, Yifei Wu, and Hanning Wu

Many bacteria have been proved to change physical (viscosity, wettability, and tension), and compositions of crude oil, which can make it easier for oil to be released from rock pores and achieve the purpose of improving recovery, which is called Microbial Enhanced Oil Recovery (MEOR). Our team has previously isolated six emulsified and viscosity-reducing bacteria (Bacillus. sp.) in low permeability layers (Chang 4+5 and Chang 6) of Ordos Basin. However, environmental tolerance of the strains is limited, and the components of crude oil used by the strains were also different. The combination of strains of different species and genera may enhance the effects of single bacteria, surpass the tolerance upper limit, and optimize the viscosity reduction and degradation. Therefore, in this study, it is extremely necessary to study the bacterial consortium. Two consortia were obtained and each consortium consisted of three bacterial strains and was designated as Consortium A (51+61, 61+H-1, 51+H-1; A-ALL) and Consortium B (34(2)+42, 34(2)+A-3; 42+A-3. B-BLL). The performance of the mixed strains was evaluated by the analysis of change in emulsification rate, crude oil composition, viscosity, and the tolerance (temperature, salinity, and pH) though GC-MS, rotational rheometer, and other methods. The results showed that bacterial consortiums had higher alkali resistance and could survive temperatures of 55 °C and salinity of 50 g/L in comparison to single bacterium. The emulsification rate was 22%-48%. Consortium B has better effects than Consortium A. The viscosity reduction rate of the Consortium A after 7 days was exceeded 30% as a whole, and the rate of Consortium B was more than 35%. The crude oil of Consortium B is basically non-stick to flask. Compared with single bacteria, the utilization components of crude oil to bacteria are still different, including both long chain hydrocarbons and short chain hydrocarbons. However, the proportion of long chain n-alkanes is further reduced compared with that of single bacteria, and the highest ratio is reduced by 23.81% (B-ALL). Overall, the bacterial consortium outperforms the single strain in terms of tolerance, viscosity reduction, and degradation, which further optimizes the application of MEOR.

How to cite: Bian, Z., Zhi, Z., Zhang, X., Qu, Y., Wei, L., Wu, Y., and Wu, H.: Viscosity-reducing and Biosurfactant-producing Bacterial Consortia Isolated from Low-permeability Reservoir in Ordos Basin, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-1627, https://doi.org/10.5194/egusphere-egu23-1627, 2023.

17:05–17:15
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EGU23-63
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ERE1.9
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ECS
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On-site presentation
Akinniyi Akinwumiju

With increasing global demand for oil and gas, the exploration of unconventional resource plays (shale oil and gas) continues to gain relevance. Such plays could be significant for maximising the production value in proven geological basins, allowing the exploration of a cleaner fossil fuel. Unconventional resources could play a part in the energy transition to lower-impact CO2 fuels while meeting current energy security needs.

For several decades, the UK North Sea has been a prolific oil and gas province, with numerous conventional oil and gas discoveries sourced predominantly by the Kimmeridge Clay Formation (KCF). In this study, we have used 3-D geostatistical modelling of the distribution of key geochemical and geomechanical properties for the KCF to investigate the potential of shale oil and gas plays within Quadrant 15 in the Outer Moray Firth region of the UK North Sea.

The utilized geochemical and geomechanical property logs were generated from sixteen selected drilled wells using machine learning and established property equations, while the top and base KCF structural depth maps used for modelling were created using grid- and isopach creation tools in Zetaware's Trinity software, an existing Base Cretaceous Unconformity (BCU) map of the UK North Sea and well top information from 58 wells within the study area.

The geostatistical property maps created for the KCF in Schlumberger’s Petrel software were then normalised and integrated to identity sweet spots for potential shale oil/gas exploitation, after the application of various cut-offs using standard industry thresholds for unconventional resources.

The modelling results suggest that the KCF show good potential for shale oil and gas exploitation within the central part of the Witch Ground Graben and limited areas of the Piper Shelf and Claymore-Tartan Ridge in the study area.  Further investigations on maturity, saturation and producibility will be conducted by 3-D basin modelling.

How to cite: Akinwumiju, A.: Sweet-spot mapping of the Kimmeridge Clay Formation in the UK North Sea for unconventional resource exploitation using a geostatistical modelling approach, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-63, https://doi.org/10.5194/egusphere-egu23-63, 2023.

Virtual Presentations
17:15–17:25
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EGU23-12741
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ERE1.9
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Virtual presentation
Elena Chabab, Michael Kühn, and Thomas Kempka

Inland salinisation due to the upwelling of highly mineralised deep waters formed by leaching of Upper Permian salt diapirs is a typical phenomenon in the North German Basin. In the German State of Brandenburg, the local absence of the regionally most important aquiclude, the Lower Oligocene Rupelian Clay, separating deep saline waters from the overlying freshwater aquifers, is considered to be the main cause of local salinisation in the freshwater column.

The present study uses density-driven 3D flow and transport simulations to assess saltwater upwelling across Quaternary window sediments in the Rupelian for an area in southeastern Brandenburg with detectable salt concentrations in the freshwater column. Previous simulations along a 55 km long transect in Brandenburg using a 2D model have already demonstrated the potential negative impact of groundwater extraction, the use of the deep subsurface as a storage reservoir or lower precipitation rates and decreasing groundwater levels as a consequence of global climate change on the degree of upper aquifer salinisation (Chabab et al., 2022; Tillner et al., 2016; Wetzel et al., 2016).

