Numerical methods to simulate spontaneous imbibition in microscopic pore structures: A review

Spontaneous imbibition, as a fundamental flow phenomenon, is widely utilized in fossil energy production, carbon dioxide and underground hydrogen storage. With the development of computing, the exploration of flow laws of spontaneous imbibition has evolved from macroscopic theoretical models to pore-scale numerical analysis. Currently, the solutions for multiphase flow in pore media mainly consider the volume of fluid and the phase field, and have been classed into level set methods based on macroscopic Navier-Stokes equations and the Shan-Chen, free energy, color gradient, and phase-field methods based on mesoscopic lattice Boltzmann equations. However, no comprehensive review article has summarized the strengths and limitations of these methods. Therefore, this work focuses on critically reviewing and commenting on the fundamentals and limitations of porescale models applied to spontaneous imbibition. In addition, recent works applying these methods are systematically reviewed. Our study aims to provide the scientific community with an expert opinion to understand the basic methods for solving the existing problems of spontaneous imbibition in porous media. Future research directions are suggested, namely, focusing on developing the reconstruction pore medium algorithms, establishing modeling methods for non-stationary states, exploring the flow laws in mixed wetting conditions, linking macroscopic and microscopic flow laws, and developing models for coupled multiphase flow numerical computation with machine learning. Overall, this review provides a comprehensive understanding of spontaneous imbibition simulation methods, promotes a thorough knowledge of spontaneous imbibition in porous media, provides guidance on exploring flow laws, and inspires researchers to give more credit to spontaneous imbibition studies.Document Type: Invited reviewCited as: Zhou, Y., Guan, W., Zhao, C., Zou, X., He, Z., Zhao, H. Numerical methods to simulate spontaneous imbibition in microscopic pore structures: A review. Capillarity, 2024, 11(1): 1-21. https://doi.org/10.46690/capi.2024.04.0

Research on the optimization formula performance and dust reduction effect of mine dust suppressant based on response surface method

In 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 gravity and buoyancy on spontaneous liquid-liquid imbibition in fractured porous media

Spontaneous imbibition in porous materials has received significant attention in recent decades; however, spontaneous liquid-liquid imbibition in fractures has not been well studied. Specifically, the mechanism behind the influence of gravity and buoyancy on the spontaneous imbibition of wetting phase fluid into fractured porous media remains uncertain. In this study, an analytical solution for spontaneous imbibition in fractured porous media under the influence of gravity and buoyancy is presented. The results show that imbibition velocity with buoyancy and gravity is faster than that without these forces. The effect of buoyancy and gravity on imbibition velocity increases with rising fracture aperture and length. When the fracture aperture is less than 1 μm, the relative deviation between imbibition height with and without gravity and buoyancy is about 50%. On the other hand, when the fracture aperture is greater than 1 μm, the relative deviation is proportional to the fracture aperture. The relative reduction in imbibition height over time is not obvious when the fracture aperture is the same. In the process of water-oil spontaneous imbibition, the effect of buoyancy and gravity is more pronounced at low oil-water interfacial tension. Therefore, the effect of buoyancy and gravity on spontaneous imbibition cannot be ignored under this condition.Document Type: Original articleCited as: Cheng, H., Wang, F. Effects of gravity and buoyancy on spontaneous liquid-liquid imbibition in fractured porous media. Capillarity, 2024, 10(1): 1-11. https://doi.org/10.46690/capi.2024.01.0

Petrophysical recipe for in-situ CO2 mineralization in basalt rocks

In-situ carbon dioxide mineralization in basalt rocks has been identified as a scalable, fast, safe, permanent, and cost-effective method to offset the anthropogenic carbon dioxide emissions. In-situ carbon dioxide mineralization refers to underground carbon dioxide transformation to carbonate minerals in basalt reservoirs. Although current field applications achieved fast in-situ carbon dioxide mineralization, limited petrophysical criteria have been proposed to screen a potential site to implement in-situ carbon dioxide mineralization. To fill this knowledge gap, geochemical modellings were performed to find an optimal petrophysical recipe, including pressure, temperature, pH, and mineral composition, to conduct in-situ carbon dioxide mineralization. The geochemical modellings showed that increasing pressure was favourable to increase water uptake of carbon dioxide, host rock dissolution, and in-situ carbon dioxide mineralization. However, a higher temperature depressed the in-situ carbon dioxide mineralization. Furthermore, the in-situ carbon dioxide mineralization was unravelled to be heavily pH dependent. Most magnesite precipitated in pH range from 9 to 11. Moreover, the forsterite was identified as the major contributing minerals while anorthite, fayalite, and diopside played a minor role in the in-situ carbon dioxide mineralization. This investigation provided a general protocol to screen the optimal petrophysical conditions for in-situ carbon dioxide mineralization.Document Type: Original articleCited as: Chen, Y., Seyyedi, M., Clennell, B. Petrophysical recipe for in-situ CO2 mineralization in basalt rocks. Advances in Geo-Energy Research, 2024, 11(2): 152-160. https://doi.org/10.46690/ager.2024.02.0

