Natural Fractures Research Articles

Effect of natural fractures on mechanical properties and fracture patterns of shale at microscopic scale: an example from the Lower Cambrian Niutitang formation in Qianbei region

In order to explore the influence of natural fractures on the mechanical properties and failure modes of shale at the micro scale, uniaxial compression numerical experiments were conducted on the shale of the Niutang Formation in northern Guizhou with different natural fracture angles using a rock failure process system and digital image processing technology. It is shown that the compressive strength of shale increases with the increase of natural crack inclination, and the growth rate of shale compressive strength also increases. Shale's microscopic fractures can generally be classified into four categories. The first category is to sprout along the natural cracks to the outside of the shale, and eventually form a crack similar to the "X" type (0°); the second category is to sprout along the natural cracks to the middle and outside of the shale, and eventually form an inverted "Y" type crack (15°, 30°); the third category is to sprout along the natural cracks to the middle and outside of the shale, and eventually form an inverted "Y" type crack (15°, 30°); the second type sprouts along the natural fractures toward the middle and outside of the shale, forming inverted "Y"-type fractures (15°, 30°); the third type cracks along the sides of the natural fractures, forming "Y"-type fractures (45°); and the fourth type does not crack along the natural fractures, forming "S"-type fractures (60°, 75°, and 90°). In the low natural fracture dip shale model, tensile damage mainly occurs, accompanied by a small amount of compressive shear damage; in the high natural fracture dip shale model, tensile damage and compressive shear damage account for a larger proportion in the fracture process.This suggests that the presence of natural cracks in shale has a significant impact on stress distribution. There are two main types of acoustic emission signal distribution and evolutionary features, the evolutionary features of acoustic emission signal distribution are of two types, 0°-45° test and 60°-90° test, and the difference is mainly reflected in the damage stage, the damage of shale with high natural fracture inclination is more intense, which is manifested by the decrease in the number of acoustic emission events, but the level of acoustic emission events in the damage stage is higher, which can reach 61788, 46605 and 94315, the shale with high natural fracture inclination is more brittle.

New Method for Capacity Evaluation of Offshore Low-Permeability Reservoirs with Natural Fractures

In recent years, the development of two offshore low-permeability oil fields has revealed unexpected challenges. The actual productivity of these fields significantly deviates from the designed capacity. Some wells even outperform the expectations for low-permeability limestone fields. This discrepancy primarily stems from a lack of accurate understanding of natural fractures before and after drilling, resulting in substantial errors in capacity assessment. This paper addresses these challenges by proposing a new production capacity model and evaluation method for both vertical and horizontal wells in low-permeability limestone reservoirs. The method leverages logging curve data, incorporating vertical gradation and fractal analysis to effectively represent the fracture’s complexity and connectivity. It uniquely considers factors such as fracture fractal dimensions, threshold pressure, and stress sensitivity, significantly enhancing prediction accuracy. Furthermore, by analyzing the longitudinal gradient in logging curves, the method effectively identifies strong heterogeneity, leading to more accurate capacity evaluations in actual fields. The results demonstrate that our model reduces the average prediction error to less than 15%, markedly outperforming traditional methods. Calculation results of the newly developed capacity formula align closely with actual production data and tracer test results, showcasing its practical applicability and potential for widespread use. This study notably advances the evaluation of reasonable production capacity in similar offshore reservoirs.

Natural fractures at depth in shale reservoirs: new insights from the southern Sichuan Basin marine shales