The presented simulation results show that 3D flow strongly affects the temporal and spatial distribution of upper aquifer salinisation due to the varying extent of layers and erosion windows in the Rupelian Clay. The location of groundwater extraction sites, hydraulically conductive faults and spatial variations in groundwater recharge additionally influence the location and degree of shallow aquifer salinisation, and must therefore be carefully considered. Depending on topographic gradients and density variations occurring due to differences in pressure and temperature, convective cells with descending flow and freshwater lenses in the saltwater column also develop locally. We show that 3D flow simulations are essential for site-specific analysis to represent the dynamics of the system with many different hydrogeologic interacting and controlling factors.

 

Literature

Chabab, E., Kühn, M., Kempka, T. (2022): Upwelling mechanisms of deep saline waters via Quaternary erosion windows considering varying hydrogeological boundary conditions. Advances in Geosciences, 58, 47-54.

Tillner, E., Wetzel, M., Kempka, T., Kühn, M. (2016): Fault damage zone volume and initial salinity distribution determine intensity of shallow aquifer salinisation in subsurface storage. Hydrology and Earth System Sciences, 20, 1049-1067.

Wetzel, M., Kühn, M. (2016): Salinization of Freshwater Aquifers Due to Subsurface Fluid Injection Quantified by Species Transport Simulations. Energy Procedia, 97, 411-418.

How to cite: Chabab, E., Kühn, M., and Kempka, T.: Saltwater upwelling quantified by density-driven 3D flow and transport simulations for a study area in Brandenburg, Germany, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-12741, https://doi.org/10.5194/egusphere-egu23-12741, 2023.

17:25–17:35
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EGU23-3107
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ERE1.9
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ECS
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Virtual presentation
Lingbin Lai, Cunyou Zou, Zhibin Jiang, Haibin Su, Xuyang Zhang, Songlin Li, and Hualing Zhang

After a long period of water flooding development, oilfields will enter the production stage of "high water cut, high recovery degree, and low oil recovery rate". On the one hand, due to the displacement effect of the water injection, some oil layers already reached the water flooding limit. On the other hand, due to the effect of reservoir heterogeneity, dominant seepage channels, and imperfect injection-production well pattern, some oil layers are enriched with a large amount of remaining oil. Unbalanced production of reservoirs and difficulty in development and adjustment are common problems in mature oilfields. Mature multi-layer oilfields generally develop many sets of oil-bearing layers vertically. After a long water injection period, the water-flood law and the remaining oil distribution are complex, and the production of different well patterns or strata varies greatly. Through strata and well pattern reorganization, combined with the evaluation results of water flooding adjustment potential, some reservoir engineers and researchers established a stereoscopic development adjustment mode for enhanced oil recovery in mature multi-layer oilfields. This paper summarizes the main technologies of stereoscopic development adjustment mode for enhanced oil recovery in mature multi-layer oilfields. The main technologies of stereoscopic development adjustment mode include research on the remaining oil distribution, evaluation of water flooding adjustment potential, selection of tertiary oil recovery methods, reorganization of strata and well pattern, and optimization of timing from water flooding to tertiary oil recovery, etc. For strata with low water flooding adjustment potential, the tertiary oil recovery well pattern is reorganized and tertiary oil recovery is adopted to improve oil recovery. For strata with large water flooding adjustment potential, the water drive well pattern is reorganized and water flooding development is used to excavate the remaining oil. As for strata with general water flooding adjustment potential, the tertiary oil recovery well pattern is reorganized and water flooding development is used to excavate the remaining oil first, and then transfer to tertiary oil recovery at the proper time. The stereoscopic development adjustment mode is applied to test block K of Q reservoir which is a mature multi-layer oilfield. After stereoscopic development adjustment, the development effect of test block K meliorates. It is estimated that the EOR will be increased by more than 8% after stereoscopic development adjustment in test block K.

How to cite: Lai, L., Zou, C., Jiang, Z., Su, H., Zhang, X., Li, S., and Zhang, H.: Stereoscopic Development Adjustment Mode for Enhanced Oil Recovery in Mature Multi-Layer Oilfield, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-3107, https://doi.org/10.5194/egusphere-egu23-3107, 2023.

17:35–17:45
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EGU23-6856
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ERE1.9
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ECS
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Virtual presentation
Yan Yiming, Zhang Liqiang, Jiang Shuai, and Wang Zuotao

