Development Of Fracture Network Research Articles

Fracture evaluation of the plutonic basement in the Upper Magdalena Basin: Implications for the development of naturally fractured reservoirs in the Northern Andes

Plutonic rocks typically have negligible matrix porosity and permeability. However, fractures and mineral alterations create storage space and flow pathways that turn plutonic rocks into fluid reservoirs. Despite significant hydrocarbon discoveries, naturally fractured reservoirs in plutonic rocks have been poorly studied. In most Colombian basins, the crystalline basement has undergone multiple deformational events and is thrust over the Cretaceous to Cenozoic source and reservoir rocks of the conventional petroleum system. This structural configuration is ideal for the migration of oil into a fractured basement. A multiscale fracture analysis, including field, petrographical and petrophysical techniques was conducted on the Permian and Jurassic plutonic basement of Upper Magdalena Basin in order to understand the controls on brittle deformation, the development of fracture networks and their potential to form hydrocarbon reservoirs. The results indicate that protolith textures and structures, including magmatic and mylonitic foliation, favours fracturing. Dykes exhibit higher fracture density (7–48 fractures/m), porosity (mean = 0.4%) and permeability (mean = 125,818.75 mD) than the host rock (2–25 fractures/m; 0.23%; 12,066.09 mD). Intersection zones from regional faults, are characterized by the highest fracture and lineament intensity. Our results suggest that dyke swarms and interacting damage zones can significantly enhance the reservoir quality of plutonic rocks by providing storage in fractures and fluid pathways to the host rock.

Investigation of surrounding rock stability during proximal coal seams mining process and feasibility of ground control technology

The goaf formation of upper seam stope in proximity coal seams mining would influence the stability of the surrounding rock mass due to mining stress redistribution, which will seriously threaten the subsequent mining process and even ground environmental protection. Therefore, developing safe and efficient mining techniques, robust support strategies, and comprehensive safety evaluation systems is crucial for ensuring the overall safety of the mining process. Drawing upon on-site data, this study conducted a detailed feasibility analysis of the mechanized caving method. We developed a simulation model using similar materials, tailored for scenarios with overlying goaf, to demonstrate how lower seam mining was affected by the caving zone of the upper seam, leading to the progressive evolution of fracture networks. Furthermore, we employed numerical simulation models to juxtapose the simulated deformation areas with the actual potential deformation zones in the mining area. The mine seismic prediction (MSP) technique was utilized for the precise identification of unfavorable geological formations ahead of the working face, thereby preempting potential fractures or irregularities due to the presence of overlying goaf. In addition, a comprehensive support strategy was designed and implemented to bolster the stability of the roadways, thereby reinforcing the safety measures within the mining process. This study presents an integrated approach to investigate mining activities in the lower layers during stratified extraction, particularly how the overlying goaf of the upper seam affects the mining of the lower seam, leading to the progressive evolution of fracture networks. The findings and methodologies outlined in this work hold substantial practical significance, offering a pathway to enhance the reliability and safety of the mining process.

Development of CASRock for modeling multi-fracture interactions in rocks under hydro-mechanical conditions

The interaction between multiple fractures is important in the analysis of rock fracture propagation, fracture network evolution and stability and integrity of rocks under hydro-mechanical (HM) coupling conditions. At present, modeling the mechanical behavior of multiple fractures is still challenging. Under the condition of multiple fractures, the opening, closing, sliding, propagation and penetration of fractures become more complicated. In order to simulate the HM coupling behavior of multi-fracture system, the paper presents a novel numerical scheme, including mesh reconstruction and topology generation algorithm, to efficiently and accurately represent fractures and their propagation process, and a potential function-based algorithm to address contact problem. The fracture contact algorithm does not need to set contact pairs and thus is suitable for complex contact situations from small to large deformations induced by HM loading. The topology of fracture interfaces is constructed by the dynamic adding algorithm, which makes the mesh reconstruction more rapid in the modeling of fracturing process, especially in the case of multiple fractures intersections. The numerical scheme is implemented in CASRock, a self-developed numerical code, to simulate the propagation process of rock fractures and the interaction of multiple fractures under the condition of HM coupling. To verify the suitability of the code, a series of tests were performed. The code was then applied to simulate hydraulic fracture propagation and fracture interactions caused by fluid injection. The ability of this method to study fracture propagation, multi-fracture interaction and fracture network evolution under hydro-mechanical coupling conditions is demonstrated.

