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Chemical agents designed for oilfield development: A new paradigm empowered by artificial intelligence
Get PDFWith the ongoing rise in global energy demand, the importance of enhanced oil recovery in oilfield development is becoming increasingly prominent. However, traditional chemical flooding agents face bottlenecks such as poor adaptability to application environments, unclear coupling mechanisms regarding multiple factors, as well as long research and development cycles. This paper systematically discusses the innovative paradigm of oilfield chemical agent development driven by artificial intelligence and proposes four core technological breakthroughs. Firstly, artificial intelligence-empowered molecular simulation technology can reveal the behavior mechanisms of flooding agents under extreme conditions. Secondly, intelligent molecular design using generative adversarial networks and reinforcement learning breaks through the traditional trial-and-error model. Thirdly, the construction of a data-mechanism dual-driven multi-objective optimization model achieves the collaborative prediction of physicochemical properties, economic benefits and environ mental friendliness. Lastly, an integrated system of robotic chemist and high-throughput experimental platforms forms a closed-loop system of “artificial intelligence design - automated synthesis- online detection”, yielding a complete ecosystem. The analysis of the current technological development challenges and future development directions reveals that the artificial intelligence-empowered intelligent Research and Development system is expected to promote the transformation of chemical flooding technology toward efficiency, environmental protection and sustainable development, providing a new standard for intelligent oil and gas field development.Document Type: Invited reviewCited as: Wei, K., Zhou, M., Huang, J., Zhang, Q., Ding, B., Lyu, W., Peng, M. Chemical agents designed for oilfield development: A new paradigm empowered by artificial intelligence. Advances in Geo-Energy Research, 2025, 17(1): 1-16. https://doi.org/10.46690/ager.2025.07.0
Heterogeneity and anisotropy of tight conglomerates: Mechanisms and implications
Get PDFTight conglomerate reservoirs pose challenges to development due to their strong heterogeneity and anisotropy, while existing characterization technologies have limitations such as cumbersome sample preparation and low efficiency. Additionally, the microscale coupling mechanism among pores, elements, and components remains unclear. To address these issues, this study aims to reveal the controlling mechanisms of such reservoir features and establish an integrated characterization system. This system couples macrolens infrared thermal imaging, umbrella deconstruction, field emission scanning electron microscopy, and energy dispersive spectroscopy, and adopts eight-directional physical slicing to systematically characterize the pores, elements, and components of tight conglomerate reservoirs. Results indicate that pores are more developed in specific directions. Characteristic elements exhibit distinct directional enrichment and depletion: Some elements reach high contents in certain directions, while others drop to very low levels. Mineral contents show angle-dependent variations; for example, the proportion of weakly weathered feldspar increases significantly with increasing angle. All these features are synergistically controlled by the original sedimentary fabric and late-stage diagenesis. This work enriches the microscopic characterization theory of tight reservoirs, provides microscopic evidence for identifying favorable reservoir zones, and offers direct technical support for optimizing wellbore deployment and avoiding high-risk fracturing areas in engineering practice.Document Type: Original articleCited as: Zhou, B., Du, S., Wei, Y., Zong, Z., Duan, X., Wang, Y. Heterogeneity and anisotropy of tight conglomerates: Mechanisms and implications. Advances in Geo-Energy Research, 2025, 18(1): 7-20. https://doi.org/10.46690/ager.2025.10.0
Novel encapsulated surfactants for enhanced oil recovery in carbonate reservoir conditions: Interfacial and wetting behavior