Reservoir heterogeneity is one of the key geological problems in the process of oil and gas exploration and development of clastic rocks. Understanding reservoir heterogeneity is imperative to improve the effectiveness of exploration and development. The primary porosity calculation model proposed by the authors in the previous study is used to calculate the primary porosity of samples from modern braided river sands and sandstone outcrops of braided sand bodies, and the primary porosity heterogeneity (PPH) model of the braided sand body is established. The architectural-elemental structures of braided sand bodies have obvious control effects on the distribution of its primary porosity heterogeneity. The central braided channel and braid bars have strong primary physical properties; the primary porosity is high and always greater than 38%. The contact areas between the braided channel and braided bars have a low value of primary porosity and are always lesser than 33%. The distribution characteristics of the present porosity of braided river reservoirs are also influenced by sedimentary architecture. To compare the relationship between PPH, present porosity heterogeneity (pPH), and sedimentary architecture (SA), the images of PPH, pPH, and SA were digital, graying, and normalized. The digital image Q-Q plots of the distribution probability of PPH, pPH, and SA are calculated. The results show that: the Q-Q plots of the probability distribution of present porosity and architectural-elemental structures (or lithofacies) can reflect the influence and degree of primary porosity and diagenesis on the present heterogeneity of the reservoir. The Q-Q plots of distribution probability primary porosity and present porosity identify the distribution areas; the points are always distributed on different lines. The line ‘y = x’, is derived from compaction and primary porosity; the line ‘y = ax, a > 1’, is derived from diagenesis, which is unfavorable to the reservoir porosity preservation (such as cementation); the line ‘y = ax, a < 1’ is derived from diagenesis, which is beneficial to reservoir porosity preservation (such as dissolution). Based on the Q-Q plots of distribution probability, the influence from primary porosity and diagenesis can be quantitatively analyzed. The influence of primary porosity on pPH in braided sand bodies of Ahe formation (Kuqa depression), middle Jurassic fluvial sandstone (Datong basin), and Karamay Formation (Junggar basin) were 19%, 90%, and 10%, respectively. A quantitative probability distribution Q-Q model of reservoir PPH and pPH is effective for reservoir physical modeling.

How to cite: Yiming, Y., Liqiang, Z., Shuai, J., and Zuotao, W.: The primary porosity heterogenetic model of braided river sandstone reservoirs and its influence on the present porosity heterogeneity in the Kuqe depression, Tarim basin, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-6856, https://doi.org/10.5194/egusphere-egu23-6856, 2023.

17:45–17:55
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EGU23-2535
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ERE1.9
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ECS
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Virtual presentation
Ming Li, Ming Wang, and Jinbu Li

Continental shale oil can be divided into two categories according to vitrinite reflectance of kerogen: medium-high maturity (Ro > 0.9%) and medium-low maturity (Ro ≤ 0.9%). Due to high ratio of gaseous (C1-5) and light hydrocarbons (C6-14), high GOR and overpressure of the shale section, medium-high maturity shale oil has commercially productivity, which is considered as the target of unconventional resources in China. Shale oil composition is the basic and key parameter for resource evaluation, prediction of favorable areas, well location and field development plan. However, in shale oil composition research projects, the samples used and the analytical methods are quite different, and evaluation standard has not been established, which has restricted the exploration and exploitation of continental shale oil in China.

To understand this effect, we took the first member of Qingshankou Formation (Late Cretaceous) in Songliao Basin in eastern China as the target section. The section develops pure shale oil at a burial depth of 2000-2500m, with vitrinite reflectance of kerogen (Ro) of 1.20%-1.70% and high clay minerals content (40 wt%-60 wt%). We performed four sets of experiments on molecular composition of shale oil, including oil produced from shale section, the full-closure coring shale, the conventional coring shale and extracted hydrocarbons of shale with chloroform. The crude oil and saturated hydrocarbons (extracted hydrocarbons) separated by chromatographic column were directly analyzed by gas chromatography. The full-closure coring and conventional coring shale samples were conducted TG-GC (thermogravimetry-gas chromatography) experiment, where the powder samples were thermally desorbed at 300 ℃ for 3 minutes.

The experimental results show that carbon number of n-alkanes in crude oil is 4–38. The carbon number of n-alkanes in full-closure coring shale is 1–26, and it contains a large amount of gaseous and light hydrocarbons, accounting for up to 60 wt%–80 wt%. It is worth noting, however, that due to the loss of gas and light hydrocarbons in conventional coring, the carbon number of n-alkanes in conventional coring shale is 11–26, and the main peak carbon is 13–16. In the process of shale placement in core library, extraction and concentration, a large amount of hydrocarbons are lost. Through chromatographic analysis, carbon number of n-alkanes in saturated hydrocarbons is 15-38, and the main peak carbon is 18–22. C15- components are totally lost in extraction (Figure 1).

The comparison data we assembled show that shale oil components obtained from different samples vary significantly, especially for medium-high maturity shale containing large amounts of gaseous and light hydrocarbons. The heavy hydrocarbon components (C15+) can be determined by combining the produced oil with extracted hydrocarbons, and the gaseous and light hydrocarbons retained in shale can be determined by combining the produced oil with TG-GC analysis for full-closure coring shale. Pressure-retained coring or full-closure coring is indispensable for obtaining shale oil components in place.

Figure 1 (a) Gas chromatogram of oil produced from shale section; (b) TG-GC chromatogram of conventional coring shale sample; (c) TG-GC chromatogram of full-closure coring shale sample; (d) Gas chromatogram of saturated hydrocarbon extracted from shale sample.

How to cite: Li, M., Wang, M., and Li, J.: Composition of pure shale oil with medium-high maturity, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-2535, https://doi.org/10.5194/egusphere-egu23-2535, 2023.

