Yandy Scientific Press
Not a member yet
641 research outputs found
Sort by
Understanding hydraulic fracture mechanisms: From the laboratory to numerical modelling
Get PDFThe development of fracture networks associated with hydraulic fracturing operations are extremely complex multiphysics processes and there is still no accepted methodology for mapping or realistic recreating such fracture networks. This is an issue especially for modeling purposes, as, ideally, an accurate numerical representation, and subsequent numerical model, should be able to honor the trajectory, type, connectivity, and geometric properties of the complex fracture network generated. This research proposes a novel framework capable of conducting fluid flow numerical simulations based on mapped fracture networks induced during hydraulic fracturing laboratory experiments where a shale sample, under true triaxial reservoir stress conditions, is subjected to fluid injection to mimic a single stage open-hole in-situ hydraulic fracture operation. The resulting post-test fracture network of the shale sample is filled with fluorescent dyed epoxy and subsequently imaged. The images are segmented, and individual fractures are classified based on their geometrical characteristics, as parted bedding planes, opened natural fractures, and newly generated hydraulic fractures. The digital fracture network is numerically represented for fluid flow simulation using a dual-porosity model within the finite volume method. In the numerical reconstruction, fractures are implicitly represented in a set of cells with virtual fracture aperture. The properties of each grid cell are assigned based on fracture classification, and flow between grid cells is explicitly assigned based on the connectivity of the grid cells. Findings show faster fluid drainage parallel to bedding planes (horizontal) than in the vertical direction, indicating strong fluid flow anisotropy.Document Type: Research highlightCited as: Abdelaziz, A., Ha, J., Li, M., Magsipoc, E., Sun, L., Grasselli, G. Understanding hydraulic fracture mechanisms: From the laboratory to numerical modelling. Advances in Geo-Energy Research, 2023, 7(1): 66-68. https://doi.org/10.46690/ager.2023.01.0
Fluid phase behavior of tight and shale reservoirs: Monte Carlo simulations
Get PDFTight and shale reservoirs are forming important components of the global hydrocarbon landscape, which impede the free thermal movement of fluid molecules, with numerous nanoscale pores. The confined hydrocarbons in the nanopores cannot be industrially produced from conventional exploration and development methods, with deviated fluid phase behavior under nano-confinement effects. Most commonly important fluid phase behavior in nanopores has been simulated and compared with the bulk cases previously, including phase coexistence, critical properties, and density distribution of confined fluids. This paper focuses on the deviated fluid phase behavior under nano-confinement effects by Monte Carlo modeling. The Monte Carlo simulation is still limited to modeling the macroscopic pore-related behavior like capillarity and complex fluid and solid materials. Moreover, the Monte Carlo simulation is usually scale-restricted and the pore-size range where the nano-confinement effect fails to work needs to be quantitatively determined. Overall, for the tight and shale fluid phase behavior, a functional Monte Carlo model, coupled with the long-range correction and configuration bias techniques, is suggested to include both the multi-component fluids and skeleton.Document Type: PerspectiveCited as: Chu, W., Zhang, K. Fluid phase behavior of tight and shale reservoirs: Monte Carlo simulations. Advances in Geo-Energy Research, 2023, 7(2): 132-135. https://doi.org/10.46690/ager.2023.02.0
Three-dimensional simulation of wormhole propagation in fractured-vuggy carbonate rocks during acidization
Get PDFAcidization is a widely used stimulation technique for carbonate reservoirs aimed at removing formation damage, and if successful, can result in the creation of wormholes of specific lengths and conductivities around the wellbore. The formation of wormholes depends on the injection rate for a particular acid-mineral system and can be predicted through numerical simulations of the reactive phenomenon during acidization. In this paper, the commonly used two-scale continuum model is enhanced to encompass fractured-vuggy porous media. The fractures are characterized by a pseudo-fracture model, while vugs are represented by a cluster of anomalous matrices with high porosity. Moreover, a method for generating random pore-fracture-vuggy models is proposed. The governing equations are discretized by the finite volume method and are solved under three-dimensional linear and radial conditions. Sensitivity analysis of dissolution dynamics with respect to fracture and vug parameters is performed. The simulation results indicate that both fractures and vugs significantly impact wormhole development. Except for fractures perpendicular to the acid flow direction, fractures in other directions play a crucial role in determining the direction of wormhole growth.Document Type: Original articleCited as: Liu, P., Kong, X., Feng, G., Zhang, K., Sun, S., Yao, J. Three-dimensional simulation of wormhole propagation in fractured-vuggy carbonate rocks during acidization. Advances in Geo-Energy Research, 2023, 7(3): 199-210. https://doi.org/10.46690/ager.2023.03.0
