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Quantitative evaluation and models of hydrocarbon accumulation controlled by faults in the Pearl River Mouth Basin
Get PDFThe Pearl River Mouth Basin is the largest petroliferous basin in the northern South China Sea, where hydrocarbon accumulation is strongly controlled by fault activities. This study performed the quantitative evaluation of the effects of faults on hydrocarbon migration and accumulation in the basin. The results indicate that the critical values of vertical migration of middle-shallow hydrocarbon, including the active strength of faults and the ratio of fault throw to shale caprock thickness, were up to 10 m/Ma and 5, respectively. The lateral hydrocarbon migration efficiency of the unbreached relay zone was higher than that of the barely breached and strongly breached types. The lower critical value of shale gouge ratio for the clay sealing efficiency was 0.32. Additionally, the zones with the EW-trending transtensional faults were found to have unique dual functions of migration and stress sealing, suggesting that the linking fault positions play important roles in the lateral migration of hydrocarbons. Finally, seven hydrocarbon accumulation models controlled by faults in different tectonic settings were constructed to clarify the effects of faults on the vertical and lateral migrations of hydrocarbon. These models suggested that fine hydrocarbon exploration should be undertaken in the northeastern Baiyun Sag, and that middle-deep hydrocarbon exploration should be enhanced in the Enping, Huizhou, and southwestern Baiyun Sags.Document Type: Original articleCited as: Peng, G., Wu, Z., Dai, Y., Zhang, L., Yu, S., Wang, W., Pang, H. Quantitative evaluation and models of hydrocarbon accumulation controlled by faults in the Pearl River Mouth Basin. Advances in Geo-Energy Research, 2023, 8(2): 89-99. https://doi.org/10.46690/ager.2023.05.0
Current advances in capillarity: Theories and applications
Get PDFAs common physical phenomena in porous media, capillarity behaviors exist in many engineering applications and natural science fields. The experimental, theoretical and numerical research on capillarity in porous media has lasted for more than a century, and the research results have been widely used in various fields, such as the development of conventional and unconventional resources. However, although the research has made great progress, the complex imbibition mechanism poses new challenges to us. The 1st National Conference on Imbibition Theory and Application in Porous Media was held in Beijing from April 22 to 24, 2023, to gather researchers who are interested in imbibition research, exchange the latest progress and achievements in the field of imbibition in porous media, and discuss research hotspots and difficulties.Document Type: EditorialCited as: Cai, J., Sun, S., Wang, H. Current advances in capillarity: Theories and applications. Capillarity, 2023, 7(2): 25-31. https://doi.org/10.46690/capi.2023.05.0
Simulation of the effect of stand-off parameter on collapse behaviours of a single cavitation bubble in jet drilling
Get PDFCavitation jet drilling has been extensively employed for the exploitation of geo-energy resources. The dynamics of cavitation bubbles in close proximity to the solid boundary have been a subject of great interest during jet drilling, as they play a crucial role in determining the cavitation performance. In present work, the dynamics of a single cavitation bubble near a solid surface is numerically investigated by using the axisymmetric Navier-Stokes equations and the volume of fluid method with considering the surface tension of gas-liquid interface, liquid viscosity and compressibility of gas in bubble. The simulated profiles are qualitatively and quantitatively consistent with the experimental images, which proves the reliability of employed numerical model. The effects of stand-off distance on the bubble profiles, bubble volume and collapse time have been analysed. Moreover, the cavitation erosion patterns towards the solid wall are also revealed for different dimensionless standoff distances. The simulation results reveal two distinct collapse patterns for the bubble profiles. The solid wall significantly impedes the shrinkage rate of the bubble, resulting in the longest collapse time when the dimensionless stand-off distance is 1.0. Three erosion patterns of cavitation bubbles towards the solid wall are observed, with the shock wave and micro-jet both contributing significantly to the damage caused by cavitation erosion. The shock wave sweeps the wall resulting in circular corrosion pits with a severely eroded centre, while the micro jet penetrates the wall leading to small spot corrosion pits.Document Type: Original articleCited as: Wu, X., Zhang, Y., Huang, H., Hui, C., Hu, Z., Li, G. Simulation of the effect of stand-off parameter on collapse behaviours of a single cavitation bubble in jet drilling. Advances in Geo-Energy Research, 2023, 8(3): 181-192. https://doi.org/10.46690/ager.2023.06.0