17:55–18:00

Posters on site: Mon, 24 Apr, 10:45–12:30 | Hall X4

Chairpersons: Paul Glover, Qian Wang, Thomas Kempka
X4.125
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EGU23-9352
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ERE1.9
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ECS
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solicited
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Highlight
Nora Koltzer, Johannes Schoenherr, Maximilian Sporleder, Sebastian Andreas Steininger, Marcel Halm, Michael Kettermann, and Florian Wellmann

The motivation behind this study is to repurpose idle wells from hydrocarbon exploration and production to provide heat for end users being located near the idle well. This is possible by prolonging the value-added chain of idle wells from the gas and oil industry by re-completion as geothermal closed loop wells. This is the most efficient way to produce green energy without drilling new wells by saving the carbon emission and costs of building a new geothermal well.

With this feasibility study we quantify the concept of re-completing idle wells in the North German Basin (NGB) into deep coaxial borehole heat exchangers. With numerical models of two typical geological settings of the NGB and two different completion schemes it was possible to simulate the thermal performance over a lifetime of 30 years. The calculated heat extraction rates are in the range of 200 kW to 400 kW with maximum values of up to 600 kW. This is higher than from already installed deep borehole heat exchangers. Sensitivity analyses demonstrate that flow rate, injection temperature and the final depths of re-completion are the most impacting parameters of thermal output determination.

In the final project stage, the heat demand around two exemplary boreholes was mapped and possible heating networks were simulated. The initial production costs for heat are comparable to other renewable energy resources like biomass and - depending on distance between source and user – well competitive against current gas prices. These calculations highlight not only the environmental valuable motivation behind the concept of repurposing idle wells but could also save capital expenditures for the geothermal industry.

Using a vacuum isolated tubing characterized by very low thermal conductivity of 0.02 W/(m*K), would make it possible to use the geothermal resources even more efficiently from idle wells. This project highlights the major potential of usable geothermal resources in already installed deep wells. The application has almost no geological risk, as the concept is independent of reservoir uncertainties like permeability and reservoir fluid composition, drilling risks are skipped completely and it is realizable at any location.

How to cite: Koltzer, N., Schoenherr, J., Sporleder, M., Steininger, S. A., Halm, M., Kettermann, M., and Wellmann, F.: Repurposing of idle wells from the oil and gas industry into deep borehole heat exchangers, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-9352, https://doi.org/10.5194/egusphere-egu23-9352, 2023.

Subsurface Storage
X4.126
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EGU23-1648
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ERE1.9
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ECS
Qian Wang, Jian Shen, Paul.W.J. Glover, and Piroska Lorinczi

Abstract: the pressure of the coal seam decays to a certain value due to the production of CH4, the production wells are switched to CO2 injection wells. The injection of CO2 can improve the CH4 recovery and realize the CO2 geological storage.The reverse migration of coal fines produced in the CH4 development stage can be caused by CO2 injection, which blocks the pore-thorats and fractures in coal seams and increases the difficulty of CO2 injection. We carried out experiments on coal fine migration and CO2 injection and storage at reservoir conditions on the simulated coal seam, which was a composite core composed of different types of coal. We focus on the migration of coal fine in simulated coal seam and the impact on CO2 storage. The experiment results show that, the permeability of the combined core, which is composed of proppant fractured coal, fractured coal and matrix coal in turn, decreases by 40.6% after being injected with 300ml of coal fine suspension with a concentration of 1g/1L. This is due to the deposition or capture of coal fines during the suspension injection, resulting in surface adsorption, bridging blockage, and direct blockage in the pore space, which seriously damaged the connectivity of the coal pore space. The proppant fractured coal can filter 77.1% of the coal fines in the suspension, and the fractured coal rock can filter the remaining 23.9% of the coal fines. The average CO2 storage capacity and CO2 storage efficiency of the composite core increased by 4.47 cm3·g-1 and 10.8%, respectively after subsequent CO2 injection into the composite core. The corresponding injection pressure difference also increased by 32.5%, and a CH4 recovery improvement of 13.6% is obtained.The migration and balockage of coal fines lead to the most significant improvement of CO2 storage in fractured coal (14.4%), followed by proppant fractured coal (10.3%), and the worst improvement of CO2 storage in matrix coal (3.4%). The migration of coal fines improves the CO2 storage effect in fractured coal seams to a certain extent, but increases the difficulty of CO2 injection, which is not conducive to the CO2 storage of the reservoir.

Keywords: CO2 storage, coal seams, coal fines migration, proppant fracture

How to cite: Wang, Q., Shen, J., Glover, P. W. J., and Lorinczi, P.: The CO2 storage in coal seams at the influence of coal fines migration, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-1648, https://doi.org/10.5194/egusphere-egu23-1648, 2023.

X4.127
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EGU23-1319
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ERE1.9
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ECS
Kai Li and Anne Pluymakers

In wells for carbon capture and storage (CCS), fractures can develop in the cement due to strong thermal shocks upon pressurized CO2 injection into the subsurface. The network of these fractures forms leakage pathways that can impair well integrity, and thus impede successful geological storage of CO2. In this study, we investigate how thermal shocks affect cement integrity under unconfined and confined conditions. Solid cylindrical samples (Φ3 x 7 cm) and samples of the same size but with a hole (Φ4 mm) in the middle are used. All samples are prepared using class G cement with 35% BWOC silica flour by Halliburton AS Norway, in accordance with API specification 10B-2. In unconfined experiments, we either quench the solid sample into cold water or inject cold water through the hollow-cylindrical sample to induce thermal shocks. In confined experiments, we mount the hollow-cylindrical sample in a triaxial deformation setup with confining pressure and axial stress, then inject cold water to induce the shocks. Before the shocks in all experiments, samples have been heated to 130°C. The temperature of the water is 5°C to achieve a strong thermal shock as possible. We produce eight cycles of thermal shock in all experiments. To study the extent of cracking, we use a micro-computed tomography (μ-CT) scanner to characterize the network of pores and fractures in the cement before and after experiments.

