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Identification and parameter characterization of pores and fractures in shales based on multi-scale digital core data
Get PDFAccurate pore structure characterization, as a basic tool for efficient exploration and development in reservoirs and digital rock, has become increasingly popular nowadays. However, using single-scale digital core data, it is difficult to evaluate the multi-scale pore structures in shales. This study proposes an integrated workflow for identifying and extracting pore parameters from multi-scale three-dimensional and two-dimensional digital rock images, which includes full-diameter core computed tomography (CT), micro-CT, focused ion beam-scanning electron microscopy and scanning electron microscopy images. This workflow realizes the identification and parameter extraction of pores and fractures from mesoscopic to microscopic scales. First, meso-fractures are extracted using the connected domain analysis method from full-diameter CT images, and the apparent attitudes are calculated using the least squares and connected domain analysis method. Then, micropores and fractures are identified from Micro-CT and focused ion beamscanning electron microscopy data, and the pore network models are established. Features, including pore radius, surface area, volume, throat radius, length, and coordination number, are calculated based on the maximum ball method. Different types of pores in scanning electron microscopy images are automatically identified using deep learning methods, and the pore parameters are computed using connected domain analysis methods. Subsequently, the workflow is applied to a practical case and the results show accurate extractions of pore structure information. This study provides important guidance and support for the quantitative evaluation of pores and fractures in unconventional reservoirs.Document Type: Original articleCited as: Zhou, Y., Zhong, X., Nie, X. Identification and parameter characterization of pores and fractures in shales based on multi-scale digital core data. Advances in Geo-Energy Research, 2024, 13(2): 146-160. https://doi.org/10.46690/ager.2024.08.0
Combination of non-ionic and cationic surfactants in generating stable CO2 foam for enhanced oil recovery and carbon storage
Get PDFSurfactant-stabilized CO2 foam is a promising technology to reduce CO2 mobility in geo logic CO2 storage and CO2 enhanced oil recovery processes. In this study, various combi nations of a non-ionic surfactant, Alkyl polyglycoside, along with cationic surfactants were ingeniously examined to enhance carbon storage and facilitate oil recovery through CO2 based foam flooding. Specifically, for the first time, the investigation focused on the impact of altering the alkyl chain length and counter-ion type of the cationic surfactants. The surfactant combinations were first screened based on surfactant characterization, surface and interfacial tension studies and bulk foam experiments. The interfacial tension studies showed that, in combination with Alkyl polyglycosides, the C16 (cetyltrimethylammonium bromide and cetyltrimethylammonium chloride) alkyl chain length cationic surfactants exhibited less interfacial tension values than the C12 (dodecyltrimethylammonium bromide and dodecyltrimethylammonium chloride) alkyl chain length cationic surfactant. The bulk foam experiments established that Alkyl polyglycosides/C16 combination showed higher foamability and foam stability than Alkyl polyglycosides/C12 combination. The bulk foam investigation showed that the optimized concentration of Alkyl polyglycosides/cationic surfactant was 0.3/0.15 wt%. The surfactant combinations screened from these studies were evaluated for EOR coreflooding experiments at 1250 psi and 60 °C. The incremental oil recovery obtained for baseline CO2 and Alkyl polyglycosides/cetyltrimethylammonium bromide foam flooding was 18.5% and 32.7%, respectively. The estimated carbon storage potential for baseline CO2 g and Alkyl polyglycosides/cetyltrimethylammonium bromide foam flooding was 11.9% and 23.7%, respectively. The combination of Alkyl polygly cosides cetyltrimethylammonium bromide surfactant was demonstrated as an effective solution for increased oil recovery and carbon storage.Document Type: Original articleCited as: Tripathi, R., Alcorn, Z. P., Graue, A., Kulkarni, S. D. Combination of non-ionic and cationic surfactants in generating stable CO2 foam for enhanced oil recovery and carbon storage. Advances in Geo-Energy Research, 2024, 13(1): 42-55. https://doi.org/10.46690/ager.2024.07.0
Visualizing oil displacement by nanofluids at pore scale: A concentration-dependent nanofluid spreading induced by structural disjoining pressure