APyCE: A Python module for parsing and visualizing 3D reservoir digital twin models
Get PDFEngineers, geoscientists, and analysts can benefit from fast, easy, and real-time immersive 3D visualization to enhance their understanding and collaboration in a virtual 3D world. However, converting 3D reservoir data formats between different software programs and open-source standards can be challenging due to the complexity of programming and discrepancies in internal data structures. This paper introduces an open-source Python implementation focused on parsing industry reservoir data formats into a popular opensource visualization data format, Visual Toolkit files. Using object-oriented programming, a simple workflow was developed to export corner-point grids to Visual Toolkit-hexahedron structures. To demonstrate the utility of the software, standard raw input files of reservoir models are processed and visualized using Paraview. This tool aims to accelerate the digital transformation of the oil and gas industry in terms of 3D digital content generation and collaboration.Document Type: Short communicationCited as: Tosta, M., Oliveira, G. P., Wang, B., Chen, Z., Liao, Q. APyCE: A Python module for parsing and visualizing 3D reservoir digital twin models. Advances in Geo-Energy Research, 2023, 8(3): 206-210. https://doi.org/10.46690/ager.2023.06.0
Stress sensitivity of multiscale pore structure of shale gas reservoir under fracturing fluid imbibition
Get PDFGenerally, huge amounts of fracturing fluid are used in a shale gas well but the flowback efficiency is low. Since the distribution characteristics of imbibed fracturing fluid in shale are complex, they need further evaluation. This paper takes the Longmaxi Shale as the research object, including matrix cores, natural fracture cores and cores of artificial fracture with proppant. Stress sensitivity experiments are carried out on the above three kinds of cores under different degrees of imbibition and retention state of fracturing fluid. The results show that when the degree of aqueous phase retention is 0-0.78 pore volume, water mainly appears in the pores with a diameter of 2-50 nm. As the water saturation increases to more than 0.9 pore volume, the amounts of aqueous phase in the pores or fractures with a hydraulic diameter of 100-1,000 nm and larger than 1,000 nm increase significantly. Both the stress sensitivity of nanopores and natural fractures are enhanced by aqueous phase retention. With the increase in effective stress, the permeability damage rate of artificial fracture cores with proppant is inversely proportional to the degree of fracturing fluid retention. Aqueous phase retention in the pores with a diameter of 2-50 nm significantly contributes to the stress sensitivity of matrix cores. With the increase in effective stress, aqueous phase retention in pores with diameter larger than 100 nm increases the stress sensitivity of natural fracture cores. It is recommended that the retention degree of fracturing fluid in a shale gas reservoir should be controlled below 0.5 pore volume. In this case, the stress sensitivity of natural fractures will be less aggravated by fracturing fluid retention, and the stress sensitivity of artificial fracture with proppant will be reduced to a certain extent.Document Type: Original articleCited as: Chen, M., Yan, M., Kang, Y., Cao, W., Bai, J., Li, P. Stress sensitivity of multiscale pore structure of shale gas reservoir under fracturing fluid imbibition. Capillarity, 2023, 8(1): 11-22. https://doi.org/10.46690/capi.2023.07.0
Automated real-time formation evaluation from cuttings and drilling data analysis: State of the art
Get PDFTraditional formation evaluation via laboratory testing and wireline logging of horizontal wells and deep formations face challenges due to several reasons and lead to uncertain results. Real-time cuttings and drilling data analysis of horizontal wells is an actively developing alternative approach to formation evaluation that can overcome several challenges faced by laboratory testing and wireline logging in providing improved estimates of formation parameters relevant to reservoir and completion quality. This study presents a state-of-the-art review of the latest methods and technologies in drill cuttings analysis to enable real-time characterization of the entire suite of formation properties, including chemical composition, densities and porosity, permeability, lithology, geomechanical properties, and characterization of fracture patterns. Specifically, the methods/techniques that enable characterizing