Oil Shale Research Articles

Characterization and source apportionment of ambient VOC concentrations: Assessing ozone formation potential in the Barnett shale oil and gas region

Atmospheric concentration and distribution of volatile organic compounds (VOC) are influenced by localized emissions and the fate and transport of secondary products formed through photochemical reactions. This study identifies the sources of VOC and its contribution to ozone formation in the Barnett Shale region, specifically in Denton, Texas, during the ozone seasons of 2015 through 2022. A total of 31 critical ozone precursor VOC compounds were observed at this site with an average total VOC concentration of 146 ppb-C, with n-alkanes from extensive oil and gas activities in the area contributing to 96.64% of the total VOC. Source apportionment using dispersion normalized positive matrix factorization (DN-PMF) identified eight VOC sources, with natural gas emissions (72%) being the dominant source followed by a combined source of natural gas combustion and aviation emissions (8.3%). Ozone formation potential (OFP) by VOC species was calculated using the propylene-equivalent concentration (propy-equiv) method. OFP calculated for all the apportioned sources highlighted that natural gas sources contributed significantly to the ozone formation in this region besides isoprene from biogenic sources and reactive alkenes from urban and industrial activities. This study underscores the critical role of slow-reacting n-alkanes along with other highly reactive VOC from urban and industrial sources influencing ambient air quality and it identifies strategies for mitigating ground-level ozone in urban areas affected by oil and gas extraction and production.

Fracture propagation characteristics of water and CO2 fracturing in continental shale reservoirs

Exploring the adaptability of CO2 and water-based fracturing to shale oil reservoirs is important for efficiently developing shale oil reservoirs. This study conducted fracturing experiments and acoustic emission (AE) monitoring on the Jurassic continental shale. Based on high-precision computed tomography scanning technology, digital reconstruction analysis of fracture morphology was carried out to quantitatively evaluate the complexity of fractures and the stimulation reservoir volume (SRV). The results show that the fracturing ability of a single water-based fracturing fluid is limited. Low-viscosity fracturing fluid tends to activate thin layers and has limited fracture height. High-viscosity fracturing fluid tends to result in a wide and simple fracture. A combination injection of low-viscosity and high-viscosity water-based fracturing fluid can comprehensively utilize the advantages of low-viscosity and high-viscosity fracturing fluids, effectively improving the complexity of fractures. CO2 fracturing is adaptable to Jurassic shale. The breakdown pressure of the supercritical CO2 (SC-CO2) fracturing is low. Branch fractures form, and laminas activate during SC-CO2 fracturing due to its high diffusivity. Under high-temperature and high-pressure conditions, the aqueous solution formed by mixing CO2 with water can promote the formation of complex fractures. Compared with water-based fracturing fluid, the complexity of fractures and effective stimulation reservoir volume (ESRV) increased by 8.7% and 47.6%, respectively. There is a high correlation between SRV and ESRV, and the proportion of AE shear activity is also highly correlated with the complexity of fractures. The results are expected to provide better fracturing schemes and effectiveness for continental shale oil reservoirs.

Research Progress and Significance of Shale Oil Micro-Migration

Research Progress and Significance of Shale Oil Micro-Migration

Lithology identification using electrical imaging logging image: A case study in Jiyang Depression, China

Lithology identification plays a significant role in stratigraphic evaluation and geological analysis. Traditional lithology identification method is by modeling the relationship between well logging and lithology. However, well logging are not always sufficient to identify lithology since sometimes the curves are similar for different lithologies. Recently, electrical imaging logging image (EILI) with high resolution plays an increasingly important role in logging interpretation since EILI can intuitively reflect the characteristics of lithology. Unlike traditional lithology identification method by using well logging, in this paper, we propose a novel multi-dimensional automatic lithology identification method by applying deep learning to EILI. First, Filtersim algorithm is employed to fill the blank strip of the EILI. Then, an integrated convolutional neural networks (CNNs) model is designed to extract the resistivity feature, texture feature, and holistic feature of the EILI, respectively. Specifically, the integrated CNNs model can realize automatic recognition for different geological structures (massive, bedded, lamellar) and lithology (mudstone, sand-mudstone, lime-mudstone). Finally, lithology identification can be achieved by combining with multi-dimensional features. The efficacy of proposed integrated model is validated experimentally on the EILI of shale oil reservoir in the Jiyang Depression of China. Experimental results show the effectiveness and superiority of the integrated CNNs method for lithology identification.

