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Characteristics of gas-oil contact and mobilization limit during gas-assisted gravity drainage process
Get PDFGravity can reduce the instability of the gas-oil contact that is caused by gas channeling in locations with low flow resistance, such as high-permeability layers, macropores, and fractures during the gas-assisted gravity drainage process. Herein, the microscopic forces during the gas-assisted gravity drainage process were analyzed and combined with the capillary model to study the occurrence boundary of gas-assisted gravity drainage process, and the characteristics of the gas-oil contact in the gas-assisted gravity drainage process was discussed. The results show that free gravity drainage occurs only in pores where a certain height of the oil column and pore radius are reached. Furthermore, the lower the oil-gas interface migration rate, the easier free gravity drainage occurs. In other scenarios, additional gas injection is required. During the gas-assisted gravity drainage process, the gas-oil contact moves down stably as a transition. The width of the transition zone and the available pore radius are related to the gas-oil contact migration rate and the oil viscosity; the smaller the gas-oil contact migration rate and the lower the oil viscosity, the smaller pore throat can be involved in mobilization. Optimizing the gas injection rate and reducing the oil viscosity can delay the gas channeling maturity time, which is beneficial for the realization of the gas-assisted gravity drainage process. Finally, a method considering micropore heterogeneity is established for determining the critical gas injection rate, while the mainstream pore throat can be involved in mobilization and the gas-oil contact can be stabilized at the same time. The method of determining the critical gas injection rate can help researchers and reservoir engineers to better understand and implement the gas-assisted gravity drainage process.Cited as: Kong, D., Gao, J., Lian, P., Zheng, R, Zhu, W., Xu, Y. Characteristics of gas-oil contact and mobilization limit during gas-assisted gravity drainage process. Advances in Geo-Energy Research, 2022, 6(2): 169-176. https://doi.org/10.46690/ager.2022.02.0
Modeling of counter-current spontaneous imbibition in independent capillaries with unequal diameters
Get PDFSpontaneous imbibition is a crucial process for oil recovery from fractured and unconventional reservoirs. Herein, with the assumption of capillaries being independent, a new mathematical model for spontaneous imbibition is proposed and solved using a numerical method. The simulated results show that the wetting phase preferentially enters smaller capillaries where the advancement velocity is higher than that in larger ones, while the non-wetting phase can be displaced out in the larger capillaries. In addition, the effect of fluid viscosity ratio on counter-current imbibition is analyzed. The results show that imbibition velocity becomes higher with the increase in the viscosity ratio. When the viscosity of the non-wetting phase is larger than that of the wetting phase, the end pressure gradually increases as the imbibition front advances. In contrast, when the viscosity of the non-wetting phase is less than that of the wetting phase, the end pressure decreases with the infiltration. With a higher viscosity ratio of non-wetting and wetting phase, the heterogeneity of the interface advancement among different capillaries increases.Cited as: Chen, K., Xu, H., Zhang, Z., Meng, Q., Zhang, T. Modeling of counter-current spontaneous imbibition in independent capillaries with unequal diameters. Capillarity, 2022, 5(6): 115-122. https://doi.org/10.46690/capi.2022.06.0
Reservoir characterization and multiphase flow property in the upper Minnelusa sandstone: Implication for geological carbon storage
Get PDFThis report summarizes the reservoir characterization [Wang et al., J. Hydrol., 2022] and multiphase flow property [Kou et al., J. Hydrol., 2021] in a target deep saline aquifer, upper Minnelusa sandstone in Wyoming. Multiscale petrophysical characterization and flow unit classification were carried out to identify two different facies groups: cross-bedded and massive sandstone. Based on the rock typing results, two representative core samples were selected accordingly to conduct coreflooding experiments. Results illustrate that the sub-core scale heterogeneity significantly affects CO2 -brine multiphase flow properties. As a result, the subcore scale heterogeneity should be considered during CO2 injection to reduce the uncertainties in storage and fluid flow.Cited as: Kou, Z., Wang, H., Alvarado, V. Reservoir characterization and multiphase flow property in the upper Minnelusa sandstone: Implication for geological carbon storage. Advances in Geo-Energy Research, 2022, 6(6): 535-536. https://doi.org/10.46690/ager.2022.06.1
Experimental and numerical analysis of imbibition processes in a corrugated capillary tube
