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A novel integrated methodology for screening, assessment and ranking of promising oilfields for polymer floods
Get PDFDue to the deterioration of the structure of oil reserves, the demand for enhanced oil recovery technologies is increasing every year. These technologies are usually classified into the following: Chemical, gas, thermal and combined enhance oil recovery methods. Among the chemical methods, polymer flooding stands out. It has been actively studied since the middle of the last century and currently numbers hundreds of completed projects around the world. Despite the relatively long study period and the number of publications dedicated to polymer flooding, there is still a range of aspects requiring research and development as well as field testing. One of the crucial issues at the preparation stage of a polymer flooding project is necessity to select oilfield or pilot area to achieve the best possible technological and economic efficiency results. This article provides analysis of the key factors influencing effectiveness of polymer flooding implementation. The paper reflects historical evolution, i.e. expansion of the technology applicability limits. Their current values have been verified, based on the analysis of the experience of implementing the technology in extreme conditions. Applicability criteria has been established as well for the polymer flooding development. The paper includes development of a uniquely designed integrated methodology for screening, assessment and ranking of promising objects for the technology implementation. The methodology is designed on the basis of a background review of completed projects, as well as on the expertise of the specialists involved in the development and scientific support of chemical enhanced oil recovery projects implementation. The purpose of the methodology is to create a basic universal tool for an express assessment of the prospects for using polymer flooding in different fields, which a wide range of specialists in the oil and gas industry could apply.Document Type: Original articleCited as: Podoprigora, D. G., Byazrov, R. R., Lagutina, M. A., Arabov, D. V., Galimov V. V., Ermolin D. S. A novel integrated methodology for screening, assessment and ranking of promising oilfields for polymer floods. Advances in Geo-Energy Research, 2024, 12(1): 8-21. https://doi.org/10.46690/ager.2024.04.0
Wettability, interfacial tension, and capillary imbibition of nanomaterial-modified cross-linked gels for hydraulic fracturing
Get PDFFor the first time, systematic studies were conducted to investigate the effect of concentration, size, material, and shape of nanoadditives on the wettability, interfacial tension, and capillary imbibition rate of cross-linked gels for hydraulic fracturing. Guar gum biopolymer was used as the gelling agent and sodium tetraborate in glycerol was used as the crosslinker in the preparation of cross-linked gels. Spherical nanoparticles of silica and alumina, as well as single-walled carbon nanotubes, and alumina nanofibers were used as nanoadditives. The nanoparticles had an average size ranging from 11 to 216 nm, and their concentration in the gels ranged from 0.01 to 0.8 wt%. The study revealed a nonmonotonic dependence of the contact angle, interfacial tension coefficient, and capillary imbibition rate of nanomodified cross-linked gels on the concentration and average size of nanoparticles. The gels exhibited maximum hydrophobic properties at a nanoparticle concentration of 0.2 wt% and an average size of 70-80 nm. At the same time, the addition of single-walled carbon nanotubes has the most significant effect on the wettability properties of the gels, reducing the capillary imbibition rate by three times. Thus, it has been shown that controlling the concentration, size, material, and morphology of the nanoadditives can significantly alter the wetting characteristics of hydraulic fracturing fluids. This provides an opportunity for more flexible control of the hydraulic fracturing process depending on the reservoir characteristics.Document Type: Original articleCited as: Minakov, A. V., Pryazhnikov, M. I., Neverov, A. L., Sukhodaev, P. O., Zhigarev, V. A. Wettability, interfacial tension, and capillary imbibition of nanomaterial-modified cross-linked gels for hydraulic fracturing. Capillarity, 2024, 12(2): 27-40. https://doi.org/10.46690/capi.2024.08.0
Petrophysical recipe for in-situ CO2 mineralization in basalt rocks
Get PDFIn-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
In-situ emulsification and viscosification system of surfactant-assisted Janus nanofluid and its profile control effect
Get PDFTo construct the in-situ emulsification and viscosification system that is suitable for low permeability oil reservoirs characterized by high-temperature and high-salt, the amphiphilic Janus SiO2 nanoparticles and Tween 60/Imidazoline oleate surfactant system were combined. The mechanism of in-situ emulsification and viscosification system was elucidated from two aspects: The dynamic adsorption and phase conversion of surfactant, and the unique bridge structure of Janus nanoparticle stabilized emulsion. The successful synthesis of Janus SiO2 nanoparticles with varying degrees of hydrophilicity and hydrophobicity was achieved through regulating the reaction conditions. Based on emulsion stability, the optimization of the modification degree of Janus SiO2 nanoparticles was achieved. The in-situ emulsification and viscosification system was constructed by introducing Tween 60/Imidazoline oleate as dispersion aid agent and emulsifier. Notably, the in-situ emulsification and viscosification system can be stably dispersed for more than 12 hours in high-temperature and high-salt. The dispersion stability of