Under unconfined conditions, fractures develop in cement after thermal shocks in both quenching and injecting-through experiments. Both experiments generate sufficient thermal stresses to cause cracking in cement. In quenching, multiple fractures are initiated at different orientations. However, by injecting cold water through the sample, only one longitudinal fracture is created. This fracture is intersected with the injecting hole, where most thermal stresses are built up. The volume ratio of pores and fractures in samples increases to 2.74% by quenching and 1.84% by injecting through respectively, from 0.38%. Compressive strength decreases from 97.9 MPa for intact samples to 53.9 MPa after quenching, and 83.6 MPa after the injecting-through experiment. Under confined conditions, we carry out injecting-through experiments to bring about thermal shocks under 1.5 and 10 MPa confining pressure. We haven’t observed any failure in cement integrity under either confinement. Instead, compressive strength increases by 6.2% and 7.2%, and the volume ratio of pores and fractures decreases by 7.7% and 18.2% after the experiment under the confinement of 1.5 and 10 MPa, respectively. This means the presence of confining pressure not only hinders the adverse effects of thermal stresses on cement integrity but also compacts the samples. Higher confining pressure causes more compression to the sample, then resulting in greater strength.

How to cite: Li, K. and Pluymakers, A.: Effects of Thermal Shocks on Cement for CCS under Confined and Unconfined Conditions, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-1319, https://doi.org/10.5194/egusphere-egu23-1319, 2023.

X4.128
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EGU23-7034
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ERE1.9
Jianbang Wu, Shenglai Yang, and Qiang Li

In geological resource exploitation engineering such as reservoir development, the intrusion of foreign liquid will cause water lock damage to the formation rock structure, which affects the effect of reservoir transformation such as CO2 sequestration. The tight sand conglomerate reservoir is characterized by high content of expansive clay minerals, high capillary pressure, small pore throat, and serious heterogeneity, which leads to serious water lock damage. The extent, mechanism and reasonable prediction of damage are the concerns of the engineering community.
In view of this problem, this study uses the laboratory long core experiment method based on nuclear magnetic resonance (NMR) monitoring to simulate and study the reservoir damage law before and after the invasion of foreign liquid into the formation. The damage distance of liquid resistance and influencing factors were studied, and a prediction model was established. The long core experiment used drilled natural cores with a total length of 45 cm that were spliced from short cores with a diameter of 2.5 cm. A total of five pressure points were set up at 10 cm intervals to monitor the pressure gradient. The pressure gradient changes along the long core after saturated oil and water intrusion were tested separately. A new method of calculating the range and degree of water lock damage zone based on pressure gradient was established. According to the damage control factors obtained from the experimental study, the prediction model of water lock damage with the transformation from multiple nonlinear problems to linear problems is established by using permeability, porosity and content of water-sensitive clay minerals as input conditions.
The results show that the physical property of reservoir plays a decisive role in the damage distance of liquid resistance. The foreign liquid intrudes into the formation has obvious characteristics of "three zones", and the "pressed liquid stop zone" is the main factor controlling the damage degree of liquid resistance. Physical property, lithology and expansibility clay mineral content together constitute the 0-1 judgment value to determine the time-varying damage of fluid resistance in reservoir. The accuracy of the established multiple nonlinear regression prediction model of liquid resistance damage is greater than 80%, which can be used to quantitatively predict the liquid resistance damage degree of underground reservoir when it is difficult to conduct indoor simulation experiments in the evaluation of water intrusion damage degree.

How to cite: Wu, J., Yang, S., and Li, Q.: Study on Hydraulic Resistance Damage Law of External Liquid Intrusion in Tight Sand Conglomerate Reservoir, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-7034, https://doi.org/10.5194/egusphere-egu23-7034, 2023.

X4.129
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EGU23-16627
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ERE1.9
Paul Glover

Efficient use of new CCS resources depends critically on their characterisation. This is as true for CCS reservoirs that are deep aquifers or reservoirs that have previously been exploited as oil or gas reservoirs. Conventional pre-existing or newly commissioned reservoir characterization methodologies, such as well logs, 3D and 4D seismic reflection and cross-well electromagnetic imaging are limited in their scope and resolution. For CCS, the  crucial characterisation is that of the connectivity of the pore network. Carbon quantum dots (CQDs) are inert carbon nano-particles less than 10 nm in diameter. They can be made easily from environmentally-friendly stock materials and remain stable in aqueous solution no matter the pH or salinity, unlike conventional nanoparticles. In fluorescence spectroscopy CQDs demonstrate a strong absorption in the UV region with peaks at 228 nm and 278 nm. Their fluorescence spectra occupy the visible spectrum and are related to the stimulating frequency. These optical properties allow the number of particles to be ascertained easily and their small size allows them to be pervasive in the porous medium. Consequently, CQDs are ideal for use as a conservative tracer. Core and bead–pack tests have shown that almost 100% of the injected CQDs can be recovered from the porous medium indicating that there would be no damage to the CCS resource by their use. Breakthrough curves (BTCs) can be used to calculate the porosity and connectivity of water saturated rocks and the water saturation and connectivity of rocks from previously exploited hydrocarbon reservoirs at temperatures up to 80oC. Indeed it is possible that CQDs could be used to monitor quantitatively the emplacement of CO2 along the injection path. Although these CQDs have an attenuated performance in carbonate rocks, surface coatings are expected to resolve this question. Surface functionalisation will also allow the properties of the reservoir, such as temperature to be measured by altering the frequency of the emerging CQDs.