Natural fractures are pervasive in southern Sichuan Basin marine shales, China, and provide a useful opportunity to try to understand subsurface fracture networks in shale reservoirs. Based on cores and electrical imaging logs from vertical and horizontal petroleum wells in the southern Sichuan Basin, four types of natural fractures were identified in terms of orientation, size, filling properties and spatial distribution. Uncemented bed-parallel shear fractures develop at or in the vicinity of mechanical interfaces and are inclined to present in shale layers with a dip angle greater than 12°. Cemented bed-parallel fractures are characterized by a crack-seal texture marked by multiple bands of fibrous cement, and their intensity decreases upwards and shows a positive relationship with total organic carbon (TOC) values. Uncemented bed-oblique fractures are a type of fracture that rarely develops, and accommodate limited open space. Cemented bed-oblique/perpendicular fractures are the most developed fracture type and are distributed on a regional scale and are subdivided into two types. The results imply that these shale fractures could be formed sequentially by local and regional tectonic deformation, and by abnormally high pressure. Most natural fractures cannot contribute to reservoir storage or efficiently enhance its permeability, yet can act as planes of weakness and be potentially reactivated during hydraulic fracture treatments.

Machine Learning Provides Fracture Analysis, Mapping for CCUS

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 214996, “Machine-Learning Application for CCUS Carbon Storage: Fracture Analysis and Mapping in the Illinois Basin,” by Guoxiang Liu, SPE, US Department of Energy, and Abhash Kumar and William Harbert, SPE, Contractors, et al. The paper has not been peer reviewed. _ The monitoring of storage reservoirs to ensure safe, long-term storage of CO2 and to derisk operations and storage management is undergoing dynamic shifts, expanding opportunities for implementing innovative techniques and applications, especially for commercial-scale deployment. In the complete paper, a method with multitiered analysis has been developed to leverage advanced machine-learning (ML) techniques to process passive seismic monitoring data acquired during an injection period along with pumping/injection pressure and rate in the Illinois Basin for potential fracture and fault analysis. Introduction This study is part of the Science-Informed ML for Accelerating Real-Time Decisions in Subsurface Applications (SMART) Initiative funded by the US Department of Energy Carbon Storage Program. The outcomes of the SMART Initiative are science-informed, ML-based tools that can be applied at carbon storage sites throughout the nation and the world to achieve the following objectives: - Improve the ability to consolidate technical knowledge, site-specific characterization information, and real-time data in a digestible way - Enable the optimization of carbon-storage reservoirs by creating a capability for real-time forecasting of the behavior of such reservoirs - Improve the ability to understand and communicate subsurface behavior during carbon-storage operations to nonexperts Methodology In the authors’ study, a multitiered, data-driven approach was created by integrating all available measurement data to visualize fracture networks. The data sets included measurements from drilling, log and core testing, injection and downhole pressure measurements, and five vertical-pressure-monitoring gauges, providing a wealth of detail on the fracture networks. A fracture network encompasses natural fractures, induced or hydraulic fractures, and the dynamic response of such fractures, culminating in a comprehensive understanding of this system. Because of the wide range of resolutions and scales of the data sets, the fracture network was mapped into 19 distinct time windows over a 3-year injection period by analyzing pumping data, which included CO2 injection and bottomhole pressure. Passive seismic data (microseismic) were compartmentalized into these time windows, similar to the industry practice of compartmentalizing microseismic data into separate stages for high-pressure fluid- injection activities (i.e., induced fracturing). In each of these time windows, the b-value of the associated microseismic population was estimated. Furthermore, event-occurrence time and distance from the treatment well were used to identify the distinct triggering front of microseismicity likely associated with pre-existing fractures and faults within the reservoir. Seismogenic b-value and diffusivity analyses were applied to identify triggered fronts for further clustering and fracture-plane and 3D fracture-distribution analysis. The potential of several unsupervised ML algorithms was leveraged to identify the spatial clusters of microseismic events within each triggering front of individual time windows by following the work flow described in Fig. 1 of the complete paper. Furthermore, these ML techniques were implemented to determine the best-fitting surface for each spatial cluster of microseismicity to infer the directional and spatial distributions of fractures.

