In low-permeability reservoirs, strong molecular interactions exist at the solid-liquid interface, necessitating the overcoming of the threshold pressure gradient in shale oil extraction. A profound comprehension of molecular interactions between oil and reservoir matrix is crucial to develop a productive strategy for enhanced oil recovery. Molecular dynamics simulation has become an important method for analyzing microscopic mechanisms of some static properties and dynamic processes. In this study, a molecular model of shale oil was built based on the reported experimental results and simulation. Subsequently, the molecular model was utilized to build a flow model within three matrix pores: kerogen, quartz, and portlandite. A comprehensive analysis of the interfacial effects and size effects on the threshold pressure gradient was undertaken. Emphasis was placed on elucidating the influence of the adsorption behaviors (stable adsorption, unstable adsorption, non-adsorption) of polar components at the interface on the flow of shale oil. The utilization of the critical shear stress facilitated the accurate prediction of the threshold pressure gradient of shale oil within large pores. Moreover, within the context of the flow model of shale oil in nanoscale pores, we conducted some explorations into oil displacement by CO₂. This work suggests fresh ideas for studying the oil-matrix interactions on the nanoscale and provides theoretical guidance for shale oil exploitation.

How to cite: Cui, F. and Wang, F.: Micromechanical mechanism of oil-rock interaction and the availability analysis of shale oil, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-6006, https://doi.org/10.5194/egusphere-egu24-6006, 2024.

Many geothermal plants in the north alpine foreland basin (NAFB) are affected by the precipitation of calcium carbonate and struggle with efficiency losses and sometimes safety problems. The adaption and implementation of predictive maintenance strategies relies on the accuracy of the prediction and make sense if the costs of early maintenance are significantly less compared to the costs of a replacement of failed parts. Therefore, the accurate description of the kinetics of inorganic precipitations have to be extended to include the fluid dynamics and the interaction of the precipitates with different materials used in the geothermal cycle. The experimental concept also applies to fluid-rock interactions which can alter the properties of the reservoir.

The parametrization of transferable hydrogeochemical models performs best with data on a single interface, single crystal level. This data allows to elucidate the underlying process kinetics and improve existing strategies. The combination of Raman spectroscopy and Quartz crystal microbalance (QCM) opened a way to quantify the formation of carbonate precipitates. Here, the QCM can measure the total mass of attached particles while Raman microscopy identifies the crystal polymorph. Running these experiments in microfluidic channels allows to assess the effects of physical stress on the formation and to test inhibition and removal stratgies.

The QCM sensor was placed in a microfluidic channel and tap water (carbonate rich, Ca²⁺ concentration approx. 2.25 mM, pH approx. 7.50) and sodium hydroxide (0.10 M) were injected through the two inlet channels. As the lime carbonic acid equilibrium shifts due to the pH increase, precipitations are formed. The adhesive forces on different materials (SiO2, aluminium, steel) were studied by changing the flow velocities and chemical cleaning processes were mimicked by injecting an acid (HCl).

The precipitation of CaCO₃ on the QCM sensor (sensitivity in the low mg-range) was less than 20% of the theoretical amount. This underlines the importance to include the fluid dynamics into the assessment models. The experimental data under dynamic conditions was modelled with a combination of CFD simulations with PhreeqC: The particle flow velocity and the precipitates formed depend on the depth as well as local equilibrium changes. The preferred location of scaling could be adequately simulated. This quantification of the effects of the shear stress and the material properties on the scaling efficiency is a further step towards predictive maintenance strategies and a solid comprehensive site assessment during the planning stage, which should improve the sustainability and the much-needed attractiveness of this energy sector.

How to cite: Zacherl, L. and Baumann, T.: Pore scale assessment of disrupted hydrochemical equilibria in geothermal systems, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-3433, https://doi.org/10.5194/egusphere-egu24-3433, 2024.

Geological storage of energy and carbon dioxide requires a deep knowledge of the complex thermo-hydro-chemo-mechanical processes that affect the stability and performance of reservoir rocks. In this study, we investigate the thermo-mechanical properties and mesoscale fracture behaviors of four key minerals in granites: quartz, plagioclase, amphibole, and biotite. We use a combination of experimental and analytical techniques to reveal the microscale mechanisms of rock failure under high temperature and tensile loading.

