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Quantitative prediction of structural fractures in the Paleocene lower Wenchang formation reservoir of the Lufeng Depression
Get PDFCurrently, the lower Paleogene Wenchang formation in the Lufeng Depression is the primary focus of reservoir development. The structural fractures that have formed inside of it not only serve as the principal path for oil migration, but also as oil storage space. As a result, the distribution features of structural fractures are crucial for future petroleum exploration and development in the Lufeng Depression. At the same time, with the quantity of conventional reservoirs in the Lufeng Depression on the decline, it is critical to determine the fracture distribution criteria for deep unconventional reservoirs. In this work, the lower Paleogene Wenchang formation in the Lufeng Depression is used as the research stratum. Then, based on existing logging data for the research region, the distinct physical properties of different rock kinds are calculated. The simulation results of the paleotectonic stress field in the study area using the finite element numerical simulation software ANSYS show that the high-value areas of maximum principal stress are the high-value areas of the uplift belt and low uplift, and the areas with low maximum principal stress are the low-value areas of Lufeng 13 Sag and the gentle slope belt in the north of Lufeng middle-low uplift. The fracture density is quantitatively predicted after the stress field simulation, which shows good agreement between the anticipated and actual observed values, and an average error of 13.61%. The predicted findings may provide new ideas for future petroleum exploration.cited as: Li, H., Yu, F., Wang, M., Wang, Y., Liu, Y. Quantitative prediction of structural fractures in the Paleocene lower Wenchang formation reservoir of the Lufeng Depression. Advances in Geo-Energy Research, 2022, 6(5): 375-387. https://doi.org/10.46690/ager.2022.05.0
Unsteady-state CO2 foam injection for increasing enhanced oil recovery and carbon storage potential
Get PDFThe efficiency of CO2 injection for enhanced oil recovery and carbon storage is limited by severe viscosity and density differences between CO2 and reservoir fluids and reservoir heterogeneity. In-situ generation of CO2 foam can improve the mobility ratio to increase oil displacement and CO2 storage capacity in geological formations. The aim of this work was to investigate the ability of CO2 foam to increase oil production and associated CO2 storage potential, compared to other CO2 injection methods, in experiments that deploy field-scale injection strategies. Additionally, the effect of oil on CO2 foam generation and stability was investigated. Three different injection strategies were implemented in the CO2 enhanced oil recovery and associated CO2 storage experiments: pure CO2 injection, water-alternating-gas and surfactant-alternating-gas. Foam generation during surfactantalternating-gas experiments showed reduced CO2 mobility compared to water-alternatinggas and pure CO2 injections indicated by the increase in apparent viscosity. CO2 foam increased oil recovery by 50% compared to pure CO2 injection and 25% compared to water-alternating-gas. In addition, CO2 storage capacity increased from 12% during pure CO2 injection up to 70% during surfactant-alternating-gas injections. Experiments performed at high oil saturations revealed a delay in foam generation until a critical oil saturation of 30% was reached. Oil/water emulsions in addition to CO2 foam generation contributed to CO2 mobility reduction resulting in increased CO2 storage capacity with foam.Cited as: Sæle, A., Graue, A., Alcorn, Z. P. Unsteady-state CO2 foam injection for increasing enhanced oil recovery and carbon storage potential. Advances in Geo-Energy Research, 2022, 6(6): 472-481. https://doi.org/10.46690/ager.2022.06.0
Reliability analysis of elastic graphite packer in heat injection well during oil shale in-situ conversion
Get PDFHeat injection well reaches temperatures above 400 ◦C during the process of heat injection, Heat injection is essential for oil shale in-situ conversion technology. The downhole of the and part of the high-temperature gas dissipates through the wellbore annulus. Consequently, in addition to causing energy loss, the dissipation causes thermal damage to the casing and wellhead. To avoid dissipation, components that are suitable for high-temperature environments should be sealed and used during heat injection while mining. Therefore, this study presents the design of a packer composed of elastic graphite rubber and a high-temperature-resistant material. The influence of numerous factors, such as downhole temperature, working load, and height of rubber, on the reliability of the packer was