Permeability Modeling of Pore Shapes, Compaction, Sorption, and Molecular Diffusivity in Unconventional Reservoirs

Summary Shale and ultratight gas reservoirs are multiscale, containing organic matter (OM) and inorganic minerals in multiple pore compartments of different pore shapes and scales. Selecting a suitable model to describe the multiscale transport mechanisms requires a minimum understanding of the inherent pore shape, OM content, typical pore size, and inherent flow regime. Interestingly, during gas production and associated pressure depletion, some mechanisms, such as pore compressibility, pore diffusion, and diffusion of sorbed gas molecules, become significant at lower pressure. In this study, multiscale and multiphysics permeability models are introduced that couple the effects of poroelasticity (especially in slit-shaped pores with <1.0 aspect ratio) and sorbed gas diffusion, Fick diffusion, transition diffusion, or Knudsen diffusion, depending on the pore structural properties at multiscale for shale and ultratight gas applications. Shale here refers to organic-rich low-permeability rock with >1–2 wt% OM, while ultratight gas has negligible organic content with <1.0 wt%. These experimentally and computationally validated models could be combined with Gaussian pressure transient solutions to effectively understand the uncertainty in multiphysics gas permeability in addition to the hydraulic and natural fracture parameters for large-scale flow simulation of hydraulically fractured unconventional reservoirs.

Optimization method of refracturing timing for old shale gas wells

Based on the elastic theory of porous media, embedded discrete fracture model and finite volume method, and considering the micro-seepage mechanism of shale gas, a fully coupled seepage-geomechanical model suitable for fractured shale gas reservoirs is established, the optimization method of refracturing timing is proposed, and the influencing factors of refracturing timing are analyzed based on the data from shale gas well in Fuling of Sichuan Basin. The results show that due to the depletion of formation pressure, the percentage of the maximum horizontal principal stress reversal area in the total area increases and then decreases with time. The closer the area is to the hydraulic fracture, the shorter the time for the peak of the stress reversal area percentage curve to appear, and the shorter the time for the final zero return (to the initial state). The optimum time of refracturing is affected by matrix permeability, initial stress difference and natural fracture approach angle. The larger the matrix permeability and initial stress difference is, the shorter the time for stress reversal area percentage curve to reach peak and return to the initial state, and the earlier the time to take refracturing measures. The larger the natural fracture approach angle is, the more difficult it is for stress reversal to occur near the fracture, and the earlier the optimum refracturing time is. The more likely the stress reversal occurs at the far end of the artificial fracture, the later the optimal time of refracturing is. Reservoirs with low matrix permeability have a rapid decrease in single well productivity. To ensure economic efficiency, measures such as shut-in or gas injection can be taken to restore the stress, and refracturing can be implemented in advance.

A permeability model for the fractal tree-like fracture network with self-affine surface roughness in shale gas reservoirs

The complex natural fracture network with self-affine rough surface and branching characteristics significantly impacts the gas transport in shale gas reservoirs. However, its effects on the permeability have not been studied so far. This study proposes an analytical permeability model for the fractal tree-like fracture network with self-affine surface roughness and branching characteristics. Firstly, the self-affine rough profiles of fracture surface are generated at different fractal dimensions by the Weierstrass–Mandelbrot function and a rough fractal tree-like fracture network is constructed with these surface profiles and branching characteristics. Then, an analytical permeability model is proposed to consider the effects of fracture surface roughness and tree-like branching characteristics on gas flow. This analytical model is verified by numerical simulations. Finally, the velocity distribution of the fracture network and the sensitivity of its structure parameters are analyzed. It is found that eddy flow is more easily formed on rougher fracture surfaces with larger fractal dimension when their fracture aperture is at millimeter scale. The eddy flow disappears when the fracture aperture is at micron scale. Bigger gas flow resistance and more energy loss are observed for smaller fracture aperture and rougher fracture surface. The gas velocity in rough fractures decreases by 60% at micron scale, but decreases by 50% at millimeter scale. Gas flow resistance also increases with the increase of branch angle, branch level and length ratio, but decreases with aperture ratio. As a result, permeability decreases with fractal dimension, branch angle, branch level and length ratio, but increases with aperture ratio.