Get PDFSurfactant encapsulation presents a novel strategy for the targeted delivery of active molecules to oil reservoirs. This study investigates the interfacial tension, wettability alteration, static adsorption and oil displacement performance of two novel encapsulated surfactants, anionic alkyl ether carboxylate and non-ionic alkyl polyglucoside, in water-oil and water-oil-carbonate rock systems. A refined synthesis yielded silica carriers with dimensions appropriate for transport through carbonate reservoir pore networks, preventing pore blockage while enabling effective delivery. A synergism between the surfactants and silica nanoparticles, released upon carrier rupture, was confirmed. The cooperative action of silica nanoparticles and surfactant molecules, facilitated by multiple intermolecular forces, including hydrogen bonding, electrostatic, and hydrophobic, enhanced the efficiency of interfacial adsorption, leading to a significant reduction in interfacial tension compared to pure surfactant systems. Furthermore, silica nanoparticles accelerated the alteration in wettability towards a hydrophilic state via disjoining pressure and competitive adsorption on the carbonate surface. Consequently, the simultaneous enhancement of interfacial behavior and mitigation of static adsorption due to encapsulation translated into more efficient oil displacement compared to use of the pure surfactants. This work demonstrates that encapsulation not only reduces adsorption but also enhances interfacial performance and displacement efficiency, supporting its potential application in chemical enhanced oil recovery.Document Type: Original articleCited as: Chekalov, A., Ivanova, A., Sokolov, A., Sukhorukov, G., Cheremisin, A., Yuan, C. Novel encapsulated surfactants for enhanced oil recovery in carbonate reservoir conditions: Interfacial and wetting behavior. Advances in Geo-Energy Research, 2025, 18(3): 272-286. https://doi.org/10.46690/ager.2025.12.0
Multi-factorial predictive model linking acoustic characteristics with geotechnical parameters in deep-water shallow formations
Get PDFOffshore infrastructure stability is controlled by deep-water shallow sediments, and the geotechnical-acoustic correlation between the two enables geological property prediction from acoustic waves. However, existing models often rely on limited sediment types or regional data, constraining their generalizability across a range of marine environments. This study presents a novel predictive model that uses a theoretical framework extending Biot’s theory to integrate key geotechnical properties-clay content, density, water content, and shear strength-with acoustic parameters. By establishing the theoretical relationship between sediment parameters and acoustic responses, P-wave velocity and attenuation coefficients are computed under a range of conditions. Single-factor predictive models for each geotechnical property are derived through numerical fitting and rigorously validated against experimental data. These individual models are subsequently integrated into a comprehensive multi-factor model using multiple linear regression. Analysis of variance and Spearman’s correlation analysis statistically confirm that these four parameters exert a significant and substantial influence on acoustic wave behavior. The capability of the model to simultaneously invert for multiple geotechnical properties from acoustic datasets makes it a practical tool for pre-drilling sediment characterization, enabling a more reliable, non-invasive method for site investigation that can reduce planning risks and costs. By improving the accuracy of sediment property assessment, the model contributes directly to enhanced geohazard identification and mitigation strategies, thereby promoting greater safety in the development of deep-water marine resources.Document Type: Original articleCited as: Li, L., Wang, H., Sun, Y., Yang, J., Zhang, D., Hao, M. Multi-factorial predictive model linking acoustic characteristics with geotechnical parameters in deep-water shallow formations. Advances in Geo-Energy Research, 2025, 18(3): 257-271. https://doi.org/10.46690/ager.2025.12.0
Development of a reactive transport solver in MATLAB Reservoir Simulation Toolbox using the fully-implicit sequential iterative approach
Get PDFDifferent operations dealing with the subsurface, such as subsurface CO2 disposal, hazardous waste disposal, geothermal energy extraction, underground hydrogen storage, etc., can change the fluid/flow system underground. The injection of fluids with thermodynamic and chemical properties different from those of the reservoir fluid can trigger a series of chemical reactions, which may affect the fluid and/or rock properties. Depending on the system under study, these changes may be advantageous or unfavorable. Reactive transport modeling is a choice for investigating how these changes can alter the system. In this study, a reactive transport solver is developed in the MATLAB Reservoir Simulation Toolbox using the sequential fully-implicit approach. The developed reactive transport solver is illustrated using reactions and geometries using reactions and geometries relevant for assessing the sealing capacity of a fractured caprock of a deep saline aquifer used for underground CO2 disposal, and the limitations and advantages of the approach are stated. Moreover, the results of the simulation for two fracture models, the discrete fracture matrix and embedded discrete fracture matrix models, are compared. The simulations demonstrate that hydrogen ion concentration or pH is the