Efforts to untie the multicollinearity knot and identify factors controlling macropore structures in shale oil reservoirs

Traditional correlation analyses based on whole-rock data have limitations in discerning pore development determinants in shale oil reservoir, given the complex lithology of shale formations and intricate interdependencies (multicollinearity) among geological variables. In this study, mercury injection capillary pressure and digital analysis of scanning electron microscopy were employed to examine the macropore structures of both whole rocks and their constituent lithologies for the Upper Triassic Chang-7 shale of the Ordos Basin. Variations were observed among clay shale (shale primarily consisting of clay-sized mineral grains), massive siltstone and silty laminae within the Chang-7 shale. Through the combination of correlation analysis and scanning electron microscope digital technique, it was demonstrated that total organic carbon content primarily controls the level of macropore development, while lithology primarily governs macropore types and structures. Although quartz and pyrite exhibit correlations with macropore volume, they do not emerge as primary factors; instead, they appear interconnected to total organic carbon. Due to detrital mineral framework preservation during compaction, larger macropores are more developed in massive siltstones and silty laminae than in clay shale. Additionally, silty laminae, situated closer to the source rock and influenced by organic acids, exhibit a higher abundance of larger dissolution pores, potentially favoring shale oil development. This study overcomes traditional method constraints, disentangling multi-correlations, and providing new insights into shale macropore development mechanisms, potentially advancing shale oil exploration and production.Document Type: Original articleCited as: Wang, Z., Dong, L., Jin, Z., Zou, S., Fu, J., Zhu, R. Efforts to untie the multicollinearity knot and identify factors controlling macropore structures in shale oil reservoirs. Advances in Geo-Energy Research, 2024, 11(3): 194-207. https://doi.org/10.46690/ager.2024.03.0

A critical review of capillary pressure behavior and characterization in fractional-wet reservoirs

Fractional wettability is common in oil and gas reservoirs, resulting in complex fluid distribution and transport phenomena. A precise understanding of capillary pressure behavior and characterization in fractional-wet reservoirs, including the two-phase flow mechanisms within pores and relationship between capillary pressure and saturation in porous media, is significant to enhanced oil recovery strategies. In this paper, an in-depth review of the two-phase flow mechanisms in fractional-wet pores and capillary entry pressures in various displacement processes was conducted. Furthermore, the effects of oil-wet proportion and contact angle on capillary pressure characterization were summarized, highlighting the emergence of similar capillary pressure curves under conditions of low oil-wet proportions. The prediction models for capillary pressure, containing empirical equations and physics-based models were discussed, with the aim of clarifying the most effective prediction methodologies. Finally, the review was finalized by outlining key findings and future directions for both experimental and theoretical studies in the realm of capillary pressure behavior and characterization.Document Type: Invited reviewCited as: Xiao, Y., You, Z., Wang, L., Du, Z. A critical review of capillary pressure behavior and characterization in fractional-wet reservoirs. Capillarity, 2024, 10(1): 12-21. https://doi.org/10.46690/capi.2024.01.0

Mechanism of shale oil displacement by CO2 in nanopores: A molecular dynamics simulation study