Get PDFSpontaneous imbibition is a capillary-driven flow phenomenon that exists widely in nature and is important for several industries. Recently, Tolman length has been introduced to improve the classical Lucas-Washburn imbibition model, in order to alleviate the deviations in calculating the capillary pressure. However, imbibition experiments to measure Tolman length have been scarce. In addition, the fluid-wall friction has a considerable impact on the imbibition process, while it is often ignored. In this work, imbibition experiments under specific conditions are carried out to measure the values of Tolman length, and the fluid-wall friction is taken into consideration in the equilibrium equation. The water uptake model in fractures is adopted to make corrections to the rise of water level. The experimental results show that Tolman length decreases first and then rises with the increasing curvature radius of liquid-gas interface. The data reveal that the Tolman length-based model can better describe the real imbibition processes than the classical Lucas-Washburn model.Cited as: Wang, J., Salama, A., Kou, J. Experimental and numerical analysis of imbibition processes in a corrugated capillary tube. Capillarity, 2022, 5(5): 83-90. https://doi.org/10.46690/capi.2022.05.0
Sorption characteristics in coal and shale: A review for enhanced methane recovery
Get PDFThe exploration and exploitation of hydrocarbon resources within coal and shale reservoirs is an engineering challenge. Well-developed internal micro-pore structures, complex sorption mechanism as well as numerous influencing factors affecting the gas flow are generally not well-accounted in the commercial life-cycle of shale gas and coalbed methane wells. Although large number of studies have been conducted to propose improved sorption models and study the influencing factors on adsorption and desorption characteristics of methane and CO2 in coal and shale reservoirs, a systematic review of such studies for efficient understanding of the accumulated literature is missing, especially with a focus towards coal and shale reservoirs. In that context, this study presents a review of sorption characteristics of methane in coal and shale. Firstly, theoretical mechanisms for methane sorption are introduced, followed by description of sorption models. Further, three factors influencing the sorption of gas in coal and shale are described: total organic carbon and clays, pore structures, and reservoir conditions. Finally, the preferential sorption characteristics of hydrocarbons and carbon dioxide are described, and the methods to promote methane desorption for enhanced recovery are discussed, which include technologies such as gas injection, microwave heating, and hydraulic fracturing.Cited as: Qin, X., Harpreet, S., Cai, J. Sorption characteristics in coal and shale: A review for enhanced methane recovery. Capillarity, 2022, 5(1): 1-11. https://doi.org/10.46690/capi.2022.01.0
Structural deformation of shale pores in the fold-thrust belt: The Wufeng-Longmaxi shale in the Anchang Syncline of Central Yangtze Block
Get PDFThe gas-rich Wufeng-Longmaxi shale has been intensely deformed within the fold-thrust belt of the Yangtze Block. To better understand the impact of structural deformation on the shale pore system, this paper systematically investigated the matrix components, porosity and pore structures in core samples from theWufeng-Longmaxi shale, newly collected from various structural domains in the first commercial shale gas field of the Central Yangtze Block, the Anchang Syncline. The shale porosity generally showed a positive relationship with total organic carbon content. Nevertheless, even at a constant total organic carbon content, the shale porosity decreased from the syncline limb to the syncline hinge zone and with a decreasing interlimb angle in the syncline hinge zone, which aligned with the structural deformation strain during folding. The artificial axial compression of shale samples also confirmed that the decrease in shale porosity was stronger at an elevated axial compression stress and was relatively higher in samples with higher total organic carbon content. The organic pore size decreased with higher structural deformation strain, but the aspect ratio of the pore shape increased. Even quartz failed to resist the effective stress under the intensive structural deformation, changing the correlation between porosity and quartz from positive to negative. In contrast, pore spaces generated by the slipping between clay flakes under intensive deformation accounted for a positive relationship between clay content and bulk porosity. Considering the shale porosity reduction caused by the intensive structural deformation of shale pores, the Wufeng-Longmaxi shale, that is rich in fracture networks between roof and floor layers, may still be an excellent exploration target in the fold-thrust belt of the Yangtze Block.Cited as: Guo, X., Liu, R., Xu, S., Feng, B., Wen, T., Zhang, T. Structural deformation of shale pores in the fold-thrust belt: The Wufeng-Longmaxi shale in the Anchang Syncline of Central Yangtze Block. Advances in Geo-Energy Research, 2022, 6(6): 515-530. https://doi.org/10.46690/ager.2022.06.0
Geological characteristics and main challenges of onshore deep oil and gas development in China
Get PDFMore than 30 years of continuous development has made onshore deep and ultra-deep conventional and unconventional oil and gas become an integral part of increasing the energy reserves and output by China’s petroleum industry. Based on the deep oil and gas geological conditions in the country, the present study finds that paleo stratum and deep burial are the two basic geological characteristics of deep oil and gas. Furthermore, we put forward the notion that it is necessary to strengthen the fundamental research of theories in four aspects and the core technology in five aspects of deep oil and gas. It is suggested that it is of special importance to promote the scientific and technological research of deep oil and gas through the scientific exploration of “myriameter deep” wells as the starting point, so as to boost the development of deep oil and gas field in China.Cited as: Yang, Z., Zou, C., Gu, Z., Yang, F., Li, J., Wang, X. Geological characteristics and main challenges of onshore deep oil and gas development in China. Advances in Geo-Energy Research, 2022, 6(3): 264-266. https://doi.org/10.46690/ager.2022.03.0