Numerical simulation of hydraulic fracture propagation after thermal shock in shale reservoir

The scale of propagation of hydraulic fractures in deep shale is closely related to the effect of stimulation. In general, the most common means of revealing hydraulic fracture propagation rules are laboratory hydraulic fracture physical simulation experiments and numerical simulation. However, the former is difficult to meet the real shale reservoir environment, and the latter research focuses mostly on fracturing technology and the interaction mechanism between hydraulic fractures and natural fractures, both of which do not consider the influence of temperature effect on hydraulic fracture propagation. In this paper, the hydraulic fracturing process is divided into two stages (thermal shock and hydraulic fracture propagation). Based on the cohesive zone method, a coupled simulation method for sequential fracturing of deep shale is proposed. The effects of different temperatures, thermal shock rates, and times on the scale of thermal fractures are analyzed. As well as the effects of horizontal stress difference and pumping displacement on the propagation rule of hydraulic fractures. The results show that the temperature difference and the thermal shock times determine the size and density of thermal fractures in the surrounding rock of the borehole, and the number of thermal fractures increases by 96.5% with the increase of temperature difference. Thermal fractures dominate the initiation direction and propagation path of hydraulic fractures. The main hydraulic fracture width can be increased by 150% and the length can be increased by 46.3% by increasing the displacement; the secondary fracture length can be increased by 148.7% by increasing the thermal shock times. This study can provide some inspiration for the development of deep shale by improving the complexity of hydraulic fractures.

Enhancing reservoir stimulation and heat extraction performance for fractured geothermal reservoirs: Utilization of novel multilateral wells

Enhanced Geothermal System (EGS) is a promising approach to improve the production efficiency of deep geothermal energy (e.g. hot dry rock). However, it faces with significant unsolved challenges to create connected fracture networks between injection-production wells, maintain high flow rates and obtain sufficient thermal power in EGSs. To address these challenges, we propose a novel multilateral-well EGS method for improving the performance of both reservoir stimulation and heat extraction from hot dry rock. In this contribution, we construct an integrated numerical model to simulate the processes of complex fracture propagation and thermal heat production as a whole. This model fully couples fluid flow, heat transfer, rock deformation and fracture propagation, taking into account the generation of new fractures, reactivation of pre-existing fractures, and mechanical interaction between hydraulic and natural fractures. The reliability of the integrated model is well verified with the analytical solution and experimental data. Subsequently, the damage and temperature fields as well as the resulting heat extraction performance of the multilateral-well EGS and conventional vertical-well EGS are compared. The results indicate that the stimulated reservoir permeability and connectivity, extracted thermal power under the configuration of multilateral-well EGS are much higher (about an order of magnitude) than those under the scheme of vertical-well EGS. This study presents a promising alternative for EGS to achieve enhanced reservoir stimulation and heat extraction performance.

The Impact of New Urbanization on Water Ecological Civilization: Based on the Empirical Analysis of Prefecture-Level Cities in Jiangxi, China

This study aims to improve the level of water ecological civilization (WEC) in the urbanization process based on the data of prefecture-level cities in Jiangxi, China, from 2011 to 2020. This paper applies spatial analysis methods such as the natural fracture method, barycenter transfer model, and standard deviation ellipse method to explore the spatiotemporal evolution characteristics of WEC and the impact of new urbanization (NU) on WEC. The NU pilot construction is further regarded as an exogenous impact, and the “net effect” of the NU pilot policy on WEC is tested. The results showed that (1) the spatial distribution pattern of the east–west polarization of WEC was broken, and a spatial distribution pattern of strong in the north and weak in the south was gradually formed. (2) NU contributes to improving the WEC level, among which population, digital, and green urbanization can significantly promote the WEC level, while economic urbanization impedes the improvement of the WEC. This conclusion is still valid following a series of robustness tests. (3) heterogeneity analysis showed that the impact of NU in improving the level of WEC is more evident in cities with scarce water resources, non-resource-based cities, and non-old industrial base cities after the implementation of NU planning. (4) NU’s pilot policy can help improve the WEC level in the region and the WEC level in neighboring regions through the spillover effect of policy. Therefore, it is necessary to make use of the superimposed effect of multidimensional urbanization based on urban characteristics, implement differentiated policy, break administrative barriers, make use of the spatial spillover effect of pilot policy, and improve the WEC level.