We perform nanoindentation tests under dynamic heating–cooling cycles to measure the reduced modulus and hardness of the minerals. We also conduct mode I fracture tests under tensile loading conditions to evaluate the fracture toughness and tortuosity of the granite. We observe the dynamic crack propagation and fracture morphology of minerals using scanning electron microscopy. We analyze the structural and physio-chemical changes at high temperatures using X-ray diffraction, thermogravimetric analysis, and Fourier’s transform infrared spectroscopy.

We find that the thermo-mechanical properties and fracture behaviors of the minerals are governed by three main factors: the alterations in mineral structure, the aperture of open cracks along cleavage planes, and the degree of heterogeneity due to mineral composition complexity. We identify two different damage modes in granite: catastrophic and non-catastrophic failure modes. We explain the underlying mechanisms of each mode and show that catastrophic failure has precursory signs, while non-catastrophic failure does not.

Our results provide new insights into the microscale mechanisms of rock failure under high temperature and tensile loading, which have implications for the macroscopic understanding of rock behavior in geological storage applications. By elucidating the microscale intricacies, this study enhances our understanding of the multifaceted interactions that influence the stability and performance of rocks, and supports the development of improved geological storage strategies, such as carbon sequestration and enhanced energy storage.

How to cite: Mo, C., Zhao, J., and Zhang, D.: Thermo-mechanical properties and fracture behavior of granite at pore scale: implications for geological storage, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-2751, https://doi.org/10.5194/egusphere-egu24-2751, 2024.

Mineral wettability plays a pivotal role in determining residual oil distribution and devising effective displacement strategies for enhanced oil recovery. Through molecular dynamics simulations, we investigated the surface wettability of various typical minerals, revealing the complete spreading of modeled crude oil over most mineral surfaces. Our research introduces an efficient method for calculating the spreading coefficient of modeled crude oil on mineral surfaces, allowing accurate predictions of its spreading state with a notable reduction in calculation time compared to traditional methods. Furthermore, the study explores the impact of various components within crude oil on mineral surface wettability, emphasizing microscopic interactions between these components and minerals. In nanopore channels, the diverse wettability of oil/rock interface results in varied occurrence forms, such as droplets, films, or columns, which are also different in the water flooding process. In addition, with the introduction of various components in crude oil, due to their different interactions with oil/water/rock, we found that these components can be evenly mixed with modeled crude oil or exist at the oil-water interface. Therefore, the introduction of this component changes the properties of oil-water interface, affects the form of oil occurrence and the process of flooding. These insights contribute to a comprehensive understanding of mineral surface wettability and its correlation with crude oil composition, providing valuable guidance for optimizing reservoir management and refining production strategies in the pursuit of enhanced oil recovery.

How to cite: Fan, J. and Wang, F.: Nanoscale Wettability of Oil/Rock Interface and its Impact on Occurrence and Flooding, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-6961, https://doi.org/10.5194/egusphere-egu24-6961, 2024.

The characterization of reservoir rocks depends on the absolute permeability as a crucial parameter. To estimate this property numerically, one can employ a combination of digital rocks and Stokes flow simulation through the Lattice Boltzmann Method (LBM). In previous studies, the LBM has typically been implemented as an iterative process, wherein iterations are repeated until the parameter estimates between consecutive iterations reach a certain threshold level. However, we argue that this termination criterion is unsuitable and may compromise the accuracy of simulation results.

In this study, we investigate the convergence of the LBM through various tests, including the Poiseuille flow between parallel plates and different types of digital rocks (such as dune sand, sandstone, and carbonates). We find that the logarithm of the relative error, when compared to the estimate at infinite time (representing a stable state), demonstrates a linear relationship with the number of iterations. This linear relationship suggests an exponential rate of convergence. On the other hand, if we rely on the difference in errors between consecutive iterations as the termination condition, the simulation may not reach a stable state.

Instead, we propose a more accurate termination criterion for the LBM simulation by analyzing the decay trend of the error difference. This criterion provides a practical and appropriate approach for the characterization of reservoir rocks. Additionally, we offer a theoretical explanation for the convergence rate, which is linked to the spectral radius of the iterative matrix in linear algebra.

How to cite: Liao, Q.: Convergence Behavior of Lattice Boltzmann Method for Pore-scale Modeling, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-4648, https://doi.org/10.5194/egusphere-egu24-4648, 2024.