Experimental and numerical modeling of deformation-cracking mechanics of 3D-printed rock samples with single fracture
Get PDFThe analysis of mechanical response and deformation-cracking behavior contributes to the high-efficiency extraction of geo-energy and long-term safety of underground engineering structures. Compared to natural cores, the mechanical properties of 3D-printed samples made from quartz sand as raw material are relatively homogeneous, and can be used for quantitative studies on the influence of natural defects on the mechanical properties of rocks. In this work, 3D-printed samples with single fractures of different crack angles, lengths and widths were fabricated and used for uniaxial compression tests. Adopting the digital image correlation method, the stress-strain distribution during uniaxial compression tests were visualized, and the influence of prefabricated fracture characteristics (dip angle, length, and width) on the deformation-failure process were studied. An extended finite element method subroutine for ABAQUS® software was modeled and used for the uniaxial compression simulation, which was validated by experiments. Then, the influence of mechanical parameters (Young’s modulus, Poisson’s ratio, cohesion, and internal friction angle) on the deformation-cracking mechanics were simulated and studied. The results indicate that, compared to the intact sample, fractures reduce the sample strength. With the extension of fracture length and width, or the decline of fracture angle, both the peak strain and strength of the 3D-printed samples decrease. The splitting tensile failure, or shear failure, or both were determined for the 3D-printed samples with different fracture angles. For the same axial strain, the extension length of the new crack increases linearly with rising Young’s modulus and decreases linearly with increasing Poisson’s ratio. The initial strain of new cracks decreases linearly with increasing Young’s modulus, while little variations are found in samples with different Poisson’s ratio. For the same axial displacement load, the peak stress increases linearly with growing internal friction angle and cohesion.Document Type: Original articleCited as: Song, R., Tian, J., Wu, M., Liu, J. Experimental and numerical modeling of deformation-cracking mechanics of 3D-printed rock samples with single fracture. Advances in Geo-Energy Research, 2023, 8(2): 126-135. https://doi.org/10.46690/ager.2023.05.0
Effect of fines migration on oil recovery from carbonate rocks
Get PDFWe perform single-phase and two-phase flooding on Edwards Brown rock samples. The single-phase injection was of seawater or CaCl2 brine, at successive salinities 0.63, 0.21, 0.07, 0.05, and 0 mol/L (distilled water). For CaCl2 brine experimental run, no significant fines migration or permeability decrease is observed. For seawater experimental run, distilled water injection is found to bring about the highest concentration of produced fines and most of the permeability decrease, with the ultimate permeability decrease being 99.94%. Therefore, distilled water injection is used to stimulate fines migration in the following two-phase experimental runs. Two-phase experiments are performed on four Edwards Brown rock samples using seawater or CaCl2 brine as the aqueous phase, and Soltrol® 130 or crude oil as the oleic phase. Rock samples are initially fully saturated with 0.63 mol/L of the selected aqueous solution. This is followed by injecting the selected oil at a constant rate for at least 20 pore volumes to displace brine. Next, selected brine is injected to displace oil, and finally distilled water. For CaCl2 brine, distilled water injection is found to recover no additional oil of either type of oil. However, for seawater, the fines production observed during distilled water injection is found to reduce water relative permeability by two orders of magnitude when Soltrol® 130 is used and by three orders of magnitude when crude oil is used. The seawater experimental runs also brought about additional oil recovery during distilled water injection: 18% when Soltrol® 130 is used and 3.4% when crude oil is used. This last result can be attributed to the plugging of pores due to fines migration, which can divert further injected water into previously unswept pores.Document Type: Original article Cited as: Almutairi, A., Saira, S., Wang, Y., Le-Hussain, F. Effect of fines migration on oil recovery from carbonate rocks. Advances in Geo-Energy Research, 2023, 8(1): 61-70. https://doi.org/10.46690/ager.2023.04.0