primary parameter affecting the extent of dissolution, while the other aqueous species concentrations are less influential. It is also shown that at higher flow rates, dissolution substantially occurs in the vicinity of the main fracture, along the flow direction, while at lower flow rates, because the injected fluid becomes fully buffered closer to the inlet, dissolution only occurs in the vicinity of the inlet over the course of the simulation. Applying the discrete fracture matrix and embedded discrete fracture matrix models to one of the scenarios demonstrates that both yield equivalent results.Document Type: Original articleCited as: Moslehi, S., Fazeli, H., Doster, F., Kord, S. Development of a reactive transport solver in MATLAB Reservoir Simulation Toolbox using the fully-implicit sequential iterative approach. Advances in Geo-Energy Research, 2025, 16(2): 114-130. https://doi.org/10.46690/ager.2025.05.0
Numerical and semi-analytical modelling of the capillary end effect for porous media of any wettability state
Get PDFThe capillary end effect appears in a two-phase displacement process as a physical consequence of the capillary discontinuity at the system outlet and causes accumulation of the wetting phase at this location and back along the system. In the study of water injection into a one-dimensional system, to obtain accurate phase saturation profiles in the presence of the capillary end effect at any time during the transient state, conventional implicit pressure explicit saturation and one-dimensional convection-diffusion methods have been modified by applying a novel boundary condition. This modification is entirely physics-based, whereas in commercial simulators fix-up procedures are applied which do not conserve mass. A new term “exit saturation” is introduced which provides a useful way to study and analyse the capillary end effect. Transient-state flow development in the presence of the capillary end effect in different wetting systems is presented in detail in this work. Also, several methods are presented to obtain steady-state saturation profiles. At steady-state conditions, the capillary end effect vanishes in purely water-wet systems and all oil in principle can be displaced from the system in a finite, but very long time. However, in mixed- and oil-wet systems, some oil is permanently trapped in the system at any chosen flowrate, i.e., the capillary end effect cannot be entirely removed no matter how large the flowrate is. However, oil recovery is improved by increasing the flowrate.Document Type: Original articleCited as: Goodarzian, S., Sorbie, K. S. Numerical and semi-analytical modelling of the capillary end effect for porous media of any wettability state. Capillarity, 2025, 14(3): 82-99. https://doi.org/10.46690/capi.2025.03.0
Impact of pore-scale corner and film flows on macroscopic transport in porous media
Get PDFCapillary pressure-saturation and relative permeability curves are crucial for predicting multiphase fluid flow behavior in porous media, directly influencing the efficiency and reliability of subsurface engineering applications. At low saturations, the wetting-phase flow transitions from bulk displacement to being governed by corner and film flows along pore surfaces. Recent experiments and pore-scale simulations have shown that these microscale flow mechanisms preserve fluid connectivity and continue to influence macroscopic transport behavior, even after bulk flow pathways are no longer active. This work synthesizes current experimental and computational findings, highlighting how the formation and persistence of microscale flow networks made of corner and film flows influence capillary pressure and relative permeability curves, especially by enhancing wetting-phase connectivity at low wetting-phase saturations. Finally, key directions for future research are proposed to further enhance the understanding of how microscale film and corner flows influence macroscopic multiphase flow characteristics.Document Type: PerspectiveCited as: Lan, T., Hu, R., Zhao, B. Impact of pore-scale corner and film flows on macroscopic transport in porous media. Capillarity, 2025, 16(1): 1-4. https://doi.org/10.46690/capi.2025.07.0
Experimental study of carbonated water imbibition in deep coal rocks using nuclear magnetic resonance spectroscopy