analyzed. Subsequently, the numerical simulation analysis of the packer reliability in in-situ conversion mining under high temperature and pressure environments was performed. The results indicate that when the operating temperature is stable, the operating load has the most obvious influence on the sealing reliability of the packer, whereas the change in the height of the rubber has the least significant effect on the maximum contact stress between the casing and rubber. The change in the operating temperature has the least significant effect on the overall sealing performance of the packer. Moreover, the rise of the temperature will increase the sealing reliability of the packer, and on the contrary, the drop in the temperature will decrease it.Document Type: Original articleCited as: Guo, W., Shui, H., Liu, Z., Wang, Y., Tu, J. Reliability analysis of elastic graphite packer in heat injection well during oil shale in-situ conversion. Advances in Geo-Energy Research, 2023, 7(1): 28-38. https://doi.org/10.46690/ager.2023.01.0
Quantitatively evaluating greenhouse gas leakage from CO2 enhanced oil recovery fields
Get PDFGreenhouse gas (mainly CO2 and CH4) leakage from abandoned wells in CO2 enhanced oil recovery sites is a long-standing environmental concern and health hazard. Although multiple CO2 capture, utilization, and storage programs, e.g., CarbonSAFE and Regional Carbon Storage Partnerships, have been developed in the U.S. to reach the net-zero emission target by 2050, one cannot neglect the significant amount of CO2 and CH4 leakage from abandoned wells. This study will investigate the potential of CO2 and oil components leakages from the abandoned wellbore and develop the first-ever quantitative approach to evaluating CO2 and oil component leakage from a CO2 enhanced oil recovery field. Results show that in addition to a large amount of CO2 leakage, a significant amount of light and intermediate oil components leaked through the wellbore. In contrast, a minimal amount of heavy oil component leaked. Oil components’ leakage is mainly through the gas phase rather than the liquid phase. CO2 leakage is positively correlated to reservoir depth, wellbore pressure, and permeability through sensitivity analysis. In contrast, it is negatively related to net-to-gross ratio, residual oil saturation, and mole fraction of CH4. On the other hand, oil component leakages are positively correlated to all uncertain parameters, except the net-to-gross ratio. Lastly, the reduced-order models generated using the machine learning technique have a relatively high fidelity.Document Type: Original articleCited as: Chen, B., Mehana, M. Z., Pawar, R. J. Quantitatively evaluating greenhouse gas leakage from CO2 enhanced oil recovery fields. Advances in Geo-Energy Research, 2023, 7(1): 20-27. https://doi.org/10.46690/ager.2023.01.0
Numerical simulation and thermo-hydro-mechanical coupling model of in situ mining of low-mature organic-rich shale by convection heating
Get PDFThe in situ efficient exploitation of low-mature organic-rich shale resources is critical for alleviating the current oil shortage. Convection heating is the most critical and feasible method for in situ retortion of shale. In this study, a thermo-hydro-mechanical coupling mathematical model for in situ exploitation of shale by convection heating is developed. The dynamic distribution of the temperature, seepage, and stress fields during the in situ heat injection of shale and the coupling effect between multiple physical fields are studied. When the operation time increases from 1 to 2.5 years, the temperature of most shale formations between heat injection and production wells increases significantly (from less than 400 to 500 °C), which is a period of significant production of shale oil and pyrolysis gas. The fluid pore pressure gradually decreases from the peak point of the heat injection well to the surrounding. Compared with shale formation, bedrock permeability is poor, pore pressure increases slowly, and a lag phenomenon exists. The pore pressure difference between bedrock and shale is minimal by 1 year. When the heat injection time is 2.5 years, the permeability coefficient of shale formation in the area from the heat injection well to the production wells increases nearly 100 times the initial permeability coefficient. With increasing formation temperature, the vertical stress gradually evolves from compressive stress to tensile stress. Meanwhile, the action area of tensile stress expands outward with time with the heat injection well as the center. In general, increasing tensile stress enlarges the pore volume. It extends the fracture width, creating favorable conditions for the injection of high-temperature fluids and the production of oil and gas.Cited as: Zhao, J., Wang, L., Liu, S., Kang, Z., Yang, D., Zhao, Y. Numerical simulation and thermo-hydro-mechanical coupling model of in situ mining of low-mature organic-rich shale by convection heating. Advances in Geo-Energy Research, 2022, 6(6): 502-514. https://doi.org/10.46690/ager.2022.06.0