Get PDFImmiscible fluid displacement in porous media is governed by pore-scale behaviors, which can be manipulated by chemical additives to engineer the process toward a greater turn-out. Although recent advances in nanofluids have been reported to influence such a process, their interfacial phenomena are likely controversial and need independent cross-examinations. As non-energetically interfacial responsive nanoparticles, silica cores adorned with polyvinylpyrrolidone were examined for their direct contribution to crude oil displacement performance at relatively low concentrations, ranging from 10 to 500 ppm, in the current study. The crude oil displacement was experimented via water wet borosilicate micromodel and visualized to elucidate pore-scale interfacial phenomena involved. Concentration-dependent property of nanofluids was found, evidenced by different pore-scale mechanisms observed. At low concentrations (10 and 50 ppm), wetting layer flow controlled the oil displacement and led to swelling into pore space, inducing snap-off events and hence high oil ganglia trapped (> 300). At higher concentrations (100 ppm), nanoparticle self-arrangement at the water wedge was more effective, which induced oscillatory structural disjoining pressures between the oil-aqueous and solid aqueous interfaces leading to narrow nanofluid spreading. Hence, the spatiotemporal displacement performed differently at high concentrations (displacement efficiencies were 36.8% at 100 ppm and 43.1% at 500 ppm), with snap-off hardly observed. At 500 ppm, more stable and stronger nanofilm spreading was developed due to meniscus expansion, obtaining faster-displacing dynamics (54.9% per pore volume injected) and additional oil displaced (+5.7%) after breakthrough time. The findings amplify nanofluid contribution and emphasize its concentration dependence on immiscible fluid flow in porous media, a potential applicability to various fields including enhanced oil recovery and CO2 geological storage.Document Type: Original articleCited as: Akamine, T., Tosuai, T., Ramadhan, R., Promsuk, N., Srisuriyachai, F., Tangparitkul, S. Visualizing oil displacement by nanofluids at pore scale: A concentration-dependent nanofluid spreading induced by structural disjoining pressure. Capillarity, 2024, 12(1): 17-26. https://doi.org/10.46690/capi.2024.07.0
Numerical simulation of multiphase multi-physics flow in underground reservoirs: Frontiers and challenges
Get PDFThis paper explores significant advancements in the numerical simulation of multiphase, multi-physics flows within underground reservoirs, driven by the necessity to understand and manage complex geological and engineered systems. It delves into the latest research in numerical simulation techniques at both the pore and Darcy scales, emphasizing the integration of traditional methods with emerging machine learning technologies. Key simulation methods reviewed at the pore scale include the lattice Boltzmann method, level set method, phase field method, and volume of fluid method, each offering unique advantages and facing limitations related to computational efficiency and stability. Special attention is given to spontaneous imbibition, where capillary action facilitates the movement of wetting fluids into porous media. Discussions at the Darcy scale focus on macroscopic simulation methods that simplify microscale interactions but face challenges in accurately modeling the multiscale and heterogeneous nature of fractured media. Furthermore, an overview of the basic principles, limitations, and potential of integrating machine learning algorithms with traditional numerical methods emphasizes their role in enhancing simulation efficiency and stability. Future research will aim to address existing challenges and maximize the use of advanced computational technologies to refine the accuracy, efficiency, and practical applicability of multiphase and multifield flow simulations in underground reservoirs.Document Type: Current minireviewCited as: Liu, P., Zhao, J., Li, Z., Wang, H. Numerical simulation of multiphase multi-physics flow in underground reservoirs: Frontiers and challenges. Capillarity, 2024, 12(3): 72-79. https://doi.org/10.46690/capi.2024.09.0
Numerical modeling of unsaturated flow in porous media using a thermodynamical approach
Get PDFThe Richards equation has been widely used to describe unsaturated flow in porous media, but its thermodynamical consistency has been scarcely investigated. In this paper, a thermodynamically consistent formulation of Richards equation is established on the basis of the free energy concept and the second law of thermodynamics. The capillary effect is described by an interfacial free energy and its corresponding chemical potential. The formulation takes the water saturation as the primary variable as well as chemical potential gradient as the primary driving force. An appealing feature is that the formulation follows an energy dissipation law, which implies the consistency to the second law of thermodynamics. Furthermore, a linearized and energy stable time discretized method is proposed for the model. Numerical results confirms the thermodynamical consistency of the formulation.Document Type: Original articleCited as: Kou, J., Wang, X. Numerical modeling of unsaturated flow in porous media using a thermodynamical approach. Capillarity, 2024, 11(3): 63-69. https://doi.org/10.46690/capi.2024.06.0