2D Phase-Field Modelling of Hydraulic Fracturing Affected by Cemented Natural Fractures Embedded in Saturated Poroelastic Rocks

AbstractThe interaction between a propagating hydraulic fracture (HF) and a pre-existing natural fracture (NF) embedded in saturated poroelastic rock formations is studied numerically in 2D plane–strain configurations. In this study, the phase-field method is further developed to be employed for modelling the HF propagation and the evolution of tensile and shear failure in geo-materials as gradient-type diffusive damaged zones. The shear slippage and dilation mechanisms inside the cemented NF are modelled using a Mohr–Coulomb–Griffith failure criterion that fitted in the framework of the phase-field fracture using appropriate energy functionals. The most important factors controlling the HF–NF interaction outcome are the approaching angle, differential in-situ stress, and hydro-mechanical characteristics of the NF. It is found out that higher tensile and shear strengths of the cemented NF are in favour of the crossing outcome when the differential stress is high enough to mobilise the resisting shear stresses against the slippage. Small hydraulic aperture (low hydraulic conductivity) for the NF is also in favour of the crossing outcome which helps to restrict the pressurised region local to the HF tip, lowering the possibility of shear slippage in the NF and the HF’s diversion. It is also concluded that the injection rate and the viscosity of fracturing fluid are operative factors to be adjusted for increasing the chance of crossing, a critical element for successful operation of hydraulic fracturing for effective use of subsurface energy resources.

On the tensorial nature of the hydraulic aperture of rough fractures

Current fractured porous media models may account for the roughness and geometry of the fractures to upscale hydraulic apertures that represent the local aperture distributions. Still, such approaches do not discuss the tensorial nature of the hydraulic aperture, and by employing scalar representations, these models may fail to capture the anisotropy of the fluid flow in rough fractures. By mimicking natural fractures with walls of varying roughness and contact area, we derive hydraulic aperture tensors that preserve the anisotropic flow patterns enforced by local aperture distributions. This work underscores the critical need to represent hydraulic apertures as tensors to model anisotropic fluid flow in rough fractures and proposes a method for upscaling such tensors.

A comprehensive review of numerical simulation methods for hydraulic fracturing

AbstractHydraulic fracturing unlocks previously inaccessible hydrocarbons in unconventional reservoirs by creating artificial pathways in the unconventional reservoir. Numerical simulation expands the scope of hydraulic fracturing design for various reservoir conditions. This review paper explores the synergy between numerical simulation and hydraulic fracturing modeling, focusing on critical elements like geomechanical behavior, geological conditions, and fluid dynamics. Analytical models in hydraulic fracturing design are discussed to underscore their foundational importance. The assumption of constant fracture height limits the application of Perkins–Kern–Nordgren model (PKN) and Kristianovich‐Geertsma‐de Klerk model (KGD). Radial models assume 3D flow but lack reliability in nonradial settings, and the Pseudo 3D model (P3D) shares PKN's assumptions with variable fracture height, sacrificing some details for efficiency. Planar 3D model (PL3D) enhances accuracy by discarding PKN's elastic response assumption but requires extended computation. Unconventional fracture model is effective for complex scenarios but relies on DFN modeling parameters for accuracy. The choice of numerical simulation method in hydraulic fracturing depends on the specific aspect studied, each with its strengths and limitations. For instance, boundary element methods are efficient for exterior problems, finite element modeling suits 3D nonplanar fractures, and the extended finite element method excels in hydraulic and natural fracture interactions. Peridynamics shows potential but needs further development for cost‐effectiveness. PFC and UDEC/3DEC‐based simulations can explore microscopic mechanisms. Combining these methods with other approaches provides a comprehensive study of realistic reservoir conditions. This review guides the selection of a suitable numerical simulation methodology based on the study's scope.