Three-dimensional physical experimental study on mechanisms and influencing factors of CO2 huff-n-puff and flooding process in shale reservoirs after fracturing

Carbon dioxide (CO2) capture and geological storage technology is a promising strategy for enhancing oil and gas production and mitigating climate change in unconventional formations. In shale reservoirs, production decline is rapid under volumetric fracturing development. Currently, CO2 injection and huff-n-puff techniques are cost-effective methods to boost shale oil recovery. However, traditional huff-n-puff techniques are limited in capturing reservoir heterogeneity and intricate fracture conditions. This study employed a three-dimensional physical experimental apparatus to explore CO₂ huff-n-puff dynamics across six distinct fracture patterns. By implementing a real-time monitoring system with multiple pressure points, the study elucidated the impacts of varying fracture penetration levels and spacing on dynamic pressure wave patterns, mobilization extent, and development outcomes during CO2 huff-n-puff. The results demonstrate that fractures substantially improve CO₂ huff-n-puff efficiency in shale reservoirs compared to a seamless model, with Model 6 achieving the highest recovery rate of 42.38%. As fracture penetration increases, CO₂ dynamic coverage expands. However, full penetration leads to preferential flow through fractures, reducing matrix contact and diminishing huff-n-puff efficiency. Reduced fracture spacing enlarges the well's control domain, amplifies CO2 huff-n-puff dynamic coverage area, and increases oil production and recovery rate. Conversely, decreasing fracture spacing accelerates oil and gas displacement rates, leading to higher economic expenses. The study concludes that 2/3 fracture penetration in five fractures offers the most efficient recovery method. For a 500 m horizontal well, optimal fracture spacing is recommended at 125 m, with a fracture length of 145.8 m for a well spacing of 417 m.

Integrating Petrophysical, Hydrofracture, and Historical Production Data with Self-Attention-Based Deep Learning for Shale Oil Production Prediction

Summary As the energy industry increasingly turns to unconventional shale reservoirs to meet global demands, the development of advanced predictive models for shale oil production has become imperative. The inherent complexity of shale formations, coupled with the intricacies of hydraulic fracturing, poses significant challenges to efficient resource extraction. Our study leverages a substantial data set from the Ordos Basin to develop an advanced predictive model, integrating 18 parameters that blend static petrophysical attributes and dynamic factors, including hydraulic fracturing parameters and real-time pump pressure data. This holistic approach enables our self-attention (SA) model to accurately forecast future production rates by processing the complex interplay between reservoir characteristics and operational inputs. In testing across three wells, the model achieved average accuracies of 99.28% for daily oil production (DOP) and 99.25% for daily liquid production (DLP) over 20 days, surpassing traditional long short-term memory (LSTM) and gated recurrent unit (GRU) models, proving its efficacy in fractured well production forecasting. Furthermore, using the initial 30 days of production data as input, the model demonstrated its capability to predict DOP and DLP over a one-year period, achieving prediction accuracies of 96.2% for DOP and 99.6% for DLP rates. Our model’s profound implications for the shale industry include establishing a quantifiable link between key factors and production forecasts, guiding the optimization of controllable aspects, and serving as a decision-support tool for more efficient and cost-effective oil recovery.

Differential hydrocarbon generation characteristics of organic matter with green algae and cyanobateria origins in the Permain Lucaogou Formation of the Santanghu Basin

Organic-rich fine-grained rocks are key carriers of unconventional oil and gas resources, making it crucial to understand their hydrocarbon generation and evolution characteristics. This study examines the fine-grained rocks of the second member of the Lucaogou Formation (P2l2) in the Tiaohu and Malang Sags of the Santanghu Basin, focusing on how different organic matter (OM) backgrounds - primarily green algae and cyanobacteria - affect hydrocarbon generation and crude oil properties. Kinetic analysis and hydrous pyrolysis experiments on shales rich in green algae, cyanobacteria, and their mixtures revealed that green algae - derived OM requires lower activation energy to initiate hydrocarbon generation, results in an earlier oil generation peak, and has a broader oil window. Conversely, cyanobacteria - derived OM needs higher activation energy to start hydrocarbon generation, has a later oil peak, and a more concentrated generation period. These findings led to two models: the "green algae origin - early hydrocarbon generation - early oil peak - broad oil window model" and the "cyanobacteria origin - late hydrocarbon generation - late oil peak - concentrated oil generation model." Correlation analysis showed that aromatic hydrocarbons, resins, and asphaltenes significantly degrade crude oil quality. Hydrous pyrolysis experiments indicated that the heavy component content (aromatic hydrocarbons + resins + asphaltenes) in liquid hydrocarbons follows the order: residual oil > absorbed oil > expelled oil, with content initially increasing and then decreasing with maturity, and the color change of liquid hydrocarbons in dichloromethane reflects heavy component content changes effectively. Calculations of density and viscosity of liquid hydrocarbons, based on heavy component content and crude oil properties, were compared with the longitudinal distribution of crude oil properties in the study area. Results show that the hydrocarbon generation characteristics of green algae and cyanobacteria control crude oil properties, highlighting significant intra-source differentiation in the P2l2 shale and validates the phase separation approach in hydrous pyrolysis experiments. The P2l2 shale, with its high OM content and substantial hydrocarbon generation, holds great potential for shale oil exploration, but both reservoir quality and crude oil property evolution under different OM backgrounds should be considered when selecting favorable areas.