Characterization and capillary pressure curve estimation of clayey-silt sediment in gas hydrate reservoirs of the South China Sea
Get PDFThe capillary pressure curve is a crucial basis for studying the pore structure and multiphase flow characteristics in oil and gas reservoirs. Due to the loose and unconsolidated nature of the clayey-silt sediment of natural gas hydrate reservoirs in the South China Sea, conventional methods such as mercury intrusion and centrifugation struggle to obtain capillary pressure curves for these sediments. In this study, X-ray diffraction analysis, scanning electron microscopy, nitrogen adsorption, and water-gas contact angle measurements are utilized to characterize the mineral composition, pore structure, pore size distribution, and wettability of the clayey-silt sediment. Subsequently, the filter paper method from soil mechanics is employed to determine the capillary pressure curve for the clayey-silt samples. The results indicate that the capillary pressure curve obtained through the filter paper method exhibits a saturation range of 18.39%-80.31% and a capillary pressure range of 19.04 to 46,481.42 kPa. It exhibits a distinct two-stage characteristic, where capillary pressure changes rapidly with water saturation below 61.05% and slowly above 61.05%. The pore radius calculated from the capillary pressure curve ranges from 2.41 nm to 5.91 μm. This alignment with the pore ranges obtains from nitrogen adsorption and Scanning Electron Microscopy confirms the accuracy of the obtained capillary pressure curve. Furthermore, in comparison with a literature capillary pressure curve obtained through centrifugation, the paper filtration method covers a broader range, providing better representation of capillary pressure in the multiscale pores of clayey-silt samples.Document Type: Original articleCited as: Xia, Y., Xu, S., Lu, C., Andersen, P. Ø., Cai, J. Characterization and capillary pressure curve estimation of clayey-silt sediment in gas hydrate reservoirs of the South China Sea. Advances in Geo-Energy Research, 2023, 10(3): 200-207. https://doi.org/10.46690/ager.2023.12.0
The effect of methylene blue and organic acids on the wettability of sandstone formation: Implications for enhanced oil recovery
Get PDFFossil fuels are the primary global energy source, and their improved production will ensure a balance between the increasing energy demand and supply. Chemical-enhanced oil recovery has been well thought of as a promising method for increasing hydrocarbon production. However, the effectiveness of this method depends on wettability of rock-oil-brine systems’ Previous studies have shown that oil-wet rock demonstrated a water-wet state when treated with surface active chemicals like surfactants, nanofluids. Moreover, increasing attention has become focused on the application of hazardous pollutants such as methyl orange and methylene blue to enhance the CO2/H2 containment security of the host rock by altering its wettability. Nevertheless, the capacity of methylene blue to modify the rock wettability for the production of trapped hydrocarbons in sandstone reservoirs is yet to be explored. Thus, in the present study, methylene blue is used as a wettability modifier to enhance the oil production from quartz rocks that have been aged with stearic acid solution (10-2 mol/L). First, the organic-aged quartz is treated with various concentrations of methylene blue (10-100 mg/L) for one week at 60 °C. Then, contact angle measurements are performed at different temperatures (25 and 50 °C) under various pressures (10-20 MPa) and brine salinities (0-0.3 M). Thus, the quartz is found to turn hydrophobic when aged in organic acid/n-decane solution at 20 MPa and 50 °C. However, when the rock is treated with various concentrations of methylene blue, the hydrophobicity is found to decrease, thus suggesting that oil recovery will be promoted by methylene blue treatment. Overall, the results demonstrate that the most favourable condition for reducing the hydrophobicity of the sandstone rock is via treatment with 100 mg/L methylene blue. Hence, the injection of methylene blue into deep underground sandstone reservoirs has the potential to produce more residual hydrocarbons.Document Type: Original articleCited as: Alhammad, F., Ali, M., Yekeen, N. P., Ali, M., Hoteit, H., Iglauer, S., Keshavarz, A. The effect of methylene blue and organic acids on the wettability of sandstone formation: Implications for enhanced oil recovery. Capillarity, 2024, 10(2): 29-37. https://doi.org/10.46690/capi.2024.02.0
Variable interaction empirical relationships and machine learning provide complementary insight to experimental horizontal wellbore cleaning results