Enhanced oil recovery via dissolution of low molecular weight PDMS in CO2 during immiscible gas injection in matrix-fracture system

Oil recovery in natural fracture reservoirs can be improved by reducing the capillary force during the gravity drainage process in matrix-fracture system. In the current study, a modified gas was generated via dissolution of low molecular weight poly(dimethyl siloxane) (PDMS, average Mw 3780 g/mol, 10000 – 50000 ppm) in CO2 to enhance oil recovery at 50 °C or 70 °C and 3000 psi. Cloud point measurements indicated that PDMS dissolved in CO2 at pressures less than 3000 psi, which was below the minimum miscibility pressure (MMP) of ∼3600 psi at 70 °C determined with the vanishing interfacial technique. The solution density increased from 669.6 kg/m3 for pure CO2 to 780.3 kg/m3 for CO2/PDMS (50000 ppm) at 70 °C and 3000 psi, thereby reducing the density difference between the CO2-rich fluid and crude oil (ρo=865.2 kg/m3) in matrix-fracture system. Also, CO2-oil interfacial tension (IFT) was reduced from 65 to 15 dyn/cm via the dissolution of 50000 ppm PDMS in CO2. Therefore, it led to the CO2 diffusion coefficient increased in both reservoir-fluid saturated porous media and bulk oil scenarios 3–4 fold and 4–7 fold respectively in comparison to pure CO2 injection. These PDMS-induced changes reduced the capillary effects in gas-invaded zone, which consequently led to an increase in oil recovery of 25% points (from 31% to 56%) compared to pure CO2 injection in the case of capillary continuity during gravity drainage tests. For the field-scale, because the PDMS can dissolve in CO2 at pressures and temperatures which are commensurate with CO2 EOR, it is a promising CO2-philic chemical for increasing CO2 density and improving CO2 diffusion coefficient in gas invaded zone compared to conventional CO2 injection.

Single-plane osteotomy model is inaccurate for evaluating the optimal strategy in treating vertical femoral neck fractures: A finite element analysis

Background and objectivesThe conventional method for simulating vertical femoral neck fractures (vFNFs) is via a vertical single-plane osteotomy (SPO) across the entire femur. However, the accuracy of SPO for evaluating the optimal internal fixation strategy (IFS) and the appropriate assessment parameters is not clear. This study thus aimed to examine the accuracy of SPO in evaluating IFSs and to identify appropriate evaluation parameters using finite element analysis. MethodsEighty patient-specific finite element models were developed based on CT images from eight vFNF patients. The natural fracture model was built using structural features of the affected side, while the SPO was simulated on the healthy side. Five different IFSs were applied to both the natural fracture and SPO groups. Thirteen parameters, including stress, displacement, and stiffness, were subjected to a two-way repeated measures ANOVA to determine the effect of IFSs and fracture morphology on stability. A Pearson correlation analysis was performed on varied parameters with various IFSs to identify independent parameters. Based on these independent parameters, the entropy evaluation method (EEM) score was used to rank the performance of IFSs for each patient. ResultsEight of the thirteen parameters were significantly influenced by IFSs (p < 0.05), two by fracture morphology (p < 0.01), and none by the interaction between IFS and fracture morphology. In the natural fracture group, parameters including screw stress and displacement, bone cut rate (BCR), and compression effects varied independently with distinct IFSs. In the SPO group, trunk displacement, BCR, cut-out risk, and compression effects parameters changed independently. The BCR of the Alpha strategy was significantly higher than that of the Inverted strategy in the natural fracture group (p = 0.002), whereas the opposite was observed in the SPO group (p = 0.016). Regarding compression effects, two IFS pairings in the natural fracture group and seven IFS pairings in the SPO group exhibited significant differences. None of the five IFSs achieved the optimal EEM score for each patient. ConclusionsThe single-plane osteotomy model may have limitations in assessing IFSs, particularly when the bone cut rate and compression effects are the main influencing factors. Parameters of the screw stress and displacement, BCR, and compression effects appear to be relevant in evaluating IFSs for natural fracture models. It indicates that individualized natural fracture models could provide more comprehensive insights for determining the optimal IFS in treating vFNFs.