CO₂-oil-rock interactions and complex pore structure affect the sweep efficiency (E_S) and wettability, thus having a significant impact on CO₂ enhanced oil recovery in tight oil reservoirs. In this study, we selected 10 rock plugs from the Yanchang Formation, Ordos Basin in China. First, casting thin sections and mercury intrusion capillary pressure were performed to investigate the microscopic pore structure characteristics of the tight rock samples. The results show that pore structure can be divided into three types (RT-I, RT-II, and RT-III) from good to poor qualities. On this basis, CO₂ floodings using the Nuclear Magnetic Resonance technique were performed to investigate the influence of pore structure on the E_S in large (P_L) and small (P_S) pore throat intervals. With the increase of displacement pressure, the oil recovery of RT-I, RT-II and RT-III are about 70.9%, 67.8% and 10.16%, respectively. The E_S of P_L of all samples are similar, while the E_S of P_S decrease subsequently for the three types. Pressure, mineral composition and the complex pore structure are attribute to the differences. On one hand, higher displacement pressure leads to lower interfacial tension and viscosity, resulting in higher oil recovery. On the other hand, CO₂ is more likely to vaporize the light oil components, resulting in the asphaltene precipitation. Quartz with a smooth surface is not easy to precipitate, while most clay minerals are easier to absorb asphaltene and are likely to alter the wettability of pore surfaces. Thus, in comparison to RT-III, the E_S of RT-I with a higher quartz content is higher in P_S. In addition, the worse the relationship between pore structure configurations, the greater the capillary pressure, causing the different E_S between RT-I and RT-II. The findings in this study shed a light on the understanding of complex mechanisms for CO₂ EOR in tight oil reservoirs.

How to cite: Cheng, Y., Qu, Y., and Cheng, X.: Effect of pore structure and CO2-oil-rock interactions on sweep efficiency of CO2 EOR in tight sandstone reservoirs, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-3479, https://doi.org/10.5194/egusphere-egu24-3479, 2024.

    The characterization of the microscopic pore systems in organic-rich shales is crucial for comprehending the occurrence mechanisms and flow behaviors of shale oil. Although various image processing techniques have advanced the study of shale pore systems recently, challenges such as unclear boundaries of pore structures, interwoven connectivity, high similarity, and complex topological structures remain unresolved. In this study, a comprehensive investigation of the multiscale pore structure in organic-rich shale is presented, through the examination of 20 lacustrine shale samples from the Paleogene Kongdian Formation. These samples were analyzed using a variety of techniques, including N2 adsorption, mercury intrusion capillary pressure (MICP), nano X-ray CT, and Focused Ion Beam-Scanning Electron Microscopy (FIB-SEM). Furthermore, We innovatively propose a machine learning-based multi-objective panoramic segmentation modeling method. This approach allows for precise segmentation and rapid panoramic modeling of various instances across different semantic categories and the gaps between these instances. It enables the creation of a more comprehensive multi-scale porous network model, which will be more conducive to future simulations of multi-physical processes such as fluid dynamics permeation models.
    We combine the dilated convolutions suitable for semantic segmentation with the feature pyramid structure favorable for instance segmentation to achieve precise panoramic segmentation. This approach accurately segments and represents various components in SEM images, including interparticle pores, intraparticle pores, organic pores, microfractures, feldspar, quartz, dolomite, calcite, clay minerals, and organic matter.In the three-dimensional reconstruction of FIB images, we innovatively employ registration based on contextual relationship sequences to accurately expand the reconstruction scope of pore pathways. Simultaneously, the use of an octree data structure index in constructing pore network structures enhances efficiency and speed. 
   The results show that the overall pore sizes range from 5 nm to more than 50 μm, consisting of abundant nanopores and a small quantity of micropores, and the dominant pores are in the range of 5 nm -200 nm. Through three-dimensional characterization of different types of pore networks, the transport behavior of shale oil within nanoslits was simulated, and it is proposed that fluid migration path is mainly controlled by the content of minerals, whether laminae are developed, and organic matter content. This study offers a promising solution for optimizing the automatic processing of microscopic images for pores, the combination of methods can provide pore structure characterization from sub-nanoscale to macroscale, spanning four orders of magnitude, which is crucial for improving the understanding of reservoir mechanisms and the hydrocarbon potential of lacustrine shale.

How to cite: Li, G., Xin, B., and Li, Z.: Applying Machine Learning Methods Based on Panoptic Segmentation, Context Registration, and Octree Indexing for Multiscale Pore Structure and Connectivity of the Organic-rich shales in Bohai Bay Basin, East China, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-19274, https://doi.org/10.5194/egusphere-egu24-19274, 2024.