the in-situ emulsification and viscosification system was evaluated qualitatively by visual inspection, Turbiscan stability index and monitoring particle size. The emulsification ability, emulsion stability and rheological properties of the systems with different concentrations were evaluated at 90 ◦C and a salinity of 35,000 ppm. It was found that the in-situ emulsification and viscosification system with the concentration of 0.64 wt% shows better profile control and enhanced recovery performance. This study presents a new approach for profile control using amphiphilic Janus nanoparticles and provides a promising prospect for applying nanoparticles in the field of enhanced oil recovery.Document Type: Original articleCited as: Wu, H., Chang, J., Xu, G., Shao, W., Li, G., Hou, J. In-situ emulsification and viscosification system of surfactant-assisted Janus nanofluid and its profile control effect. Advances in Geo-Energy Research, 2024, 14(2): 135-146. https://doi.org/10.46690/ager.2024.11.0
Analysis of core temperature variation and its influencing factors in deep rock in-situ temperature-preserved coring
Get PDFDeep rock in-situ temperature-preserved coring is important for the exploration and development of deep resources. In addition, understanding the temperature variation laws of the core during coring is fundamental to achieving temperature-preserved coring. In this study, under the coexistence of the core and strata water inside the coring tool, we explore the factors sensitive to the temperature variation of the core during coring and propose suggestions to reduce the unevenness of core temperature. The findings indicate that at a strata temperature of 150 ◦C and a core lifting speed of 2.5 m/s, during process of lifting the passively insulated core to the ground, natural convection occurs within the coring tool due to buoyancy, circulating in a counterclockwise direction. The temperature difference of the core in the axial and radial directions is 21 and 7.7 ◦C, respectively, with temperature variation rates of 21 and 308 ◦C/m per unit length, respectively. The greatest decrease in temperature is observed at the outer edge of the core bottom. The natural convection of strata water results in significant temperature differences along the axis of the core, exacerbating the unevenness of core temperature. To ensure uniform core temperature, efforts should be made to minimize the space between the core and the inner tube. In addition, the use of water-blocking mechanisms should be facilitated to reduce the ingress of strata water into the coring device. During the coring process, the frequency of active thermal insulation gradually increases as the ambient temperature decreases, thereby reducing the temperature difference between the inner and outer sides of the coring device to suppress the occurrence of natural convection. These research findings have practical implications for achieving deep rock in-situ temperature-preserved coring, providing theoretical and technical guidance for the development of deep resources such as coal, geothermal energy, and oil and gas.Document Type: Original articleCited as: Wei, Z., He, Z., Yang, J. Analysis of core temperature variation and its influencing factors in deep rock in-situ temperature-preserved coring. Advances in Geo-Energy Research, 2024, 14(3): 215-223. https://doi.org/10.46690/ager.2024.12.0
Pore-scale fluid flow simulation coupling lattice Boltzmann method and pore network model
Get PDFThe lattice Boltzmann method and pore network model are two types of the most popular pore-scale fluid flow simulation methods. As a direct numerical simulation method, lattice Boltzmann method simulates fluid flow directly in the realistic porous structures, characterized by high computational accuracy but low efficiency. On the contrary, pore network model simulates fluid flow in simplified regular pore networks of the real porous media, which is more computationally efficient, but fails to capture the detailed pore structures and flow processes. In past few years, significant efforts have been devoted to couple lattice Boltzmann method and pore network model to simulate fluid flow in porous media, aiming to combine the accuracy of lattice Boltzmann method and efficiency of pore network model. In this mini-review, the recent advances in pore-scale fluid flow simulation methods coupling lattice Boltzmann method and pore network model are summarized, in terms of single-phase flow, quasi-static two-phase drainage flow and dynamic two-phase flow in porous media, demonstrating that coupling the lattice Boltzmann method and pore network model offers a promising and effective approach for addressing the up-scaling problem of flow in porous media.Document Type: Current minireviewCited as: Zhao, J., Liu, Y., Qin, F., Fei, L. Pore-scale fluid flow simulation coupling lattice Boltzmann method and pore network model. Capillarity, 2023, 7(3): 41-46. https://doi.org/10.46690/capi.2023.06.0
Effect of TiO2–SiO2 hybrid nanofluids on enhanced oil recovery process under different wettability conditions