Get PDFThe deep eastern edge of the Ordos Basin is rich in coalbed methane, presenting great potential for development. Meanwhile, CO₂ imbibition is an important method to increase production. To study the CO₂-water-rock interactions and microstructural damage characteristics before and after supercritical carbon dioxide immersion in deep coal rocks, CO₂ imbibition experiments were conducted on these rocks by using nuclear magnetic resonance and scanning electron microscopy imaging techniques. The results showed that CO₂ imbibition leads to pore dilatation and reveals the key role of coal rock anisotropy on imbibition efficiency under different physicochemical conditions. Specifically, the immersion of CO₂ produces cracks due to the brittle action of the coal rock, as well as calcite dissolution that exacerbates crack production and expansion. Due to adsorption of CO₂, part of the coal rock becomes swollen, which leads to detachment and changed the physical properties and surface characteristics of the coal rock.Document Type: Original articleCited as: Yang, L., Liu, Z., Zhao, Z., Li, W., Ding, J., Sun, L. Experimental study of carbonated water imbibition in deep coal rocks using nuclear magnetic resonance spectroscopy. Capillarity, 2025, 16(2): 27-38. https://doi.org/10.46690/capi.2025.08.0
Deviation of macro-micro tubing direct transition in liquid f low comparing to the constructal transition: Experimental study and CFD simulation
Get PDFCapillary tubes have growing domain in heat transfer applications. However, complexity of micro pumps and macro-micro constructal optimum transition section impede this growth, especially for polymeric microtubes. In this study, a simplified macro-micro transition section is proposed, analyzed and tested. Three dimensional computational fluid dynamics numerical simulation was conducted to compare between the direct simplified model and the optimal constructal model. In addition, fabrication and experimental testing of the proposed design is done to study the fluid flow behavior in such design and distribution. The numerical results of pressure fields produce comparable pressure drop outcome of the direct transition design. Further, it is notable that the drop in pressure drop increases with increasing flow rate, the fact that encourages utilizing this design for higher flow rates. Moreover, the proposed direct transition design provide a well distributed flow achieved from both the numerical results and experimental measurements. The pressure drop gradient between the central and peripheral branches is very small comparing to the pressure drop. However, this gradient increases with increasing flow rate. The flow velocity of the direct transition was comparable to that of the constructal design. The flow velocity elevation in the direct design increases with increasing flow rate. The numerical simulations consolidated by the experimental results about the fairly approximate flow velocity in the micro-branches in the direct transition design. The suggested design was applied for a liquid cooling vest system successfully and can be applied for several further micro applications.Document Type: Original articleCited as: Abdulelah, A., Ali, L. F. Deviation of macro-micro tubing direct transition in liquid flow comparing to the constructal transition: Experimental study and CFD simulation. Capillarity, 2025, 15(2): 44-52. https://doi.org/10.46690/capi.2025.05.0
Revisiting the role of fluid imbibition in the hydrocarbon recovery processes from shale reservoirs
Get PDFSpontaneous imbibition has recently received a great deal of research attention for improving hydrocarbon recovery from shale gas and oil reservoirs. It is highly desirable to know the true significance and the role of fluid imbibition in the recovery process. Using a Krüss Drop Shape Analyzer 100S with Krüss’ Advance software, water imbibition depth was measured in this study on dry cores from four shale gas/oil reservoirs namely Tuscaloosa Marine Shale, Eagle Fort Shale, Marcellus Shale, and Green River Shale. The initial water-contact angles on the Tuscaloosa Marine Shale, Eagle Fort Shale, Marcellus Shale and Green River Shale core surfaces were measured to be 36.62◦, 66.68◦, 52.78◦ and 84.73◦, respectively. The contact angle and thus volume of liquid droplet changed due to fluid imbibition into the core samples and evaporation. The change in droplet volume, together with the contact area and shale porosity, was used to calculate the imbibition depth. An analytical imbibition model was derived and tuned to upscale the tested fluid imbibition data to field level. The result of time-upscaling using the tuned imbibition models shows that the 1-month water imbibition depths for the Tuscaloosa Marine Shale, Eagle Fort Shale, Marcellus Shale and Green River Shale are 2.61, 1.59, 0.89 and 0.16 cm, respectively. These low values suggest that the direct effect of water imbibition into shale matrix on hydrocarbon recovery in shale reservoirs is insignificant in the practical scales of space and time. However, the imbibition-induced shale cracks can increase shale permeability significantly for mass transfer during the hydrocarbon recovery process. Water imbibition in the cracks should be investigated in future studies.Document Type: Original articleCited as: Guo, B., Wortman, P. Revisiting the role of fluid imbibition in the hydrocarbon recovery processes from shale reservoirs. Capillarity, 2025, 15(2): 25-32. https://doi.org/10.46690/capi.2025.05.01