Research Progress on the Microfracture of Shale: Experimental Methods, Microfracture Propagation, Simulations, and Perspectives

The fracture network generated by hydraulic fracturing in unconventional shale reservoirs contains numerous microfractures that are connected to macroscopic fractures. These microfractures serve as crucial pathways for shale gas to flow out from micro- and nano-scale pores, playing a critical role in enhancing shale gas recovery. Currently, more attention is being given by academia and industry to the evolution of macroscopic fracture networks, while the understanding of the microfracture mechanisms and evolution is relatively limited. A significant number of microfractures are generated during the hydraulic fracturing process of shale. These microfractures subsequently propagate, merge, and interconnect to form macroscopic fractures. Therefore, studying the fracture process of rock masses from a microscale perspective holds important theoretical significance and engineering value. Based on the authors’ research experience and literature review, this paper provides a brief overview of current progress in shale microfracture research from five aspects: in situ observation experiments of microfractures in shale, formation and evolution processes of discontinuous microfractures, the impact of inhomogeneity on microfracture propagation, measurement methods for microscale mechanical parameters and deformation quantities in shale, and numerical simulation of shale microfractures. This paper also summarizes the main challenges and future research prospects in shale microfracture studies, including: (1) quantitative characterization of in situ observation experimental data on shale microfractures; (2) formation and evolution laws of macroscopic, mesoscopic, and microscopic multi-scale discontinuous fractures; (3) more in-depth and microscale characterization of shale heterogeneity and its deformation and fracture mechanisms; (4) acquisition of shale micro-mechanical parameters; (5) refinement and accuracy improvement of the numerical simulation of microfractures in shale. Addressing these research questions will not only contribute to the further development of microfracture theory in rocks but also provide insights for hydraulic fracturing in shale gas extraction.

Research on the impact of pre‐existing geological fractures on hydraulic fracturing in high in situ stress environments

AbstractThe formation of complex fracture network is a difficult problem in the process of deep rock reservoir reconstruction, and the key to the generation of intricate fracture systems in deep reservoirs is to communicate more pre‐existing fractures through hydraulic fracturing, so as to enhance oil recovery. At present, there are few studies on the interactions of hydraulic fractures with pre‐existing fractures under high stress. Therefore, this research studied the influence of the number of pre‐existing fractures on the characteristics of hydraulic fractures by using advanced hydraulic fracturing instruments, and then analyzed the characteristics of hydraulic fractures under different pre‐existing fracture number based on three‐dimensional topography scanning technology and three‐dimensional square box fractal dimension calculation method. Based on the three‐dimensional finite element discrete element method, further research is carried out. The laboratory test findings indicated that the increase of pre‐existing fractures will make the pump pressure curve more stable during the test, and will significantly improve the roughness of hydraulic fractures. The numerical simulation indicated that as the quantity of pre‐existing fractures grows, the fracture area and width also increase, and in instances of a substantial quantity of pre‐existing fractures, the hydraulic fractures are prone to bifurcation, which contributes to the development of intricate fracture networks. With the increase of natural fracture angle, the fracture width decreased, but the fracture area increased. In this study, the influence of the number of pre‐existing fractures on hydraulic fracturing was studied through laboratory tests and numerical simulations, which provided theoretical reference for engineering practice.