Get PDFThe effect of TiO2–SiO2 hybrid nanofluid on the enhanced oil recovery process is experimentally investigated. The flooding efficiency is measured for a flooding process in an initially oil-filled transparent micro-porous medium. Measurements were performed for two different surface wettability conditions, namely water-wet and neutral-wet. The average nanoparticle size, viscosity, surface tension, and contact angle of TiO2–SiO2 hybrid nanofluid are reported. The flooding efficiency of the hybrid nanofluid is compared with that of SiO2 nanofluid and TiO2 nanofluid. The experimental results reveal that for neutral-wet surface condition, SiO2 nanofluid achieves the best recovery, whereas for water-wet surface condition, TiO2–SiO2 hybrid nanofluid produces the best flooding efficiency. Obtained results showed that TiO2 nanofluid is unstable, with larger aggregated particles settling under gravity, and therefore not suitable for the flooding process by itself. The efficiency of hybrid nanofluid flooding depends significantly on fluid stability, wettability of the porous wall, surface tension, and contact angle of the three phases (crude oil, nanofluid solution, and solid surface). The TiO2–SiO2 hybrid nanofluid reduces surface tension while increasing contact angle and solution stability.Document Type: Original articleCited as: Goharzadeh, A., Fatt, Y. Y., Sangwai, J. S. Effect of TiO2 – SiO2 hybrid nanofluids on enhanced oil recovery process under different wettability conditions. Capillarity, 2023, 8(1): 1-10. https://doi.org/10.46690/capi.2023.07.0
Recovery mechanisms and formation influencing factors of miscible CO2 huff-n-puff processes in shale oil reservoirs: A systematic review
Get PDFShale oil production is vital for meeting the rising global energy demand, while primary recovery rates are poor due to the ultralow permeability. CO2 huff-n-puff can boost yields by enabling key enhanced oil recovery mechanisms. This review examines the recent research on mechanisms and formation factors influencing CO2 huff-n-puff performance in shale liquid reservoirs. During the soaking period, oil swelling, viscosity reduction and CO2-oil miscibility occur through molecular diffusion into shale nanopores. The main recovery mechanism during the puff period is depressurization with oil desorption and elastic energy release. The interplay between matrix permeability and fracture network directly determines the CO2 huff-n-puff performance. Nanopore confinement, wettability alterations, and heterogeneity also significantly impact the huff-n-puff processes, with controversial effects under certain conditions. This work provides an integrated discussion on the mechanistic insights and formation considerations essential for the advancement of CO2 huff-n-puff application in shale reservoirs. By synthesizing the recent research findings, we aim to spotlight the key challenges and opportunities in considering reservoirs for this process, thereby contributing to the advancement of CO2 huff-n-puff applications for enhanced oil recovery.Ducument Type: Invite reviewCites as: Wan, Y., Jia, C., Lv, W., Jia, N., Jiang, L., Wang, Y. Recovery mechanisms and formation influencing factors of miscible CO2 huff-n-puff processes in shale oil reservoirs: A systematic review. Advances in Geo-Energy Research, 2024, 11(2): 88-102. https://doi.org/10.46690/ager.2024.02.0
A numerical analysis of background flow velocity effects on long-term post-injection migration of CO2 plumes in tilted storage aquifers
Get PDFEven though groundwater flow exists in many saline aquifers, very few studies have investigated its significance on the injected CO2 migration and trapping processes. Here, a numerical simulation approach is used to study the late post-injection migration and trapping of CO2 injected into a tilted aquifer. The analysis highlights that although the migration of the CO2 and its dissolution in brine is induced by buoyancy, the existence of background flow can further affect the plume velocity, convective dissolution, the dissolved CO2 flux and its distribution in the storage complex. Our analysis shows that the background flow removes the residual CO2, by dissolution, before the convective dissolution of the mobile part becomes dominant. The plume decelerates during its vertical migration by a factor of 6.5; then, its height increases with time to more than 15% as background flow velocity increases, hence reducing its rate of deceleration. However, when the plume reaches its maximum height, it migrates with a constant velocity. Greater background flow velocity not only allows the plume to migrate further, but it may hinder CO2 dissolution. This is because it can transport the dissolved CO2 underneath the plume for a long time, thus slowing down the interaction at the CO2-brine interface. The weak and strong background flows can impact the tendency of the dissolved CO2 to persist underneath the caprock. Our results indicate the existence of a critical background flow velocity which can control the distribution of the dissolved CO2 at the bottom of the aquifer, further away from the caprock.Document Type: Original article Cited as: Awag, M., Mackay, E., Ghanbari, S. A numerical analysis of background flow velocity effects on long-term post-injection migration of CO2 plumes in tilted storage aquifers. Advances in Geo-Energy Research, 2024, 11(2): 103-114. https://doi.org/10.46690/ager.2024.02.0
Enhanced oil recovery in complex reservoirs: Challenges and methods
Get PDFEnhanced oil recovery draws increasingly interests from the research and development phases to oilfield implementation worldwide. Due to the complexity of the developed reservoirs and requirement of carbon footprint reduction, new innovations are urgently needed to increase enhanced oil recovery efficiency and/or reduce emissions simultane- ously. This paper presents the strategies to improve the enhanced oil recovery performance of carbon dioxide flooding, polymer flooding and imbibition in complex reservoirs. Field trials conducted at Mahu reservoirs demonstrated the potential of nanoemulsion imbibition in stimulating tight oil recovery. These results can provide constructive envision for the development and application of enhanced oil recovery technologies for challenging systems.Document Type: PerspectiveCited as: Wu, R., Wei, B., Li, S., Zhang, Y., Luo, Q. Enhanced oil recovery in complex reservoirs: Challenges and methods. Advances in Geo-Energy Research, 2023, 10(3): 208-212. https://doi.org/10.46690/ager.2023.12.0