Mechanism of shale oil displacement by CO2 in nanopores: A molecular dynamics simulation study
Get PDFUtilizing CO2 to enhance shale oil recovery has a huge potential and thus has gained widespread popularity in recent years. However, the microscopic mechanisms of CO2 enhancing shale oil recovery remain poorly understood. In this paper, the molecular dynamics simulation method is adopted to investigate the replacement behavior of CO2 in shale oil reservoirs from a micro perspective. Three kinds of n-alkanes are selected as the simulative crude oil in silica nanopores. Molecular dynamics models are established to study the occurrence patterns of different alkanes on the rock surface and the alkane[1]stripping characteristics of CO2. The fluid density, mean square displacement and centroid variation are evaluated to reveal the effect of CO2 on alkanes. The results indicate that different alkanes exhibit varying occurrence characteristics of oil film on the rock surface of the shale reservoir. Specifically, a higher carbon number leads to a thicker oil film. Through the alkane molecular gaps, CO2 penetrates the alkane molecular system and reaches the rock surface to effectively strip the oil film of different alkane molecules. CO2 will more readily mix with the stripped oil molecules and displace them from the rock surface when the carbon number is small. The process for CO2 replacing crude oil on the rock surface can be divided into four typical stages, namely, CO2 diffusion, competitive adsorption, emulsification and dissolution, and CO2-alkanes miscible phase (for light alkanes). This study contributes to the improvement of micro-scale enhanced oil recovery mechanisms for shale oil via CO2 injection and provides a guidance for enhancing shale oil recovery by using CO2.Document Type: Original articleCited as: Wu, Z., Sun, Z., Shu, K., Jiang, S., Gou, Q., Chen, Z. Mechanism of shale oil displacement by CO2 in nanopores: A molecular dynamics simulation study. Advances in Geo-Energy Research, 2024, 11(2): 141-151. https://doi.org/10.46690/ager.2024.02.0
Energy storage in carbonate and basalt reservoirs: Investigating secondary imbibition in H2 and CO2 systems
Get PDFGas injection into geological storage sites displaces existing water in rock pore spaces, triggering lateral secondary imbibition. This phenomenon involves the migration of water from areas with higher water saturation to replenish the displaced water. The lateral distance over which this imbibition occurs is critical for understanding injection/withdrawal flow rates and trapped-gas saturation during hydrogen and carbon dioxide geological storage. This study investigates secondary imbibition dynamics in hydrogen and carbon dioxide systems for calcite (representing carbonates) and basalt, considering pressure and temperature effects. Utilizing the modified Lucas-Washburn equation, the results reveal that lateral distance and secondary imbibition rates of water for all gas and rock systems decline with pressure. Additionally, the lateral distance and secondary imbibition rate of water for the hydrogen system at carbonates and basalts, and the carbon dioxide system at carbonates, increase with temperature. However, the lateral distance and secondary imbibition rate of water for the carbon dioxide system at basalts decrease with temperature. This research provides crucial fundamental data with significant implications for underground hydrogen storage and carbon dioxide geological storage. The findings contribute to the understanding of lateral imbibition in carbonate and basaltic rocks, offering valuable insights for enhancing gas retention within pore spaces, thereby influencing residual trapping.Document Type: Original articleCited as: Hosseini, M., Ali, M., Fahimpour, J., Keshavarz, A., Iglauer, S. Energy storage in carbonate and basalt reservoirs: Investigating secondary imbibition in H2 and CO2 systems. Advances in Geo-Energy Research, 2024, 11(2): 132-140. https://doi.org/10.46690/ager.2024.02.0
Research on the optimization formula performance and dust reduction effect of mine dust suppressant based on response surface method
Get PDFIn this study, sodium dodecyl benzene sulfonate, triton, guar gum and sodium polyacrylate are selected as the composite raw materials of dust suppressants through the determination of physical and chemical properties of single components. Design expert software is used to carry out the mixture design, the determination of experimental parameters and the response surface analysis of the sedimentation rate, evaporation resistance property, surface tension, contact angle of coal dust with the reagent. According to the response surface analysis results, the optimal ratio of the reagent has been determined, which is 39.8% for sodium dodecyl benzene sulfonate, 53% for triton, 3.9% for guar gum, and 3.3% for sodium polyacrylate. The results of infrared spectrum show that the dust