Review of discrete fracture network characterization for geothermal energy extraction

Geothermal reservoirs are highly anisotropic and heterogeneous, and thus require a variety of structural geology, geomechanical, remote sensing, geophysical and hydraulic techniques to inform Discrete Fracture Network flow models. Following the Paris Agreement on reduction of carbon emissions, such reservoirs have received more attention and new techniques that support Discrete Fracture Network models were developed. A comprehensive review is therefore needed to merge innovative and traditional technical approaches into a coherent framework to enhance the extraction of geothermal energy from the deep subsurface. Traditionally, statistics extracted from structural scanlines and unmanned aerial vehicle surveys on analogues represent optimum ways to constrain the length of joints, bedding planes, and faults, thereby generating a model of the network of fractures. Combining borehole images with seismic attributes has also proven to be an excellent approach that supports the stochastic generation of Discrete Fracture Network models by detecting the orientation, density, and dominant trends of the fractures in the reservoirs. However, to move forward to flow modelling, computation of transmissivities from pumping tests, and the determination of hydraulically active fractures allow the computation of the hydraulic aperture in permeable sedimentary rocks. The latter parameter is fundamental to simulating flow in a network of discrete fractures. The mechanical aperture can also be estimated based on the characterization of geomechanical parameters (Poisson’s ratio, and Young’s modulus) in Hot Dry Rocks of igneous-metamorphic origin. Compared with previous review studies, this paper will be the first to describe all the geological and hydro-geophysical techniques that inform Discrete Fracture Network development in geothermal frameworks. We therefore envisage that this paper represents a useful and holistic guide for future projects on preparing DFN models.

Injection-induced fault slip and associated seismicity in the lab: Insights from source mechanisms, local stress states and fault geometry

Probing source mechanisms of natural and induced earthquakes is a powerful tool to unveil associated rupture kinematics. The source processes of failure and slip instability driven by stress loading are affected by fault geometry, but the source ruptures of injection-induced seismicity in relation to fault structures and local stress states remain poorly understood. We have conducted a series of fault reactivation and slip experiments on sandstone samples containing faults with different surface roughness (smooth saw-cut fault and fractured rough fault). We impose progressive fluid injection to induce fault slip, and simultaneously monitor the associated acoustic emission (AE) activity. Using high-resolution AE recordings, we perform full moment tensor inversion of all located AE sources, and investigate the changes of AE source characteristics associated with induced fault slip and their relation to fault roughness. For the complex and rough fault, we observe significant non-double-couple components of AE sources and a high degree of focal mechanism heterogeneity. The temporal changes of AE mechanisms associated with injection-induced fault slip on the smooth fault reveal increasing proportions of double-couple components and decreasing variability of AE focal mechanisms when approaching the onset of slip events. The observed inconsistency between the nodal planes of AE sources and the macroscopic fault plane orientation is attributed to the development of secondary fracture networks surrounding the principal slip surface. We analyze changes in the magnitude-frequency characteristics and source mechanisms of AEs with fault-normal distance, showing that for the smooth (mature) fault, Gutenberg–Richter b-value of on-fault seismicity is lower and focal mechanisms are less heterogeneous, compared to off-fault seismicity. Our results emphasize the important role of roughness-related changes in local fault geometry and associated stress heterogeneity for source mechanisms and rupture kinematics of injection-induced seismicity.

Coupled simulations on fracture network evolution during nitrogen fracturing after liquid nitrogen pre-conditioning in shale

Coupled simulations on fracture network evolution during nitrogen fracturing after liquid nitrogen pre-conditioning in shale

Deformation evolves from shear to extensile in rocks due to energy optimization

Determining how fracture network development leads to macroscopic failure in heterogeneous materials may help estimate the timing of failure in rocks in the upper crust as well as in engineered structures. The proportion of extensile and shear deformation produced by fracture development indicates the appropriate failure criteria to apply, and thus is a key constraint in such an effort. Here, we measure the volume proportion of extensile and shear fractures using the orientation of the fractures that develop in triaxial compression experiments in which fractures are identified using dynamic in situ synchrotron X-ray imaging. The fracture orientations transition from shear to extensile approaching macroscopic, system-size failure. Numerical models suggest that this transition occurs because the fracture networks evolve in order to optimize the total mechanical efficiency of the system. Our results provide a physical interpretation of the empirical internal friction coefficient in rocks.