Genetic mechanism and petroleum geological significance of calcite veins in organic-rich shales of lacustrine basin: A case study of Cretaceous Qingshankou Formation in Songliao Basin, China

Based on the observation and analysis of cores and thin sections, and combined with cathodoluminescence, laser Raman, fluid inclusions, and in-situ LA-ICP-MS U-Pb dating, the genetic mechanism and petroleum geological significance of calcite veins in shales of the Cretaceous Qingshankou Formation in the Songliao Basin were investigated. Macroscopically, the calcite veins are bedding parallel, and show lenticular, S-shaped, cone-in-cone and pinnate structures. Microscopically, they can be divided into syntaxial blocky or columnar calcite veins and antitaxial fibrous calcite veins. The aqueous fluid inclusions in blocky calcite veins have a homogenization temperature of 132.5–145.1 °C, the in-situ U-Pb dating age of blocky calcite veins is (69.9±5.2) Ma, suggesting that the middle maturity period of source rocks and the conventional oil formation period in the Qingshankou Formation are the sedimentary period of Mingshui Formation in Late Cretaceous. The aqueous fluid inclusions in fibrous calcite veins with the homogenization temperature of 141.2–157.4 °C, yields the U-Pb age of (44.7±6.9) Ma, indicating that the middle-high maturity period of source rocks and the Gulong shale oil formation period in the Qingshankou Formation are the sedimentary period of Paleocene Yi'an Formaiton. The syntaxial blocky or columnar calcite veins were formed sensitively to the diagenetic evolution and hydrocarbon generation, mainly in three stages (fracture opening, vein-forming fluid filling, and vein growth). Tectonic extrusion activities and fluid overpressure are induction factors for the formation of fractures, and vein-forming fluid flows mainly as diffusion in a short distance. These veins generally follow a competitive growth mode. The antitaxial fibrous calcite veins were formed under the driving of the force of crystallization in a non-competitive growth environment. It is considered that the calcite veins in organic-rich shale of the Qingshankou Formation in the study area has important implications for local tectonic activities, fluid overpressure, hydrocarbon generation and expulsion, and diagenesis-hydrocarbon accumulation dating of the Songliao Basin.

Molecular Dynamics Insights into the Adsorption and Diffusion of Oil Shale Secondary Lysates in SBA-15 with Different Si/Al Ratios

Molecular Dynamics Insights into the Adsorption and Diffusion of Oil Shale Secondary Lysates in SBA-15 with Different Si/Al Ratios

Production of Shale Oil and Gas in the US: Current Status and Prospects

Production of Shale Oil and Gas in the US: Current Status and Prospects

Evaluation of the reaction order and kinetic modeling of Domanic oil shale upgrading at supercritical water conditions

Two different kinetic models were developed for the kinetic study of Domanic oil shale conversion in the supercritical water. The oil shale reaction order was evaluated with a three-lump reaction scheme taking into account oil shale, gases, and synthetic oil. Contrary to the commonly reported first-order, it was found that a higher order (2.5) is more suitable for the conversion of oil shale at supercritical water conditions. The main reaction mechanism and predictions were obtained using a more detailed reaction network (five-lump model), which precisely estimates the experimental yield of all compounds contemplated. The statistical analysis suggested that the estimated kinetic parameters were suitably optimized, as well as the sensitivity analysis confirmed that these are the optimal values. The conversion of organic matter into gas and coke through free radical reactions exhibits larger rates using supercritical water. Low temperature (380 °C) and short reaction times favor the yield of synthetic oil because when these conditions are exceeded secondary cracking reactions provoke the generation of gases. Gas production is mainly carried out by the conversion of organic matter for brief reaction times and the transformation of carbonates for extended periods.