Controlling effect of tectonic-paleogeomorphology on deposition in the south of Lufeng sag, Pearl River Mouth Basin
Get PDFPaleogene depositional systems in the south of Lufeng sag have complex spatial distribution, which are influenced by pre-depositional paleogeomorphology and multi-period tectonic activities. In this paper, to clarify the controlling effect of tectonic-paleogeomorphology on sedimentary facies distribution and effectively guide oil and gas exploration, the Paleogene paleogeomorphic pattern in the south of Lufeng sag is reconstructed by the impression method, and the temporal and spatial evolution laws of the main faults are clarified. The results show that braided river deltas developed stably in the long-axis gentle slope belt of the lake basin, while the short-axis sedimentary system changed from fan deltas to braided river deltas in response to the change of active strength of dominant faults from strong to weak. It is found that the scale of the sedimentary fan is closely related to the activity of the main fault, the area of the catchment, and the vertical elevation difference. The steep cliff is controlled by the boundary fault with large fault throw and steep section, and there are wedge-shaped sand bodies near the steep cliff. The multi-level fault-step zone provides the driving force for the advancement of the sedimentary system, and the sand body extends for a long distance. It is established that the supply capacity of the source area and the accommodated space of the lake basin are coupled to control the deposition scale. Moreover, the slope controlled by the combination of paleogeomorphic assemblage and the activity of the main fault determines the sedimentary type, and the structural slope-break zone defines the spreading pattern of the sands.Cited as: Jiang, M., Chen, D., Chang, X., Shu, L., Wang, F. Controlling effect of tectonic-paleogeomorphology on deposition in the south of Lufeng sag, Pearl River Mouth Basin. Advances in Geo-Energy Research, 2022, 6(5): 363-374. https://doi.org/10.46690/ager.2022.05.0
Imbibition oil recovery of single fracture-controlled matrix unit: Model construction and numerical simulation
Get PDFThe fracture-controlled matrix unit is commonly found in low-permeability fractured reservoirs. Due to the permeability difference between the fracture system and the matrix system, a large amount of oil will remain in the matrix during traditional water injection development, thus limiting reservoir productivity. However, the special imbibition mode of the fracture-controlled matrix unit provides a breakthrough for secondary oil recovery. In this paper, based on the model of single fracture-controlled matrix unit, the dynamic production process of fractured reservoir is studied by the numerical simulation method. The numerical simulation of the imbibition oil production is carried out on the two-point well model by using the method of huff and puff injection. The results show that imbibition is the main mechanism in the middle and late stages of oil recovery from fractured reservoirs. The water in the fracture is absorbed into the matrix by capillary force and the oil is replaced; in this way, imbibition can increase the recovery rate by 20%. The findings provide a basis for the further study of the fracture-controlled matrix unit and imbibition.Cited as: Liu, Q., Liang, B., Liu, J., Sun, W., Lei, Y. Imbibition oil recovery of single fracture-controlled matrix unit: Model construction and numerical simulation. Capillarity, 2022, 5(2): 32-40. https://doi.org/10.46690/capi.2022.02.0
Quantitative prediction of palaeo-uplift reservoir control and favorable reservoir formation zones in Lufeng Depression
Get PDFIn this paper, taking the Lufeng Depression as the study object, the distribution characteristics and reservoir-controlling conditions of palaeo-uplift are analyzed from both qualitative and quantitative perspectives. The distribution characteristics of the three-level palaeo-uplift structural pattern are elucidated, which show that the palaeo-uplifts went through three structural evolutionary stages: Eocene, Early-Middle Miocene, and Late Miocene, with long-term inherited development characteristics. Palaeo-uplift controls the distribution of hydrocarbon planes, the direction of dominant hydrocarbon transport, the development of various traps, and the types of hydrocarbon reservoirs. Applying the principle and method of “multi-element matching reservoir formation model”, the corresponding geological and mathematical models are established, which indicate that 86.29% of the number of reservoirs are distributed on the top and slope of the palaeo-uplift, and the reserves and number decrease with the distance to the top of the palaeo-uplift. Based on the palaeo-uplift control model, four high-probability areas for palaeo-uplift control in the Wenchang and Enping Fms are predicted, which are mainly located in the Lufeng middle-low uplift, the Dongsha uplift, and uplifts within the depression.Cited as: Guo, B., Yu, F., Wang, Y., Li, H., Li, H., Wu, Z. Quantitative prediction of palaeo-uplift reservoir control and favorable reservoir formation zones in Lufeng Depression. Advances in Geo-Energy Research, 2022, 6(5): 426-437. https://doi.org/10.46690/ager.2022.05.0