Experimental Study on Mode I Fracture Characteristics of Granite after Low Temperature Cooling with Liquid Nitrogen

Liquid nitrogen fracturing has emerged as a promising technique in fluid fracturing, providing significant advantages for the utilization and development of geothermal energy. Similarly to hydraulic fracturing in reservoirs, liquid nitrogen fracturing entails a common challenge of fluid–rock interaction, encompassing the permeation and diffusion processes of fluids within rock pores and fractures. Geomechanical analysis plays a crucial role in evaluating the transfer and diffusion capabilities of fluids within rocks, enabling the prediction of fracturing outcomes and fracture network development. This technique is particularly advantageous for facilitating heat exchange with hot dry rocks and inducing fractures within rock formations. The primary objective of this study is to examine the effects of liquid nitrogen fracturing on hot dry rocks, focusing specifically on granite specimens. The experimental design comprises two sets of granite samples to explore the impact of liquid nitrogen cooling cycles on the mode I fracture characteristics, acoustic emission features, and rock burst tendency of granite. By examining the mechanical properties, acoustic emission features, and rock burst tendencies under different cycling conditions, the effectiveness of liquid nitrogen fracturing technology is revealed. The results indicate that: (1) The ultimate load-bearing capacity of the samples gradually decreases with an increase in the number of cycling times. (2) The analysis of acoustic emission signals reveals a progressive increase in the cumulative energy of the samples with cycling times, indicating that cycling stimulates the release of stored energy within the samples. (3) After undergoing various cycling treatments, the granite surface becomes rougher, exhibiting increased porosity and notable mineral particle detachment. These results suggest that the cyclic application of high-temperature heating and liquid nitrogen cooling promotes the formation of internal fractures in granite. This phenomenon is believed to be influenced by the inherent heterogeneity and expansion–contraction of internal particles. Furthermore, a detailed analysis of the morphological sections provides insights into the structural changes induced by liquid nitrogen fracturing in granite samples.

Influence of supercritical CO2 on fracture network evolution with nanopore structure linkage in high-rank anthracite matrix

It is essential to understand the permeability evolution of coal reservoirs under the interaction of supercritical CO2 (SC-CO2) in order to be successful in both CO2 geological storage and extraction of coalbed methane. However, the influence of nanopore structure characteristics on the permeability evolution of coal exposed to SC-CO2 has not been elucidated. To this end, the quantitative analysis of the pores in high-rank coal was conducted through low-temperature N2 adsorption, low-temperature CO2 adsorption, and Nuclear Magnetic Resonance (NMR). The analysis revealed that micropores and mesopores are the major contributors to the specific surface area and pore volume of the nanopores, respectively. After SC-CO2 interaction, the pore size and pore number of the coal increased significantly, with small pores changing to large ones, mainly due to the dissolution of SC-CO2 with the contribution of gas pressure being negligible. The proportion of micropore and mesopore decreases while that of macropore increases after SC-CO2 treatment, especially SC-CO2 causes macropores to be continuous and increased the connectivity of fractures. The relationship between nanopore structure characteristics and the deformation of the fracture network under SC-CO2 interaction was studied. The results showed that the specific surface area (SSA) of the micropore and the volume fractal dimension (DLN2) of the mesopore were related to the change of fracture porosity, while the surface fractal dimension (DLN1) of the micropore, the specific surface area (SSA) and pore volume of mesopore were related to the change of fracture complexity. This indicated that the evolution of the fracture network under SC-CO2 interaction is related to the nanopore structure characteristics. A mechanical model was established based on the close correlation between nanopore structures characteristics in the matrix and the evolution of fracture networks under SC-CO2 interaction. This mechanical model elucidates the impact of nanopore alteration resulting from mineral dissolution induced by SC-CO2 on the evolution of fracture networks. This research provides a clearer understanding of the evolution in reservoir permeability during CO2 geological sequestration, offering valuable reference for safety assessments.

Osmotic Pressure Gradient Effects on Water Diffusion in Porous Rock: Can They Pervert Permeability Tests?