Improving lithofacies prediction in lacustrine shale by combining deep learning and well log curve morphology in Sanzhao Sag, Songliao Basin, China

The accurate identification of shale lithofacies is crucial for characterizing the hydrocarbon potential of lacustrine shale oil reservoirs. Petrophysical logging, serving as an effective tool for acquiring subsurface lithofacies information, provides a convenient and reliable lithofacies identification solution. Deep learning technology, capable of adapting to the nonlinearity and non-stationarity inherent in geological statistics, exhibits unique advantages in conventional reservoir lithofacies prediction. However, the lithofacies of lacustrine shale formations undergo rapid spatial and temporal changes, rendering lithofacies prediction more complex compared to conventional reservoirs. In this study, the lower Qingshankou member in the Sanzhao Sag was selected as the research target, and the Deep Residual Shrinkage Network (DRSN), known for its ability to handle complex nonlinear relationships and mitigate the effects of noisy data through residual connections and shrinkage mechanisms, was employed as a deep learning framework for predicting lithofacies in lacustrine shale formations for the first time. Well logging data, including natural gamma ray (GR), acoustic (AC), deep investigate double lateral resistivity log (RD), shallow investigate double lateral resistivity log (RS), and corrected compensated neutron log (CNC), were used as input features for the model. The results indicate that the DRSN model achieves an accuracy of 76.3% in predicting lithofacies in lacustrine shale formations. However, the DRSN model still exhibits shortcomings in capturing lithofacies change information. To enhance the model's ability to identify lithofacies change interfaces, this study further explicitly introduces Well Logging Curve Morphological Features (WLCM) as additional features and establishes a recognition method combining DRSN with WLCM. The combined DRSN-WLCM model was validated using a separate test dataset, demonstrating an improved accuracy of 85.5%, using the five well logging attributes and the derivative of the AC as inputs. Furthermore, the study reveals the lithofacies spatial distribution characteristics of the lower Qingshankou member in the Sanzhao Sag. This method can be widely applied to lithofacies delineation in lacustrine shale formations and similar stratigraphic units.

Numerical Study on the Enhanced Oil Recovery by CO2 Huff-n-Puff in Shale Volatile Oil Formations

The Sichuan Basin’s Liangshan Formation shale is rich in oil and gas resources, yet the recovery rate of shale oil reservoirs typically falls below 10%. Currently, gas injection huff-n-puff (H-n-P) is considered one of the most promising methods for improving shale oil recovery. This study numerically investigates the application of the CO2 huff-n-puff process in enhancing oil recovery in shale volatile oil reservoirs. Using an actual geological model and fluid properties of shale oil reservoirs in the Sichuan Basin, the CO2 huff-n-puff process was simulated. The model takes into account the molecular diffusion of CO2, adsorption, stress sensitivity effects, and nanopore confinement. After history matching, through sensitivity analysis, the optimal injection rate of 400 tons/day, soaking time of 30 days, and three cycles of huff-n-puff were determined to be the most effective. The simulation results show that, compared with other gases, CO2 has significant potential in improving the recovery rate and overall efficiency of shale oil reservoirs. This study is of great significance and can provide valuable references for the actual work of CO2 huff-n-puff processes in shale volatile oil reservoirs of the Sichuan Basin.

Hyperelastic constitutive relations for porous materials with initial stress

Initial stress is widely observed in porous materials. However, its constitutive theory remains unknown due to the lack of a framework for modeling the interactions between initial stress and porosity. In this study, we construct the porous hyperelastic constitutive model with arbitrary initial stresses through the multiplicative decomposition approach. Based on the compression experiment of shale samples, the parameters in the constitutive equation are determined. Then, the explicit equations of in-plane elastic coefficients are proposed by linearizing the finite deformation formulation. The influences brought by the coexistence of initial stresses and porosity on these coefficients are revealed. Later, comparative analyses of the linearized equations between the present model, the initially-stressed models without pores, the Biot poroelasticity, and the porous hyperelastic model without initial stress are conducted to illustrate the performances of the two ingredients. As a specific example, we investigate the variation of pore sizes under external pressures and initial stresses since changes in pore sizes during deformation are crucial for understanding the accumulation and migration of shale oil and gas. The newly proposed model provides the first initially stressed porous hyperelasticity (ISPH), which is suitable for describing the finite deformation behavior of solid materials with large porosity and significant initial stress simultaneously.