Experimental study on the effect of foam in preventing gas channeling in shale reservoir

Shale oil resources have enormous potential and broad development prospects in China. Especially with the rapid development of horizontal well volume fracturing technology, the production of shale oil has been greatly increased, and it has become an important position to increase oil and gas storage and production. However, due to the existence of artificial and natural fractures produced by fracturing, gas channeling will occur in the process of huff-n-puff gas injection, which will affect the production and lead to poor development effect. In this paper, foam is used as an anti-channeling agent in the process of huff-n-puff gas injection. The results of microfluidic experiments show that the production mode of foam in porous media is liquid membrane hysteresis and liquid membrane separation. In porous media, foam first blocks large channels such as fractures, and then enters the matrix. The oil recovery mechanism of foam assisted gas injection in porous media is to improve the sweep efficiency and oil displacement efficiency of gas. Compared with N2 huff-n-puff, the oil recovery of the first cycle of foam assisted N2 huff-n-puff increased by 4.50%, and the third cycle increased by 9.58%. It is proved that foam has good anti channeling effect in gas huff-n-puff injection process. The research results provide an effective method for efficient gas injection development of shale oil.

Characterization and reconstruction of rough fractures based on vector statistics

The characteristics of fracture networks are of great significance for unconventional geo-energy exploitation such as shale oil, shale gas and geo-thermal extraction. Natural fractures and induced fractures after reservoir stimulation control the mechanical properties and fluid flow of the reservoirs. The quantitative characterization and reconstruction of rough fractures are essential for studying the fluid flow and mechanical properties of the reservoirs with complicated fracture networks. Based on vector statistics, a vector statistical method (VSM) for quantitative characterization of rough fractures is proposed and tested using 10 standard joint profiles. Furthermore, the growth vector counting method (counting method) and growth vector probability method (probability method) for single rough fractures in two-dimensional (2D) and three-dimensional (3D) models are proposed. Afterward, a morphology comparison and quantitative evaluation of single rough fractures before and after reconstruction are conducted. When the counting and probability methods are used to reconstruct single rough fractures, the difference in the tortuosity and fractal dimensions of the original and reconstructed fractures are less than 5% and 2.5%, respectively. It implies the counting and probability methods proposed herein can reconstruct rough fractures with approximate statistical characteristics and quantitative characterization parameters. Subsequently, the counting and probability methods for single rough fractures are further developed for 2D and 3D modeling of conventional and rough discrete fracture networks. The results indicate that the growth vector counting and probability methods proposed in this study have significant potential for rough discrete fracture network modeling. In addition, the merits and limitations of the proposed algorithms in modeling discrete fracture network models are discussed.

Numerical simulation study on evolution law of three-dimensional fracture network in unconventional reservoirs