Abstract Generation of a large network of hydraulic cracks is of key importance not only for the success of fracking of shale but also for the recent scheme of sequestration of CO2 in deep formations of basalt and peridotite, which are mafic and ultramafic rocks that combine chemically with CO2. In numerical simulation of the creation of a fracture network in porous rock, an important goal is to enhance the rock permeability. The objective of this article is to calculate the effect of osmotic pressure gradients caused by gradients of concentration of the ions of Ca, Mg, Na, etc. on the effective permeability of the rock. The basic differential equations are formulated, and their explicit solutions for appropriate initial and boundary conditions are obtained under certain plausible simplifications. The main result is explicit approximate formulas for the critical time before which no water permeation through a test specimen can be observed. Depending on various parameters, this time can be unacceptably long, which is manifested as a zero water outflow. The solution may also explain the unreasonably small permeability values reported for some shales.

Activation of natural fractures during hydraulic fracturing in elastoplastic jointed rocks

Complexity of fracture development in low permeability oil and gas reservoirs is of interest to many field operators for production enhancement. In highly jointed shales such as Marcellus and Sanmin, fluid-induced shear slip deformation along joint junctions coupled with soft nature of shale fabrics make fracturing operations more complicated. Sophistication includes widely reported occurrences of seismic tremors. Understanding of slip phenomena and fracture network development in such scenarios is never straightforward and curtailed with limited lines of evidence. In this study, we propose a globally embedded cohesive zone modelling within an elastoplastic three-dimensional framework to provide an understanding of the complex fracture development in soft shale formations. Shear strength of the global pore pressure cohesive elements is obtained as a function of field variable (stress) through parallel computation with FORTRAN language. Drucker Prager frictional behavior is included in the model with different friction coefficients to ascertain the joint slip phenomena when shear strength of the joints is reduced under the drenched effect of fracturing fluid. Results indicate that when the coefficient of friction is high, the total slip of the rock is reduced compared to the scenario with low friction coefficients. Other parametric analyses indicate that an isotropic stress regime leads to a more complex fracture development, while increased injection rates favour the opening of more compressed fracture wings. The model is validated against field data from layered shale reservoir as well as against Kristianovich-Geertsma-de Klerk (KGD) model with excellent agreements in both cases. This study is important for understanding fracture development complexity in soft jointed rocks together with associated slip phenomena.

Application of Micro-Seismic Monitoring in Post-Fracturing Evaluation of Shale Gas: A Case Study of Well X from Puguang Area, China

Multi-stage fracturing of horizontal wells is an indispensable technology to create complex fracture networks, which can unlock production potential and enable commercial productivity for shale gas with low porosity and permeability. Real-time monitoring of fracture networks is essential for adjusting key parameters, mitigating fracturing risks, and achieving optimal fracturing effects. Micro-seismic monitoring technology accurately captures and describes the development of fracture networks by detecting micro-seismic waves generated through rock ruptures, providing valuable insights into the evaluation of post-fracturing. In this study, we first introduced the basic parameters of well X that were obtained by laboratory experiments and logging interpretation, including porosity, gas-bearing properties, mineral composition, rock mechanics, and crustal stress. Then, the hydraulic fracturing scheme was designed on the basis of the geological engineering characteristics of well X. Finally, we conducted a comprehensive analysis of various factors that can affect hydraulic fracturing. This included an examination of the impact of pre-fluid temporary plugging and fracture complexity on the overall effectiveness of the operation. Based on the laboratory experiments and theoretical analysis, the following conclusions can be drawn: (1) fracture size is essentially formed when the fluid strength exceeds 35 m3/m; (2) both preflush with high viscosity and the amount of power sand exceeding 20 cubic meters are conducive to the propagation of fracture height; (3) temporary plugging balls facilitate the balanced propagation of multiple fracture clusters within a stage, whereas temporary plugging particles promote the formation of complex fractures; and (4) geological conditions are a prerequisite for creating a complex network of fractures, and only engineering techniques can facilitate the appropriate enhancement of fracture complexity. This study provides an essential method for the fracturing design of shale gas.