Short-term interactions between Longmaxi shale and carbon dioxide-based fracturing fluids

The shale is a dense quarried rock material containing abundant shale oil/gas. Extracting shale gas usually requires fracturing the rock formation to speed up gas desorption and migration. Supercritical carbon dioxide fracturing, as an environmentally friendly and waterless fracturing technique of reservoir stimulation, gains increasing recognition in commercial exploitation of shale oil and gas. However, there is insufficient understanding on the interaction between carbon dioxide-based fracturing fluids and shale, as well as its influence on the mechanical parameters of shale, which are pivotal for determining injection parameters and forming the fracture network. This study focuses on the injection of carbon dioxide-based fracturing fluids to enhance shale gas extraction and carbon dioxide sequestration. Simulation tests of injection were conducted to investigate the influence of different fracturing fluids (deionized water, gaseous/supercritical carbon dioxide, gaseous/supercritical carbon dioxide mixed with brine) injected into shale reservoirs on the microstructure and mechanical properties of shale after short-term physicochemical interaction. This article adopts research methods such as uniaxial compression and uniaxial tensile mechanical experiments based on acoustic emission monitoring and various physical characterizations such as scanning electron microscopy, X-ray diffraction, X-ray fluorescence spectrometer, etc. Results show that following treatment with different carbon dioxide-based fluids, the uniaxial tensile/compressive strength, elastic modulus, fractal dimension of pore structure, and the brittleness index of shale exhibit varying degrees of decrease compared to those of dry untreated shale samples. After interacting with different carbon dioxide-based fracturing fluids, the mechanical parameters and brittleness index of shale decrease more significantly than that of the others as the addition of brine. This study shows that the water in carbon dioxide-based fracturing fluids is a controlling factor affecting the elastic modulus of shale. Additionally, the ductility of the shale increases and the acoustic emission emitting lag due to the coupling effects of brine and carbon dioxide. The change law of the elemental and mineral composition of the shale is consistent with the mechanical strength; and the change of element content and mineral composition is the most significant. Compared to gaseous carbon dioxide, the supercritical carbon dioxide has a greater impact on mineral composition of the shale. The change of mechanical strength and microstructure evolution mechanism caused by the short-term interactions between the shale and fracturing fluids provide theoretical references and implications for the determination of injection parameters and permeability transformation of the Longmaxi shale reservoirs.

Distribution, Origin, and Impact on Diagenesis of Organic Acids in Representative Continental Shale Oil

Distribution, Origin, and Impact on Diagenesis of Organic Acids in Representative Continental Shale Oil

Feasibility and recovery efficiency of in-situ shale oil conversion in fractured reservoirs via steam heating: Based on a coupled thermo-flow-chemical model

Shale oil is a type of liquid hydrocarbon obtained through the pyrolysis of organic matter such as kerogen in oil shale reservoirs. Effective extraction of shale oil can significantly alleviate the pressure on oil supply. Among the various methods proposed for shale oil extraction, in-situ conversion of shale oil through high-temperature steam heating is a promising technique. This study employs a newly developed thermo-flow-chemical numerical simulator to establish a heterogeneous geological model and provides a detailed description of the evolution of different components within the shale oil reservoir during the in-situ conversion process. Additionally, the study thoroughly analyzes the role of high-permeability channels, such as fractures, in fluid transport and heat transfer during this process. In comparison with homogeneous reservoirs, fractures play a controlling role in the transport of steam. After injection, steam forms a preferential transport path between the heating well and the production well through the fractures. Subsequent injected steam will preferentially travel through this path, leading to faster heating of the reservoir. However, the uneven distribution of fractures may result in incomplete pyrolysis of the organic matter within the reservoir. Additionally, we found that the producing pressure and the steam injection rate significantly affect the pyrolysis of kerogen and the production of oil and gas. Both excessively low producing pressure and excessively high steam injection rate are detrimental to shale oil extraction. Based on these findings, this study aims to develop more rational heating strategies for reservoirs with different characteristics.