It has become a consensus that large-scale hydraulic fracturing is adopted to achieve the stimulation of unconventional oil and gas reservoir. The complex fracture network formed by fracturing is closely related to the effect of reservoir stimulation, which has extremely complicated evolution process. Therefore, it is necessary to study the evolution law of fracture network in large-scale hydraulic fracturing of unconventional reservoirs. In this article, the geological engineering parameters of horizontal well H in shale gas reservoir in southern Sichuan are taken as an example, a three-dimensional fracture network expansion model is established based on the boundary element method and finite volume method, and the simulation of the complex fracture network in a whole well section is carried out to analyze the evolution law of reservoir fracture network under different geological and engineering parameters. The results show that the horizontal stress field distribution has a significant effect on fracture geometric form. Hydraulic fractures in reservoirs with larger horizontal stress difference have stronger directivity, while the horizontal wellbore tends to obtain better reservoir stimulation results when it is parallel to the minimum horizontal principal stress setting. The conjugated natural fracture developed in the reservoir inhibits the hydraulic expansion fractures in both directions. Although it increases the complexity of the fractures, it is not necessarily conducive to improving the reservoir stimulation effectiveness. The lower the strength of natural fracture is, the more complex the fracture geometric form becomes, and the smaller the stimulated reservoir volume is. Correspondingly, the higher the strength of natural fracture is, the simpler the fracture geometric form becomes, and the larger the stimulated reservoir volume is. Suitable fracturing construction displacement can not only contribute to form a more complex fracture distribution, but also help to obtain a larger stimulated reservoir volume. The optimal construction displacement ranges from 10 to 14 m3/min. Low viscosity fracturing fluids are suitable for the formation of long-narrow fractures and able to connect with the remote reservoir and form complex fracture networks. Lower viscosity fluids can be used to achieve better reservoir stimulation effectiveness when sand-carrying capacity is met.

Optimization Simulation of Hydraulic Fracture Parameters for Highly Deviated Wells in Tight Oil Reservoirs, Based on the Reservoir–Fracture Productivity Coupling Model

The production potential of highly deviated wells cannot be fully realized by conventional acid fracturing, as it can only generate a single fracture. To fully enhance the productivity of highly deviated wells, it is necessary to initiate multiple fractures along a prolonged well section to ensure the optimal number of fractures, thereby maximizing the economic returns post-stimulation. Thus, the number of fractures is a crucial parameter in the acid fracturing design of highly deviated wells. Considering factors such as the random distribution of natural fractures within the reservoir and interference between fractures during production, and, based on the oil–water two-phase flow equation, a three-dimensional reservoir–fracture production coupling model and its seepage difference model are established to simulate the production performance of highly deviated wells under varying conditions, including the number of fractures, fracture spacing, and conductivity parameters. A numerical model for the number of acid fracturing fractures in highly deviated wells is also established, in conjunction with an economic evaluation model. The simulation results indicate that the daily oil production of highly deviated wells increases with the increase in fracture number, fracture conductivity, fracture length, and reservoir permeability. However, over time, the daily oil production gradually decreases. Similarly, the cumulative production also increases with these parameters, but shows a downward trend over time. By conducting numerical simulations to evaluate the productivity and economy of highly deviated wells post-acid fracturing, it is determined that the optimal number of fractures to achieve maximum efficiency is six. The reliability of this result is confirmed by the pressure distribution cloud map of the formation after acid fracturing in highly deviated wells.

Study on the interaction between hydraulic fracture and natural fracture under high stress

The existence of natural fractures in the reservoir has a great influence on the formation of complex fracture network, but the interaction between hydraulic fractures and natural fractures under high stress was rarely studied. Through laboratory tests, the law and characteristics of the interaction between hydraulic fractures and natural fractures under high stress were studied from the aspects of natural fractures angle, size, quantity, production method and ground stress in this study. Based on these interaction characteristics, a complex fracture network formation method of deep reservoir was proposed, which provided reference for engineering practice. The criterion of interaction between hydraulic fracture and natural fracture was improved, and the calculation method of rock tensile strength in three-dimensional state was proposed, which was applied to the criterion of fracture opening and fracture expansion. Combined with laboratory tests, a special interaction mode of hydraulic fracture passing through a certain position from the direction to end A (F-Type crossing mode) under high stress was proposed, and the criterion of this interaction mode were obtained. The three-dimensional finite discrete element model (FDEM) was used to investigate the effects of natural fracture strength and fracturing fluid viscosity on hydraulic fracture propagation under high stress. The results showed that the natural crack strength has great influence on the width, volume and shape of hydraulic crack. Small difference of fracturing fluid viscosity has little influence on fracture propagation, but high viscosity fracturing fluid has a greater influence on fracture propagation. This study provided reference for hydraulic fracturing engineering.