Study on oil seepage mechanisms in lamellar shale by using the lattice Boltzmann method

The shale oil and gas resources in the world are rich and are an important part of unconventional oil and gas resources. In this paper, firstly, by comprehensively using CT scanning technology, the three-dimensional pore-fracture structure characteristics of shale core samples of different sizes is characterized, and a three-dimensional digital core is established; Secondly, SEM and FIB-SEM techniques are systematically used to describe the microstructure and fracture network development characteristics of shale matrix pores and fractures, and a three-dimensional pore and fracture network model is established; Thirdly, Combined with LBZ simulation method, the mechanism of two-phase fluid transport in shale cross-scale fracture network is explored. Results show that: (a) The relatively dispersed mesopores and macropores in space constitute the main storage space of methane. Some pores in the study area of shale samples have good connectivity, and some samples only have connected pores in the study area of their magnification. (b) A large number of intergranular pores and fissures developed together with the intergranular pores of clay minerals, forming a good network connection system between microscopic pores in laminated shale. (c) when the hydrophilic mineral proportion is increased from 30% to 70%, the relative permeability of oil phase at water saturations of 20%, 40% and 60% has an increase of 6.8%, 7.8% and 4.2%, respectively, and the relative permeability of water phase at water saturations of 20%, 40% and 60% has a decrease of 1.8%, 2.6% and 6.5%, respectively. (d) When the oil phase contact angle is increased from 30° to 70°, the relative permeability of oil phase at water saturations of 20%, 40% and 60% has an increase of 1.9%, 2.7% and 2.2%, respectively, and the relative permeability of water phase at water saturations of 20%, 40% and 60% has a decrease of 1.2%, 2.1% and 3.5%, respectively.

Effects of rock ductility on the fracability of ductile reservoirs: An experimental evaluation

Deep hydrocarbon resources below 4000 m are an important replacement for shallow-depth resources; however, as depth increases, the difficulty and cost of development increase sharply. One of the possible reasons is that deep reservoir rocks exhibit strong ductility, which causes difficulties to stimulate a well-developed fracture network in rocks. To date, the mechanism by which rock ductility affects reservoir fracturing remains unclear, and there is a lack of quantitative evaluation models for reservoir fracability. To overcome the problems, in this study, artificial rock specimens with different ductility were fabricated using similar materials based on the geological data and petrophysical properties of the target deep reservoir; the specimens were classified using the proposed ductility index BIf. The hydrofracturing and CT scanning experiments of the artificial specimens with different BIf values under various horizontal stress differences Kh were conducted. The spatial fractal index Df was proposed to characterize the three-dimensional morphology and development of the fracturing network. The fracability evaluation function of ductile rock correlating the indices BIf and Kh was established. It was shown that ductile rocks tended to form non-planar hydraulic fractures with obvious tortuosity and the degree of fracture network development was lower than that of brittle rocks. The maximum breakdown pressure was approximately twice that of the brittle specimen, while the corresponding injection energy was approximately 5–10 times and the energy dissipation of fracture propagation was approximately 4–6 times those of the brittle rock. When Kh ≥ 0.3 the maximum horizontal principal stress played a major role in controlling the hydraulic fracture propagation in ductile rocks. If Kh < 0.3, the fracture propagation in rocks was mainly governed by material ductility rather than the maximum horizontal principal stress. This study provides a new way to explore and quantify the effect of rock ductility on the fracability of deep reservoirs.

Effects of fracturing parameters on fracture network evolution during multicluster fracturing in a heterogeneous reservoir