Damage mechanism of proppant and conductivity reduction post fracturing in unconventional reservoirs

To investigate the impact of proppant embedding and crushing damage on the conductivity in unconventional oil and gas development, experiments on long-term conductivity under suspension injection of proppant were conducted on shale and tight sandstone samples. Based on elastic contact mechanics theory, finite element software (Abaqus) was secondarily developed to globally embed proppant meshes with cohesive elements, analyzing the dynamic changes involving proppant embedding, deformation, and crushing under different closure pressures. The results indicated that the conductivity of fractures is highly sensitive to closure pressure. When closure pressure increases to 40 MPa, the conductivity of shale damage exceeds 60 % compared to 10 MPa. Larger proppants and shale reservoirs accelerate the decline in conductivity significantly, compared to tight sandstone. Combined with laser scanning and fractal dimension identification, the roughness of shale fracture (JRC48) was found to be much greater than that of tight sandstone (JRC37), leading to significantly higher stress concentration between proppants and shale, resulting in a smaller crushing ratio. Additionally, the deformation of shale and contacting proppant is significantly greater than in sandstone, resulting in a rapid decline in shale oil production. These findings provide theoretical guidance for ensuring effective inflow near oil wells, necessitating optimization of proppant injection sequence and placement concentration.

Comprehensive Evaluation of Microscopic Movability and Macroscopic Productivity of Continental Shale Reservoir

Abstract Continental shale oil is diversified, differentiated and complex. It suffers from low production and inferior development benefits. Given this, the movability and productivity of shale oil were proposed in this research to evaluate the producible capacity and development potential of shale oil. Taking the Yingxiongling shale oil reservoir as an example, the microscopic movability and macroscopic productivity of the main lithofacies were systematically investigated via the NMR tests, imbibition experiments, uniaxial compression tests, and CT imaging. The characteristics of different lithofacies were clarified, and the favorable targets were identified. The results showed that the layered limy dolomite of the shale oil reservoir has the highest microscopic movability, followed by that of the laminated limy dolomite and the least of the laminated clayed shale. The laminated limy dolomite has better fluid flow properties, higher capacity to form fracture network and the best macroscopic productivity. The layered limy dolomite has the medium macroscopic productivity, and that of the clayed shale is the least. Based on the field testing and experimental understanding of layered limy-dolomitic shale as high-quality targets, the laminated limy-dolomitic shale is further identified as a favorable target. It features a stronger capacity to form fracture networks, better imbibition performance, medium microscopic movability and relatively high macroscopic productivity. This research further clarifies the correlation between microscopic movability and macroscopic productivity and provides theoretical support for the exploration and development of the continental shale oil reservoir.

Numerical Simulation Study on Dynamic Interaction between Two Adjacent Wells during Hydraulic Fracturing

The heterogeneity in fracture formation significantly influences the hydraulic fracture propagation among adjacent wells, underscoring the urgency to comprehend the underlying fracture mechanisms. Specifically, in shale gas or oil extraction fracturing operations, stress interactions among neighboring fracturing clusters, or mutual interference during the propagation of parallel fractures, are commonplace. At present, there is relatively little research on the sensitivity parameters of adjacent borehole fracture propagation morphology. Consequently, we employed ABAQUS software 2022 to construct a numerical model simulating the fracturing of adjacent boreholes in opposing directions. Upon validating the model’s fidelity, we systematically explored the influence of various engineering and geological factors on fracture morphology and propagation length. Our findings revealed a three-phase evolution: independent fracture propagation, subsequent mutual repulsion, and, ultimately, mutual attraction. It is worth noting that increasing the elastic modulus from 10 GPa to 80 GPa, and increasing the crack length by 16.30%, is beneficial for crack propagation, while the horizontal stress difference profoundly shapes the crack mode, but has a relatively small impact on the overall crack length. When HSD increases from 0 MPa to 15 MPa, the total crack length only changes by 1.24%. In addition, the filtration coefficient of the reservoir is a key determining factor that has a significant impact on the morphology and length of cracks generated by adjacent boreholes. Increasing the filtration coefficient from 1 × 10−14 m3/s/Pa to 5 × 10−12 m3/s/Pa reduces the total length of cracks by 60.77%. Notably, an optimal injection rate exists, optimizing fracturing outcomes. Conversely, the viscosity of the fracturing fluid exerts a limited influence on fracture morphology and length within the confines of this simulation, allowing for the selection of a suitable viscosity to ensure smooth proppant transport during actual fracturing operations. In designing fracturing parameters, it is imperative to aim for sufficient fracture propagation length while harnessing “stress interference” to foster the development of intricate fracture networks. Ultimately, our research findings serve as a solid foundation for engineering practices involving hydraulic fracture propagation in adjacent boreholes undergoing opposing fracturing operations.