In conjunction with scanning electron microscope (SEM) and energy-dispersive spectrometer (EDS), quasi-static nanoindentation has been widely used to investigate the mechanical properties of minerals and organic matters in shale at micro scale. However, due to the limited test efficiency of conventional nanoindentation measurement and the demand of mineralogical identification which is achieved by SEM observation and EDS analysis, the research scheme in previous works can be time-consuming and complicated. This work attempts to develop a new micromechanical research scheme with high test efficiency and automatic mineralogical identification. A newly-developed high-speed nanoindentaion technique is used to characterize the mechanical properties distribution of a shale sample from the Yanchang Formation in the Ordos Basin, China. Then, the mineralogical distribution in the corresponding areas is obtained by using MAPS Mineralogy. Finally, logistic regression is applied to link the mechanical properties distribution and mineralogical distribution, and to realize the automatic mineralogical identification based on nanoindentation results. In addition, to further investigate the influence of characterization experiments on machine learning results, the characterization abilities, including lateral spatial resolution, detection depth, and signal spacing, of the two experimental methods are compared. The detection depth of MAPS Mineralogy is markedly higher than that of nanoindentation, which means that the material volume detected by the two methods is different. The lateral range responding to applied force and incident electrons determines that the signal of data points at the boundary can be a mixture of two or more minerals. The influence of such detection depth difference and boundary effect is also discussed.

How to cite: Jiang, S., Zhao, J., and Zhang, D.: Machine Learning for mechanical classification of organic-rich shale based on high-speed nanoindentation, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-13458, https://doi.org/10.5194/egusphere-egu24-13458, 2024.

Horizontal well multi-stage and multi-cluster fracturing technology has played an important role in unconventional reservoir development. However, traditional methods rarely investigated fracturing fluid flow characteristics in reservoirs with abundant natural fractures. Furthermore, affected by the stress interference from dense number of fracturing clusters, some perforations do not form fractures. For deep shale reservoirs, failure to consider these contents may result in unsatisfactory fracturing results for deep shale reservoirs.

An innovative approach is introduced in this paper. This innovation can be based on natural fracture development, fracture propagation law and reservoir composition characteristics. The flow regularity of fracturing fluid inside natural fractures was characterized through CT scanning experiments. Numerical simulation is used to analyze fracture propagation in fracturing horizontal well with multi-stage and multi-cluster. Core full component test experiment was conducted to analyze compressibility. In response to the above results, different fracturing process is adopted, the length of fracturing section is adjusted, the number of fracturing clusters is set. Then the fracturing design scheme of each segment is formulated and the fracturing effect and operation lessons of actual wells are analyzed. 

The results show that obvious pressure interference between developed section and undeveloped section of natural fracture, fracturing fluid first enters the extended natural fracture and then enters other fractures. Therefore, the temporary plugging of the extended natural fracture weakens its preferential tendency to enter the fluid and ensures the uniform migration of fracturing fluid to each fracture. Numerical simulation shows that some perforations do not form effective fractures, due to stress interference caused by excessive number of perforations. Hence, a fracturing scheme with fewer perforation times is adopted to reduce stress interference and improve the efficiency of perforating fracture formation. The results also observe that the reservoir contains plenty of brittle minerals such as calcite, which is easy to cause fractures. However, high silicon content easily form, extremely irregular fracture. Consequently, the fracturing scheme of shortening the length of fracturing section is adopted to strengthen the control of fracture expansion. The fracturing evaluation of the effect shows that the initial production of the well was 6.59 ×10⁴ m³ with a flowback rate of 15.5%. Microseismic monitoring data shows that the reconstruction volume has increased from the original 9.70 ×10⁴ m³ to 1.06 10⁵ m³, the fracturing effect is remarkable.

The conclusion of this research supports for deep shale fracturing design and has a vital practical application significance. Compared with conventional fracturing methods, the fracturing performance is significantly improved results from weakening the advanced fluid tendency of natural fractures, decreasing the stress interference between clusters and strengthening the fracture control.

Key words: deep shale; natural fracture; stress interference; brittle mineral content; temporary plugging technology

How to cite: Di, S., Ma, S., Wei, Y., Cheng, S., Miao, L., and Liu, M.: Effective fracturing strategy considering natural fracture, stress interference and rock component—A practical application of Dingshan block in Sichuan Province of China, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-5027, https://doi.org/10.5194/egusphere-egu24-5027, 2024.