How to cite: Glover, P.: CCS Reservoir Characterisation using Carbon Quantum Dots, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-16627, https://doi.org/10.5194/egusphere-egu23-16627, 2023.

X4.130
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EGU23-9383
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ERE1.9
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Thomas Kempka

Power-to-Methanol is considered as an additional option to Power-to-Gas to convert surplus energy from renewable sources and the electric grid into storable energy carriers. In this context, methanol is an alternative fuel to power combustion engines, and it can be applied to produce chemical feedstock such as formaldehyde required for polymer production, hydrocarbons, gasoline and olefines, as well as gasoline additives and especially as an energy carrier and carbon sink.

As long-term storage of energy carriers is required to realise the transition of the energy sector to renewable sources scheduled in the European Union, the fact that storage of methanol requires less operational and safety efforts compared to natural gas or hydrogen is a significant benefit, i.e. methanol does not require any compression prior to its injection into geologic subsurface reservoirs, while being biodegradable and of generally low environmental toxicity. Existing hydrocarbon transport and storage infrastructure can be directly applied to transport and store methanol in the geologic subsurface. In this context, a major concern besides methanol biodegradability is its high miscibility with water, potentially resulting in relevant storage losses that may favour uneconomic storage operations in active groundwater aquifers. Hence, the present study aims at a quantitative assessment of the mixing behaviour of methanol and water based on a reference numerical simulation benchmark previously applied to investigate that of CH4 stored in a CO2 cushion gas within a depleted natural gas reservoir (Oldenburg et al., 2003, Ma et al., 2019, and others). For that purpose, the TRANSPORTSE numerical simulator (Kempka, 2020), applicable to simulate fluid flow as well as transport of heat and reactive transport of chemical species (Kempka et al., 2022) is used in the present study. Mixing ratio-dependent density and viscosity changes as well as different reservoir dipping angles are considered to determine the chemical storage efficiency in view of mixing losses. Simulation results demonstrate that methanol fraction-driven variations in fluid density and viscosity of up to 20 % and 30 %, respectively, as well as the relatively low diffusion coefficients compared to those of gases result in low mixing degrees of both liquid components. Structural geological features need to be considered in the selection of methanol storage sites, since these directly affect the spatial extent of the mixing region, and thus methanol recovery efficiency.

 

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

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

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

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

How to cite: Kempka, T.: Mixing behaviour of methanol stored in depleted hydrocarbon reservoirs to support the European Union energy transition, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-9383, https://doi.org/10.5194/egusphere-egu23-9383, 2023.

X4.131
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EGU23-15410
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ERE1.9
Sjoerd de Ridder, Afsaneh Mohammadzaheri, Alexander Calvert, and Mikael Lüthje

Seismic time-lapse (4D) imaging has been considered as a key solution to monitor CO2 reservoirs. However, traditionally this technology requires dense data acquisition to produce high-resolution images. It is anticipated that monitoring will be required for more than 50 years after CCS operations cease and the monitoring phase is profit-negative. Developing cheaper 4D seismic imaging techniques is necessary. Historical knowledge of the subsurface structure in and near abandoned hydrocarbon fields, could reduce the dense data requirement of 4D imaging.

Here we present preliminary results of 4D seismic (image-domain) wavefield tomography (IDWT) using pre-stack gathers from a sparse monitoring acquisition. IDWT uses short-offset data to exploit primarily kinematic changes rather than amplitude changes. IDWT minimises the shift between baseline and monitor migrations by optimising the monitor velocity model. Pre-stack IDWT, unlike post-stack methods, can use individual shot gathers to calculate the migration images. This property is beneficial when using sparse data acquisition permitting reliable measurement of shifts between monitor and baseline. Knowing the structure of the subsurface, we can design sparse acquisition surveys for seismic deployment, to minimize uncertainty in target areas. 

We create synthetic models based on Tyra gas field, a prospective future repository of CO2 in the Danish sector of North Sea and simulate CCS and subsequent leakage scenarios. The presence of CO2 in the reservoir, as well as the effect of reservoir pressure on the overburden stress-state, changes the seismic velocity structure of the reservoir and the overburden. These velocity changes cause an apparent depth (or time) shift when migrating the data.

How to cite: de Ridder, S., Mohammadzaheri, A., Calvert, A., and Lüthje, M.: Sparse image domain wavefield tomography for low-cost CCS monitoring in repurposed hydrocarbon fields, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-15410, https://doi.org/10.5194/egusphere-egu23-15410, 2023.