suppressant had a significant effect on the content change of hydroxyl of hydrophilic functional groups of coal dust. The results of scanning electron microscope experiments show that the dust suppressor has good wetting and binding effects on coal dust. The toxicity test shows that the coal sample did not have the acute inhalation toxicity characteristics of hazardous waste. The dust reduction experiment in similar space shows that the dust reduction efficiency of this new dust suppressants is 95.3%, which is 28.1% and 10.2% higher than that of natural dust fall and water spray dust fall. The conclusions of this study are of great significance for improving the dust reduction efficiency of mine dust suppressants, the dust prevention technologies, the working environment of underground workers, and reducing the incidence of pneumoconiosis.Document Type: Original articleCited as: Gao, N., Zhou, T., Jin, L., Fan, J., Tong, L., Zhang, B. Research on the optimization formula performance and dust reduction effect of mine dust suppressant based on response surface method. Advances in Geo-Energy Research, 2024, 11(2): 115-131. https://doi.org/10.46690/ager.2024.02.0
Effects of pore pressure on coring-induced damage based on simulation by mesoscale stress-flow coupling numerical model
Get PDFThe deep in-situ environment is often characterized by high pore pressure, which will be released during traditional coring in deep rocks and lead to damage in rock samples. Hence, a novel coring technology has been proposed and systematically investigated for preserving in-situ conditions, including pore pressure, to obtain rock samples with high fidelity to the deep in-situ environment. To theoretically examine the variation in pore pressure after coring and evaluate its influence on rock samples, two kinds of mesoscopic model representing closed-pore and open-pore were established and analyzed by stress flow coupling, in which both seepage in porous matrix and flow in relatively bigger cavities are considered. An elastic-plastic-damage model associated with volumetric dilatation was introduced to reflect tensile damage. The influences of pore pressure after different kinds of coring were simulated by a series of conceptualized models, and the results revealed three kinds of situations: Pore pressure removal, pore pressure release, and pore pressure preservation. During traditional coring, the high pore pressure will neither be sealed completely nor released suddenly because the rock matrix has low permeability. The higher residual permeation pressure in the rock matrix will be caused by lower permeability, larger closed cavities or smaller open cavities. During traditional coring, the coring-induced inner damage arises nearby closed cavities. Both the damage value and the damage zone are increased with decreasing permeability. However, extra tensile damages rarely arise during in-situ pore pressure-preserved coring, which technology can also retain in-situ high pressure. Hence, the in-situ pore pressure-preserved coring technology has great significance for eliminating the distortion effect of coring to the greatest possible extent.Document Type: Original articleCited as: Zhao, L., Peng, R., Hao, P., Yang, Y., Zhou, H. Effects of pore pressure on coring-induced damage based on simulation by mesoscale stress-flow coupling numerical model. Advances in Geo-Energy Research, 2024, 14(3): 170-186. https://doi.org/10.46690/ager.2024.12.0
Expanding role of borehole image logs in reservoir fracture and heterogeneity characterization: A review
Get PDFBorehole imaging well-log datasets provide a wide range of valuable information for various aspects of petroleum reservoir characterization. In particular, electrical borehole images make it possible to detect and quantify the distributions, orientations, and forms of fractures at high resolution. Acoustic borehole images are extensively used for breakout detection and width measurements to determine horizontal principal stress magnitudes and orientations. However, by combining information from different types of borehole imaging tools more comprehensive reservoir characterization can be achieved. Data from the dipole shear-wave imager can be used to provide anisotropy insights that are of complementary value for lithofacies, poro-permeability, and seismic dataset interpretations of heterogeneous reservoirs. Cases are made to incorporate data from both electrical and acoustic borehole imaging datasets into integrated reservoir characterization analysis. Moreover expanding the reach of borehole imaging data is becoming increasingly possible with the aid of machine learning models configured to predict key borehole imaging metrics from standard suites of petrophysical well-log and drilling mud-log datasets.Document Type: Invited reviewCite as: Wood, D. A. Expanding role of borehole image logs in reservoir fracture and heterogeneity characterization: A review. Advances in Geo-Energy Research, 2024, 12(3): 194-204. https://doi.org/10.46690/ager.2024.06.0