drill cuttings in real-time and critically reviewed in this study include Raman spectroscopy for chemical composition, nuclear magnetic resonance for densities and porosity, liquid pressure pulse for permeability, deep learning for rock classification, 7 different methods for geomechanical properties, and mud loss signatures for characterization of fracture patterns. Benchmark comparison of drill cuttings analysis with the measurements from the core samples at similar depths is also reviewed. Key learnings are provided in 4 areas: to address the uncertainties in estimates of specific parameters affected by physical deformations due to drill bits, minimum cutting size for reliable nuclear magnetic resonance data, sweet spot identification, and power and network considerations for real-time analysis, respectively.Document Type: Invited reviewCited as: Singh, H., Li, C., Cheng, P., Wang, X., Hao, G., Liu, Q. Automated real-time formation evaluation from cuttings and drilling data analysis: State of the art. Advances in Geo-Energy Research, 2023, 8(1): 19-36. https://doi.org/10.46690/ager.2023.04.0
Hydrocarbon accumulation and resources evaluation: Recent advances and current challenges
Get PDFConventional petroleum exploration targets have become increasingly complex recently. Although geological research of unconventional oil and gas resources has received much attention in recent years, such resources also face many complex geological and scientific problems. In this context, the 8th International Symposium on Hydrocarbon Accumulation Mechanisms and Petroleum Resources Evaluation was held in Beijing from 21 to 23 October, 2022. Experts presented and discussed their latest research findings on this topic relating to both conventional and unconventional oil and gas resources. They also discussed various development strategies for the petroleum industry taking into account the global objectives of “carbon peaking and carbon neutrality” to mitigate the impacts of climate change. Six significant theoretical advances and some new technologies were introduced at this conference. These advances related to the “Whole Petroleum System” theory, shale oil and gas exploration, deep and ultra-deep petroleum exploitation, clean energy issues, and alternative types of unconventional oil and gas resources. In response to these technological advances, four major current challenges were identified. These challenges related to the petroleum industry’s ongoing growth and development in the context of carbon-neutrality goals, the evolution of hydrocarbon laws relating to petroleum accumulations and their exploitation, organic and inorganic effects on petroleum generation and accumulation mechanisms, and artificial intelligence applications related to hydrocarbon prediction.Document Type: PerspectiveCited as: Jin, Z. Hydrocarbon accumulation and resources evaluation: Recent advances and current challenges. Advances in Geo-Energy Research, 2023, 8(1): 1-4. https://doi.org/10.46690/ager.2023.04.0
Empirical correlations for density, viscosity, and thermal conductivity of pure gaseous hydrogen
Get PDFThis study addresses the critical need for reliable tools to calculate the thermophysical properties of pure gaseous hydrogen across a wide range of temperatures and pressures. This work proposes accurate and user-friendly functions of temperature and pressure based on a meticulous analysis of an extensive dataset sourced from the open literature.These functions are designed to predict volumetric, transport, and derived properties.The dataset comprises 3,396 data points for density, 940 data points for viscosity, and 2,287 data points for thermal conductivity, covering an extensive temperature and pressure spectrum. For density, the data covers a temperature range from 97 to 873 K and pressures ranging from atmospheric to 1.983 GPa. Viscosity data span temperatures from 100 to 1,100 K and pressures from atmospheric to 217 MPa, while thermal conductivity data extend from 98 to 873 K, with pressures ranging from atmospheric to 99 MPa. The data have been meticulously curated to ensure reliability and representativeness. The proposed correlations exhibit exceptional accuracy, as evidenced by the Absolute Average Deviation results: 0.66% for density, 1.21% for viscosity, and 1.65% for thermal conductivity. To ensure the reliability, the correlations were validated against data from REFPROP 10. In addition to the absolute average deviations, maximum absolute deviations, Coefficients of Determination, and the Percentage of Accuracy-Precision are also included. The proposed correlations have been formulated and validated for a range of key parameters, including isothermal compressibility, volume expansion, fugacity coefficient, enthalpy, entropy, Helmholtz energy, Gibbs energy, adiabatic bulk modulus, speed of sound, as well as kinematic viscosity and thermal diffusivity.Document Type: Original articleCited as: Heidaryan, E., Aryana, S. A. Empirical correlations for density, viscosity, and thermal conductivity of pure gaseous hydrogen. Advances in Geo-Energy Research, 2024, 11(1): 54-73. https://doi.org/10.46690/ager.2024.01.0