A novel machine learning model for autonomous analysis and diagnosis of well integrity failures in artificial-lift production systems
Get PDFThe integrity failure in gas lift wells had been proven to be more severe than other artificial lift wells across the industry. Accurate risk assessment is an essential requirement for predicting well integrity failures. In this study, a machine learning model was established for automated and precise prediction of integrity failures in gas lift wells. The collected data contained 9,000 data arrays with 23 features. Data arrays were structured and fed into 11 different machine learning algorithms to build an automated systematic tool for calculating the imposed risk of any well. The study models included both single and ensemble supervised learning algorithms (e.g., random forest, support vector machine, decision tree, and scalable boosting techniques). Comparative analysis of the deployed models was performed to determine the best predictive model. Further, novel evaluation metrics for the confusion matrix of each model were introduced. The results showed that extreme gradient boosting and categorical boosting outperformed all the applied algorithms. They can predict well integrity failures with an accuracy of 100% using traditional or proposed metrics. Physical equations were also developed on the basis of feature importance extracted from the random forest algorithm. The developed model will help optimize company resources and dedicate personnel efforts to high-risk wells. As a result, progressive improvements in health, safety, and environment and business performance can be achieved.Cited as: Salem, A. M., Yakoot, M. S., Mahmoud, O. A novel machine learning model for autonomous analysis and diagnosis of well integrity failures in artificial-lift production systems. Advances in Geo-Energy Research, 2022, 6(2): 123-142. https://doi.org/10.46690/ager.2022.02.0
Characteristics of Precambrian basement intruded by Cretaceous geological intrusions in Monteregian Igneous Province and their impacts on regional thermal structure
Get PDFWith the progress of geothermal exploration in deep buried geological bodies, high radiogenic geological intrusions have become the hot spot in recent years. However, the assessment of the complex structure, lithology of geological intrusions by the geophysical methods has uncertainty, making it a challenging to accurately predict the thermal structure around the geological intrusions. In southern Québec, Canada, recent studies show that a relative high surface heat flux has been detected in the region enclosed by Montréal, Salaberry-de-Valleyfield and Saint-Jean-sur-Richelieu, around the southwest of the Monteregian Hills, which belong to the Early Cretaceous alkaline and carbonatite intrusions. It is not clear whether these Monteregian intrusions have impacts on the thermal anomaly of the Montréal, Salaberry-de-Valleyfield and Saint-Jean-sur-Richelieu region. The objective of this paper is to numerically investigate the thermal structure in the thermal anomaly region, considering the impact of different Monteregian intrusions. The simplified Monteregian intrusions are embedded into a three-dimensional geological model consisting of the sedimentary formations in the St. Lawrence Lowlands and the simulator Underworld2 is used for the thermal modelling. Simulation results show that the geological intrusions in this region have large impacts on the thermal structure at the local-scale, depending on the radiogenic heat production, thermal conductivity, emplacement depth and size. Temperature in the sedimentary formations may be lower or higher than that of the adjacent geological intrusions, highly depending on the thermal physical characteristics of these intrusions. Furthermore, the complex fault systems also strongly control the thermal distribution in different fault blocks, making the Potsdam Group sandstone located between the Grand-St-Esprit and Notre-Dame-du-Bon-Conseil faults as the potential geothermal reservoir.Cited as: Liu, H., Ban, S., Bédard, K., Giroux, B. Characteristics of Precambrian basement intruded by Cretaceous geological intrusions in Monteregian Igneous Province and their impacts on regional thermal structure. Advances in Geo-Energy Research, 2022, 6(3): 206-220. https://doi.org/10.46690/ager.2022.03.0
The impact of geological heterogeneity on horizontal well-triplet performance in CO2-circulated geothermal reservoirs