Get PDFLong horizontal wellbore sections are now a key requirement of oil and gas drilling, particularly for tight reservoirs. However, such sections pose a unique set of borehole-cleaning challenges which are quite distinct from those associated with less inclined wellbores. Experimental studies provide essential insight into the downhole variables that influence borehole cleaning in horizontal sections, typically expressing their results in multivariate empirical relationships with dimensionless cuttings bed thickness/concentration (H%). This study demonstrates how complementary empirical H% relationships focused on pairs of influential variables can be obtained from published experimental data using interpolated trends and optimizers. It also applies five machine learning algorithms to a compiled multivariate (10-variable) interpolated dataset to illustrate how reliable H% predictions can be derived based on such information. Seven optimizer-derived empirical relationships are derived using pairs of influential variables which are capable of predicting H% with root mean squared errors of less than 1.8%. The extreme gradient boosting model provides the lowest H% prediction errors from the 10-variable dataset. The results suggest that in drilling situations where sufficient, locally-specific, information for multiple influential variables is available, machine learning methods are likely to be more effective and reliable at predicting H% than empirical relationships. On the other hand, in drilling conditions where information is only available for a limited number of influential variables, empirical relationships involving pairs of influential variables can provide valuable information to assist with drilling decisions.Document Type: Original articleCited as: Wood, D. A. Variable interaction empirical relationships and machine learning provide complementary insight to experimental horizontal wellbore cleaning results. Advances in Geo-Energy Research, 2023, 9(3): 172-184. https://doi.org/10.46690/ager.2023.09.0
Imbibition behaviors in shale nanoporous media from pore-scale perspectives
Get PDFIn shale reservoirs, spontaneous imbibition is an important mechanism of fracturing fluid loss, which has an important impact on enhanced oil recovery and water resource demand. However, spontaneous imbibition behaviors are more complicated to characterize and clarify due to the nanoscale effects of the boundary slip, oil-water interfacial slip, and heterogeneous fluid properties caused by intermolecular interactions. A nanoscale multi-relaxation-time multicomponent and multiphase lattice Boltzmann method was applied to investigate the water imbibition into oil-saturated nanoscale space. The effects of pore size, fluid-surface slip, water film, oil-water interfacial slip, water bridge, and pore structures on the imbibition behaviors in a single nanopore were investigated. Then, the spontaneous imbibition behaviors in nanoporous media based on the pore scale microsimulation parameters obtained from the molecular simulation velocity results were simulated, and the effects of water saturations on imbibition behaviors were discussed. The results show that as the water saturation increases from 0 to 0.1, the imbibition mass in nanoporous media increases because of the oil-water interfacial slip and a completely hydrophilic wall. As water saturation continues to increase, the imbibition mass decreases gradually because the existence of water bridges impedes the water imbibition.Document Type: Original articleCited as: Wang, H., Cai, J., Su, Y., Jin, Z., Wang, W., Li, G. Imbibition behaviors in shale nanoporous media from pore-scale perspectives. Capillarity, 2023, 9(2): 32-44. https://doi.org/10.46690/capi.2023.11.0
Coupling mechanisms of displacement and imbibition in pore-fracture system of tight oil reservoir
Get PDFFracturing and water flooding have been popular technologies to achieve the effective development of tight oil reservoirs in recent years. However, in the late stage of production, the oil recovery rate declines with a rapid increase in the water cut. Water huff-puff could improve reservoir energy; however, the displacement and imbibition in the micro-nano pore throat and fracture systems are complex processes with unclear characteristics and position. Therefore, it is urgent to study the coupling mechanisms of oil-water displacement and imbibition in tight oil reservoirs. In this work, based on the phase field method of COMSOL Multiphysics software, we establish a two-dimensional microscopic numerical simulation model of the pore-fracture system, and carry out displacement-imbibition simulation programs of different injection media (water and surfactant) and injection methods (displacement, displacement-imbibition). By comparing the saturations and pressure distributions of different simulation programs, we analyze the changes in the oil-water interface, and summarize the action conditions of counter-current imbibition and pore throat limit. Finally, reasonable development suggestions are proposed for tight oil reservoirs.Document Type: Original article Cited as: Pi, Z., Peng, H., Jia, Z., Zhou, J, Cao, R. Coupling mechanisms of displacement and imbibition in pore-fracture system of tight oil reservoir. Capillarity, 2023, 7(1): 13-24. https://doi.org/10.46690/capi.2023.04.0