X4.132
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EGU23-8226
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ERE1.9
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ECS
|
Tobias Schnepper, Michael Kühn, and Thomas Kempka

Large-scale energy storage is becoming more important due to the increase in electricity generation from renewable sources and the related grid balancing requirements. In this context, Pumped Hydropower Storage (PHS) in former open-pit lignite mines can substantially contribute to energy supply safety. Assuming an average storage capacity of 150 MW per open-pit mine, PHS could generate a power output of at least 6 GW in European mines which will be abandoned in the next two decades. Experiences from mine-flooding across Europe demonstrate that hydrogeochemical processes can become a critical environmental and economic factor for the realisation of such projects. Depending on sulphide and oxygen availability, buffer capacities and dilution processes, mine waters with increased acidity as well as elevated sulphate and metal concentrations can pose a threat to adjacent ecosystems, groundwater resources and the installed PHS infrastructure.

We present a generic parameter study by means of numerical simulations to predict changes in the mine water composition as a result of PHS operation in different hydrogeochemical settings. Published datasets on hydrogeochemical, hydrogeological and technical conditions with a focus on German mines were applied for model parametrisation. A reaction path model was developed that accounts for initial mine flooding, inflows and outflows as well as pumping and release cycles between the two reservoirs. The simulations were run until chemical equilibrium was achieved in the lower reservoir.

Simulation results indicate that the long-term availability of buffer capacities in the reservoir water and adjacent sediments determine the development of acidic or neutral mine waters. Sulphate concentrations are mainly influenced by dilution processes, emphasizing the relevance of considering additional in- and outflows. Depending on these fluxes as well as oxygen availability and initial sulphide concentration in the mine sediments, the time to reach chemical equilibrium in the lower reservoir varies significantly from several weeks to months. Furthermore, the dissolution of sulphides and carbonates as well as the precipitation of iron (oxy)hydroxides may affect the properties of the open-pit slope sediments. Their long-term stability may be altered, based on their initial mineral concentration and hydraulic conductivity.

In summary, potential impacts on water quality in the PHS reservoirs have been investigated under different hydrogeochemical settings. We conclude that, under specific boundary conditions such as the availability of sufficient buffer capacities and dilution by controlled inflows and outflows, PHS operation in abandoned open-pit coal mines can be realised from an environmental perspective.

How to cite: Schnepper, T., Kühn, M., and Kempka, T.: Hydrogeochemical impacts of pumped hydropower storage in open-pit lignite mines, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-8226, https://doi.org/10.5194/egusphere-egu23-8226, 2023.

Modelling and Simulation
X4.133
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EGU23-16672
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ERE1.9
Paul Glover, Mehdi Yaghoobpour, Piroska Lorinczi, Wei Wei, Li Bo, and Saddam Sinan

One strategy for reducing global greenhouse gas emissions as the world progresses towards net zero is to extract more hydrocarbons from existing resources. Conventional modelling and simulation of heterogeneous and anisotropic reservoirs consistently and significantly underestimates production, sometimes by as much as 70%.

We now understand that many reservoir properties are fractal, such as porosity, grain size and permeability. While water saturation and capillary pressure have distributions which arise from fractally-distributed microstructural properties. Recent work has resulted in the development of the fractal theory of Archie’s laws, providing fractal dimensions underlying both the cementation and saturation exponents that is consistent with the n-phase Archie’s law theory.

The significant underestimation of production by conventional reservoir models can be overcome by the use of advanced fractal reservoir models (AFRMs) which take account of the fractal distribution of key petrophysical properties such as porosity, grain size, cementation exponent, permeability, water saturation and capillary pressure. These models employ existing and interpolated data across an extended range of scales and take account of variability less than the 50 m seismic resolution limit. AFRMs provide production profiles that are much closer to actual production profiles.

This presentation describes briefly the AFRM approach to the modelling and simulation of heterogeneous and anisotropic reservoirs, showing how AFRMs can be generated easily to match an imposed degree of heterogeneity and anisotropy, or can be conditioned to represent the heterogeneity and anisotropy of the target reservoirs. We describe how AFRMs can be generated and normalised to represent key petrophysical parameters, how AFRM models can be used to calculate permeability, synthetic poroperm cross-plots, water saturation maps and relative permeability curves, and how AFRMs which have been conditioned to represent real reservoirs provide a much better simulated production parameters than the current best technology.

Generic AFRM modelling and simulation show that total production, production rate, water cut and the time to water breakthrough all depend strongly on heterogeneity and anisotropy. Counter to expectation, optimal production is obtained from placing both injectors and producers in the most permeable areas of heterogeneous reservoirs. Furthermore, modelling with different degrees and directions of anisotropy shows how hydrocarbon production depends critically on anisotropy direction, which changes over the lifetime of the reservoir.

AFRMs are ultimately only useful if they can be conditioned to real reservoirs. We have developed a method of fractal interpolation to match AFRMs to reservoir data across a wide scale range. Results comparing the hydrocarbon production characteristics of such an approach to a conventional krigging approach show a remarkable improvement in the modelling of hydrocarbon production when AFRMs are used; with AFRMs in moderate and high heterogeneity reservoirs returning values always within 5% of the reference case, while the conventional approach often resulted in systematic underestimations of production rate by over 70%.

Although more work needs to be done on this new approach to reservoir modelling, initial results indicate that it has the potential for improving the accuracy of modelling and simulation in heterogeneous and anisotropic reservoirs by an order of magnitude or more.

How to cite: Glover, P., Yaghoobpour, M., Lorinczi, P., Wei, W., Bo, L., and Sinan, S.: Unconventional Fractal Modelling and Simulation of Heterogeneous and Anisotropic Reservoirs, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-16672, https://doi.org/10.5194/egusphere-egu23-16672, 2023.