Role of interfacial tension on wettability-controlled fluid displacement in porous rock: A capillary-dominated flow and how to control it
Get PDFOil displacement by spontaneous imbibition is a capillary-governed process, in which wettability controls fluid displacement direction. Capillarity is a driving force to enhance oil displacement in water-wet system, while in oil-wet system capillarity is a resisting one. To promote oil displacement, the former requires high capillarity, but the latter opposes. Such requisites are hypothesized to be alternatively achieved by manipulating an oilwater interfacial tension, without altering wetting character. In this study, spontaneous imbibition was conducted with a set of specifically designed imbibing fluids. Brines at different valencies were meticulously selected to attain desired wettabilities: monovalent brine establishes a water-wetting while divalent brine provides an oil-wet characteristics. A non-ionic surfactant, Triton X-100, was intentionally chosen to solely reduce interfacial tension, with negligible change in wettability. By mixing each brine with the surfactant, high-interfacial tension and low-interfacial tension imbibing fluids at the same wettability for the two wetting regions were obtained, and hence the hypothesis can be examined. For water-wet system, reduced interfacial tension attributed to a weakened driving capillary force to oil displacement, and hence lower oil displaced. On the contrary in oil-wet system, reduction in resisting capillary force as contributed from a reduced interfacial tension displaced greater oil. The results demonstrate how the capillary-driven fluid displacement can be manipulated by the interfacial tension change only, without a challenge of altering wettability. With results obtained from both wetting regions, a correlation between capillarity and ultimate oil displacement was also observed.Document Type: Original articleCited as: Tangparitkul, S., Sukee, A., Jiang, J., Tapanya, C., Fongkham, N., Yang, H. Role of interfacial tension on wettability-controlled fluid displacement in porous rock: A capillary-dominated flow and how to control it. Capillarity, 2023, 9(3): 55-64. https://doi.org/10.46690/capi.2023.12.0
Pore-GNN: A graph neural network-based framework for predicting flow properties of porous media from micro-CT images
Get PDFThis paper presents a hybrid deep learning framework that combines graph neural networks with convolutional neural networks to predict porous media properties. This approach capitalizes on the capabilities of pre-trained convolutional neural networks to extract n-dimensional feature vectors from processed three dimensional micro computed tomography porous media images obtained from seven different sandstone rock samples. Subsequently, two strategies for embedding the computed feature vectors into graphs were explored: extracting a single feature vector per sample (image) and treating each sample as a node in the training graph, and representing each sample as a graph by extracting a fixed number of feature vectors, which form the nodes of each training graph. Various types of graph convolutional layers were examined to evaluate the capabilities and limitations of spectral and spatial approaches. The dataset was divided into 70/20/10 for training, validation, and testing. The models were trained to predict the absolute permeability of porous media. Notably, the proposed architectures further reduce the selected objective loss function to values below 35 mD, with improvements in the coefficient of determination reaching 9%. Moreover, the generalizability of the networks was evaluated by testing their performance on unseen sandstone and carbonate rock samples that were not encountered during training. Finally, a sensitivity analysis is conducted to investigate the influence of various hyperparameters on the performance of the models. The findings highlight the potential of graph neural networks as promising deep learning-based alternatives for characterizing porous media properties. The proposed architectures efficiently predict the permeability, which is more than 500 times faster than that of numerical solvers.Document Type: Original articleCited as: Alzahrani, M. K., Shapoval, A., Chen, Z., Rahman, S. S. Pore-GNN: A graph neural network-based framework for predicting flow properties of porous media from micro-CT images. Advances in Geo-Energy Research, 2023, 10(1):39-55. https://doi.org/10.46690/ager.2023.10.0