Get PDFCO2 circulated geothermal production can be integrated with CO2 geological sequestration as a utilization method to offset cost. Investigation of heterogeneity impact is limited to CO2 sequestration and its effect on CO2 circulation and associated heat recovery is unclear. This study is aimed to improve the understanding of this problem by numerical experiments. A set of spatially correlated heterogeneous porosity fields is generated using a variety of geostatistical parameters, i.e., variance, correlation lengths, anisotropy and azimuth. Heterogeneous fields of intrinsic permeability and initial/residual water saturation are derived from porosity using equations regressed from a field dataset. Twenty combinations of injection pressure and well space obtained by Latin-Hypercube sampling are deployed in each heterogeneous field, generating a suite of numerical geothermal reservoir models. Performance indicators, including lifespan, net stored CO2 , produced heat flux, and total recovered heat energy in lifespan, are calculated from each model simulation. The simulation results suggest that geologic heterogeneity could develop high-permeable CO2 flow paths, causing bypass of the hot low-permeable zones, shortened lifespan and reduced total recovered heat energy. Depending on the azimuth, anisotropy can create either flow barriers or preferential flow paths, increasing or decreasing heat sweeping efficiency. The relative angle between horizontal wells and the axis of maximum continuity of the heterogeneity can be optimized to maximize heat recovery efficiency. These finds provide useful insights of interplay between geological heterogeneity, well placement and operation of CO2 circulated geothermal production.Cited as: Chen, M., Al-Saidi, A., Al-Maktoumi, A., Izady, A. The impact of geological heterogeneity on horizontal well-triplet performance in CO2-circulated geothermal reservoirs. Advances in Geo-Energy Research, 2022, 6(3): 192-205. https://doi.org/10.46690/ager.2022.03.0
Using mesoporous thin films as nano-micro-fluidic tools
Get PDFAchieving active control on small amounts of liquids represents a substantial challenge in both scientific and engineering aspects. Imbibition of fluids in bodies with nanoscale dimensions enables the spontaneous propelling of nano-flows because of the powerful capillarity at small-length scales. Peculiarities of nanopore imbibition at the thin film level lead to distinctive capillary transport phenomena of fluids across the nanopore matrix. This particular imbibition also impacts on the behavior of the in-contact liquid micro-volumes. These both features add versatile alternatives to the high interest in the management of femtolitre to microlitres amounts of liquids. Herein, we show a brief discussion-outlook based on recent advances in the design of versatile tools to attain programmable nano/microfluidics using mesoporous thin film platforms.Cited as: Berli, C. L. A., Bellino, M. G. Using mesoporous thin films as nano-micro-fluidic tools. Capillarity, 2022, 5(6): 123-127. https://doi.org/10.46690/capi.2022.06.0
Effect of dynamic threshold pressure gradient on production performance in water-bearing tight gas reservoir
Get PDFAbstractWater content and distribution have important impacts on gas production in water-bearing tight gas reservoirs. However, due to the structural and chemical heterogeneity of tight reservoirs, the water phase exists in various states, which has complicated the analyses of the effects of water characteristics on tight gas production performance. In this work, the water phase is distinguished from immobile to mobile states and the term of constrained water saturation is proposed. It is established that water can flow when the driving pressure difference is larger than the critical driving pressure difference. A new theoretical model of threshold pressure gradient is derived to incorporate the influences of constrained water saturation and permeability. On this basis, a new prediction model considering the varied threshold pressure gradient is obtained, and the result indicates that when threshold pressure gradient is constant, the real gas production capacity of the reservoir will be weakened. Meanwhile, a dynamic supply boundary model is presented, which indicates that the permeability has a strong influence on the dynamic supply boundary, whereas the impact of initial water saturation is negligible. These findings provide insights into the understanding of the effects of water state and saturation on the threshold pressure gradient and gas production rate in tight gas reservoirs. Furthermore, this study provides useful guidance on the prediction of field-scale gas production.Cited as: Zhu, W., Liu, Y., Shi, Y., Zou, G., Zhang, Q., Kong, D. Effect of dynamic threshold pressure gradient on production performance in water-bearing tight gas reservoir. Advances in Geo-Energy Research, 2022, 6(4): 286-295. https://doi.org/10.46690/ager.2022.04.0