X4.134
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EGU23-2016
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ERE1.9
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Benjamin Nakaten and Thomas Kempka

Conversion of static geologic models into numerical simulation grids is a pre-requisite to undertake site-specific assessments of geologic subsurface utilisation in terms of risk assessments, design and operational optimisations as well as long-term predictions.

GEOMODELATOR is a Python-based Open Source software package which enables modellers to translate static geologic models into regular structured simulation grids with element partitions following a complex model geometry.

For that purpose, geologic models generated by means of Geographic Information Systems (GIS), Computer-Aided Design (CAD) or other specific geologic modelling software packages are integrated in form of point cloud data together with the desired structured simulation grid geometry.

GEOMODELATOR maps geometric features such as lithologic horizons, faults and any kind of other geometric data by 3D Delaunay triangulation onto the pre-defined grid element centres, and provides the modeller with Visualization Toolkit (VTK) data and Python numpy arrays for visual model inspection and their direct application in numerical simulations, respectively.

The present contribution shows the application of GEOMODELATOR to different numerical simulation studies addressing fluid flow as well as transport of heat and chemical species in geological subsurface utilisation.

How to cite: Nakaten, B. and Kempka, T.: GEOMODELATOR – from static geologic models to structured grids for numerical simulations, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-2016, https://doi.org/10.5194/egusphere-egu23-2016, 2023.

X4.135
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EGU23-17292
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ERE1.9
Qian Wang, Jian Shen, Bai Jie, Paul W.J. Glover, and Piroska Lorinczi

Tight oil reservoirs are often oil-wet and contain surface adsorbed layers of hydrocarbon. Improvement of production lies in part in the ability to produce this adsorbed oil for its own sake and to unblock small pores that can improve the relative permeability of the reservoir. In this paper we have used molecular modelling and simulation first to study the formation of adsorbed oil films made from n-alkanes of 5 different molecular weights (nC7, nC12, nC18, nC22, nC25) on an hydroxylated ->-SiO2 surface, and then to examine the process of stripping oil from these layers using carbon dioxide, nitrogen and water. It was found that all n-alkanes but nC12 formed a monolayer oil film, while nC12 formed a three-layer oil film. Molecular weight, length and flexibility of the n-alkane were all factors in oil film formation. It was found that flooding with CO2 is able to strip all of the modelled n-alkanes from the α-SiO2 surface effectively. The time required to strip the n-alkane was longer for n-alkanes with higher molecular weights. The stripping process was divided into three stages: (i) CO2 diffusion and dissolution, (ii) competitive adsorption, and (iii) oil film push-off. A fourth stage was recognized only for light n-alkanes, and which involved the dissolution of CO2 in mobilized n-alkane, leading to improvements in its mobility. Comparative simulations using nC12 showed that N2 and H2O exhibit no efficacy in stripping n-alkanes from surface adsorbed oil films. The efficacy of CO2 was attributed to (i) it being a polar molecule that is attracted to the hydroxylated silica surface, (ii) its miscibility in n-alkanes, and (iii) that it is in a supercritical state at reservoir conditions. The failure of N2 arises because it is a non-polar molecule with no affinity for the surface and exists as an immiscible gas at reservoir conditions. Water was ineffective, because, though polar, it is immiscible in the oil layer and so cannot access the rock surface. Consequently, CO2-flooding is expected to be particularly effective in improving production from tight oil-wet clastic reservoirs.

Key words: tight reservoir; pore throats; CO2 flooding; oil film stripping; molecular simulation

How to cite: Wang, Q., Shen, J., Jie, B., Glover, P. W. J., and Lorinczi, P.: Molecular simulation of stripping of crude oil by CO2 in tight reservoirs, EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-17292, https://doi.org/10.5194/egusphere-egu23-17292, 2023.

X4.136
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EGU23-12843
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ERE1.9
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ECS
Celine Eid, Christoforos Benetatos, and Vera Rocca

The use of the coupling approach in analyzing the interaction between the flow field and the stress field in shallow, unconsolidated aquifers allows a better description of the involved phenomena. We perform our study on an area in the Po Plain (northern Italy) in the province of Bologna in Emilia-Romagna based on intended future studies on ground movements due to the superposition of shallow water production with deep underground gas storage.

The static geological model of the alluvial sediments, locally exceeding 500 meters of thickness, is developed via a stochastic approach in order to manage the high degree of uncertainty in the system spatial continuity and heterogeneities. Corresponding water production data and piezometric measurements are collected for simulating the dynamic behavior of the shallow aquifer. The high uncertainty in water production data are managed considering a maximum and minimum scenarios on the basis of punctual well measurements and regional trend information. Correlation law between petrophysical parameters and deformation variables are derived for technical literature. The coupling technique is then applied and some sensitivity analysis are developed to assess the effects of the correlation laws. The results are finally compared with the output from the uncoupled techniques.

How to cite: Eid, C., Benetatos, C., and Rocca, V.: Coupling approach in shallow, unconfined aquifers in the Po Plain area: A preliminary study for future ground monitoring purposes., EGU General Assembly 2023, Vienna, Austria, 23–28 Apr 2023, EGU23-12843, https://doi.org/10.5194/egusphere-egu23-12843, 2023.