Utilizing 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

Geomechanical properties of hydrate-bearing strata and their applications

Natural gas hydrate is an alternative potential energy source that contributes to depressurizing the pressure of energy supply and environmental pollution in the future. Field hydrate production has a close association with geological risks. In this regard, accurate estimation of strength and deformation properties is crucial to risk prevention and control during hydrate development. However, the geomechanical properties of hydratebearing sediments and their applications remain unclear. Herein, this work provides a comprehensive summary of studies on the mechanical characteristics of hydrate-bearing sediments and their applications in field trials. It starts with the main research methods, including laboratory tests, constitutive modeling, and numerical simulations, followed by the effects of clay content, hydrate distribution, and morphology on mechanical properties. Besides, typical applications of geomechanical parameters are examined and discussed. Finally, the challenges and perspectives of mechanical studies on hydrate-bearing sediments are presented, which is favorable for the evaluation and control of geological risks during hydrate exploration and development.Document Type: PerspectiveCited as: Dong, L., Liu, X., Gong, B., Li, Y. Geomechanical properties of hydrate-bearing strata and their applications. Advances in Geo-Energy Research, 2024, 11(3): 161-167. https://doi.org/10.46690/ager.2024.03.0

Whole petroleum system theory and new directions for petroleum geology development

As the global petroleum exploration domain gradually shifts from conventional to unconventional hydrocarbon resources, the classical petroleum system theory faces new challenges in terms of guiding the deepening exploration practices in the petroleum industry. After years of research, Chengzao Jia proposed the whole petroleum system concept and established an orderly distribution model for the coexistence of conventional and unconventional petroleum, which provides a new theoretical framework for the joint assessment and integrated exploration of conventional and unconventional petroleum resources. In this context, the 1st International Symposium on Whole Petroleum System Theory and New Directions for Petroleum Geology Development was held in Beijing in October 2-3, 2023. The theme was “Whole petroleum system theory and new frontiers in petroleum exploration”. Experts engaged in in-depth discussions on the progress of whole petroleum system theory and development directions of petroleum geology; they systematically reviewed the new theory developments and advances in sequence stratigraphy, tight oil and gas, shale oil and gas reservoir characteristics, genetic mechanisms, and development mechanisms. The conference also proposed unified genetic models for conventional and unconventional petroleum resources, and novel methods and technologies for joint assessment. Furthermore, it also included case studies on the whole petroleum system in clastic and carbonate formations in oil and gas basins, challenges, opportunities, and new directions in the development of petroleum geology. This symposium provided a valuable opportunity for the petroleum geology community to gain a deep understanding of the “whole petroleum system theory” and to summarize and refine the development directions of petroleum geology. Undoubtedly, this event contributes to the advancement of the whole petroleum system theory, guiding the development of petroleum geology theory and further promoting the joint assessment and integrated future development and utilization of conventional and unconventional petroleum resources.Document Type: PerspectiveCited as: Hu, T., Pang, X., Jiang, F. Whole petroleum system theory and new directions for petroleum geology development. Advances in Geo-Energy Research, 2024, 11(1): 1-5. https://doi.org/10.46690/ager.2024.01.0

Novel method for the rapid evaluation of pressure depletion in tight oil reservoirs

Tight oil reservoirs hold immense development potential but are characterized by challenging reservoir properties, severe heterogeneity, and extremely low permeability and porosity. Massive hydraulic fracturing of horizontal wells is applied to achieve sustainable production in these reservoirs. The swift assessment of pressure depletion in tight reservoirs is essential for their successful and cost-effective development. Traditional pressure testing methods necessitate well shutdown, impacting subsequent production, while numerical simulation methods demand significant computational resources and expertise from technical personnel. To identify the sensitivity parameters influencing the reservoir pressure drop, this study uses a Plackett-Burman design and variance analysis. Using numerical simulations, variance analysis and multi-linear regression, we formulate evaluation indices and surrogate models for individual well depletion. The method’s reliability is validated through multiple experiments along with testing data. Our rapid evaluation method accurately assesses pressure depletion in typical well groups, with a fitting rate exceeding 85%. In regions where the pressure maintenance is below 80%, indicating severe reservoir depletion, enhanced oil recovery treatments, e.g., gas or water injection, are applied based on the evaluation results. The proposed method for evaluating individual well pressure depletions provides crucial guidance for realizing the efficient development of tight oil reservoirs.Document Type: Short communicationCited as: Ding, C., Chen, J., Yang, G., Bao, R., Dou, Y., Song, K. Novel method for the rapid evaluation of pressure depletion in tight oil reservoirs. Advances in Geo-Energy Research, 2024, 11(1): 74-80. https://doi.org/10.46690/ager.2024.01.0