There are some major problems in the study of fracture network evolution during multicluster fracturing, such as the simple assumption that the reservoir is homogeneous, without considering the heterogeneity of rock mineral particles. In addition, different viscosities used in fracturing fluid and fluid injection methods can affect fracture propagation. As reservoir stimulation enters the 2.0 era, it is important to study the evolution of multicluster fracture networks based on reservoir heterogeneity to improve the stimulated reservoir volume. For this purpose, a 2D, coupled stress-seepage-damage field multicluster fracturing numerical model was developed in this study, and a globally embedded 0-thickness cohesive element was used to simulate the random propagation of hydraulic fractures. Moreover, the elastic modulus, tensile strength and mixed fracture energy of the cohesive element mesh were randomly assigned using the Weibull distribution probability density function to simulate the reservoir heterogeneity. In addition, the dynamic distribution of the injected fluid rate during multicluster fracturing was implemented based on the Bernoulli equation. The capability of the model was validated with analytical solutions of the Khristianovich-Geertsma-de Klerk (KGD) problem and similar numerical modeling criteria of multicluster fracturing and was used to investigate the geological and engineering factors that influence the evolution of the fracture network. The results show that the fracture network formed by hydraulic fracturing is more complex when the reservoir has significant heterogeneity and the injection pressure has a larger extreme value. As the reservoir becomes increasingly homogeneous, using low-viscosity fracturing fluid does not significantly contribute to fracture network complexity or effectively reduce the extreme value of the injection pressure. Shortening the pad fluid injection time can significantly increase the fracture network complexity, but it increases the extreme value of the injection pressure, which requires a higher pressure tolerance for fracturing equipment. The results of this study have important significance for the parameter optimization of multicluster fracturing.

The propagation behavior of hydraulic fracture network in a reservoir with cemented natural fractures

AbstractThere are still some problems in the study of hydraulic fracture (HF) network evolution in cemented naturally fractured reservoirs, such as microseismic mapping showing exaggerated stimulated reservoir volume in some cases. In addition, the dominant role of natural fracture (NF) cementation strength, injection rate, in situ stress difference, NF distribution, and fracture initiation sequence of perforations in synthetically influencing fracture network formation needs to be further studied. For this purpose, a three‐dimensional matrix hexahedral element global coupled 0‐thickness cohesive element hydraulic fracturing model was developed. Results show that each interaction between HF and NF causes HF diameter shrinkage, which increases the propagation pressure of HF. When the cementation strength of the NF is low, the HF tends to deviate toward the tip of the NF to form a complex fracture network. Increasing the injection rate and the number of NFs can significantly enhance the complexity of the HF network, but does not change the HF and NF interaction pattern. The in situ stress differences dominate the morphology of the HF network when the cementation strength of NFs is constant. The stress interference of multiple fractures under segmented fracturing may form “S”‐shaped HFs, and the HFs are difficult to maintain a symmetrical morphology in the direction of the well axis. In addition, some NFs in inactivated damaged zones have developed a certain width geometrically due to the induced effect of HF, but they are still isolated by the low permeability matrix and might only generate some microseismic events.

Understanding hydraulic fracture mechanisms: From the laboratory to numerical modelling

The 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. Cited 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.2023.01.07

Effects of fluid and proppant properties on proppant transport and distribution in horizontal hydraulic fractures of coal under true-triaxial stresses

Proppant distribution and sedimentary area spacing are crucial factors that influence fracture closure, and they directly impact the efficiency and effective utilisation time of unconventional oil and gas. However, the fracture surface roughness of actual hydraulic fractures and the development of microfractures significantly impact proppant transport. Few proppant transport laws for hydraulic fractures under true-triaxial stresses have been proposed. In this study, the effects of fluid and proppant properties on proppant transport and distribution in horizontal coal hydraulic fractures were investigated using a true-triaxial hydraulic fracturing experimental system subjected to high-pressure sand injection. The results show that high-injection-rate fracturing and low-injection-rate sand injection facilitate proppant transport to fracture tip and increase the distribution area of the proppant in fractures. The high viscosity of sand-carrying fluid improves the carrying capacity of the proppant but also increases the transport resistance. The resistance and the buoyancy of the high-viscosity fluid make the proppant transport complex. The higher the proppant concentration, the larger the proppant settlement at the crack entrance, and the closer the proppant-transport distance. During multiple sand injections, the proppant injected previously is pressed into the coal seam under the closure stress. The stress required to migrate the proppant injected subsequently is higher, and the proppant settlement at the crack inlet is larger. The smaller the proppant particle size, the easier the proppant penetrates the microcracks; this is more conducive to reaching the crack tip and promoting the fracture network development.