Hydraulic Fracturing Research Articles

Experience in developing carbonate formations with hydraulic fracturing at fields of Gazprom Neft Group

The development of carbonate formations with hydraulic fracturing is a very interesting and controversial process. In contrast to terrigenous formations, zonal stimulation can be performed by both acid and proppant fracturing methods, and the abundance of process variations expands the options even further. Although there is a general concept of choosing hydraulic fracturing technology depending on the geological and physical characteristics of the formation, the qualitative choice is complicated by the fact that effective solutions for one reservoir could not show the same efficiency in similar conditions at another one. For this reason, from the point of view of working with carbonates, to have as extensive experience as possible in various well conditions in order to minimize production risks and costs associated with the choice of approach and zonal stimulation technology. The study aims to provide a technological overview of effective fracturing solutions for carbonate formations, seeking to understand their features and applicability depending on well and geological conditions. An important place is given to the communication of experience in the application of stimulation technologies that have proven themselves at carbonate formations of Gazprom Neft and show the risks and limitations that can be encountered when choosing a particular solution. It describes experience in hydraulic and multistage fracturing, technologies, approaches and their features depending on geological conditions of carbonate formations. The study also outlines the actual experience of using hydraulic fracturing technologies at carbonate formations, their comparative effectiveness, and the most successful practices based on the actual experience of the work performed. Much attention is paid to comparing the effectiveness of acid fracturing, acid-proppant fracturing, and variations of fracturing on viscous acid compositions. The findings not only give an idea of the technological diversity of the types of zonal stimulation, but also highlights their comparative effectiveness in geological and physical conditions of the reservoir. The reflected experience can help to choose more effective solutions in the development of similar formations, reduce risks at early stages of preparation for fracturing and helps in deciding on the choice of stimulation technology, thereby improving the quality and efficiency of fields development.

Simulation-Based Optimization Workflow of CO2-EOR for Hydraulic Fractured Wells in Wolfcamp A Formation

Hydraulic fracturing has enabled production from unconventional reservoirs in the U.S., but production rates often decline sharply, limiting recovery factors to under 10%. This study proposes an optimization workflow for the CO2 huff-n-puff process for multistage-fractured horizontal wells in the Wolfcamp A formation in the Delaware Basin. The potential for enhanced oil recovery and CO2 sequestration simultaneously was addressed using a coupled geomechanics–reservoir simulation. Geomechanical properties were derived from a 1D mechanical earth model and integrated into reservoir simulation to replicate hydraulic fracture geometries. The fracture model was validated using a robust production history matching. A fluid phase behavior analysis refined the equation of state, and 1D slim tube simulations determined a minimum miscibility pressure of 4300 psi for CO2 injection. After the primary production phase, various CO2 injection rates were tested from 1 to 25 MMSCFD/well, resulting in incremental oil recovery ranging from 6.3% to 69.3%. Different injection, soaking and production cycles were analyzed to determine the ideal operating condition. The optimal scenario improved cumulative oil recovery by 68.8% while keeping the highest CO2 storage efficiency. The simulation approach proposed by this study provides a comprehensive and systematic workflow for evaluating and optimizing CO2 huff-n-puff in hydraulically fractured wells, enhancing the recovery factor of unconventional reservoirs.

Geomechanical modeling aspects in support of hydraulic fracturing operations

This paper describes the main aspects and nuances of geomechanical modeling that must be considered when supporting hydraulic fracturing operations and providing engineering support of projects. A key feature of geomechanical modeling for hydraulic fractures aims or self-induced fracturing in mature fields is the estimation of reservoir pressure, particularly in the vicinity of production and injection wells. In addition, this has a significant impact on stress anisotropy, which is the primary factor affecting the geometry of the hydraulic fracture and the surrounding induced stress field. It is also crucial to monitor geomechanical core studies, ensure quality control of samples, and accurately process research results since the profiles of elastic-strength properties and stresses depend on these factors. This paper also addresses fracturing, including its measurement, calculations, and the prediction of its spatial orientation and intensity.

Study on Near-Wellbore Fracture Initiation and Propagation with Fixed-Plane Perforation in Horizontal Well for Unconventional Reservoirs

At present, in the process of volume fracturing for a tight reservoir, employing the spiral perforation method to induce the fracture propagation direction would always obtain an unsatisfactory effect, which causes the deflection and tortuosity of hydraulic fractures. Therefore, researchers presented the fixed-plane perforation method for enhancing the effect on volume fracturing. In this paper, the three-dimensional discrete lattice method is used to study the initiation and propagation law of horizontal well fixed-plane perforation in unconventional reservoirs under two different stress states. The results show that it is more suitable to use fixed-plane perforation for reducing the initiation pressure. When employing the fixed-plane perforation method, fracture always initiates in the perforation plane, presents as an irregular fan-shaped failure surface, and then propagates along the wellbore. The initiation pressure is highly correlated to the phasing angle between adjacent perforations under different conditions, and the rate of increase in the initiation pressure decreases by around 1.59~6.38% when the phasing angle reaches 30°. The fracturing pressure is inversely correlated with the diameter and tunnel length of the perforations and the horizontal stress difference. When the diameter increases to 17 mm, the tunnel length increases to 25 cm or the horizontal stress difference reaches 8 MPa. These results reveal an insignificant effect of the above parameters on the initiation pressure.

Multi-Task Learning Network-Based Prediction of Hydraulic Fracturing Effects in Horizontal Wells Within the Ordos Yanchang Formation Tight Reservoir

Accurate prediction of fracture volume and morphology in horizontal wells is essential for optimizing reservoir development. Traditional methods struggle to capture the intricate relationships between fracturing effects, geological variables, and operational factors, leading to reduced prediction accuracy. To address these limitations, this paper introduces a multi-task prediction model designed to forecast fracturing outcomes. The model is based on a comprehensive dataset derived from fracturing simulations within the Long 4 + 5 and Long 6 reservoirs, incorporating both operational and geological factors. Pearson correlation analysis was conducted to assess the relationships between these factors, ranking them according to their influence on fracturing performance. The results reveal that operational variables predominantly affect Stimulated Reservoir Volume (SRV), while geological variables exert a stronger influence on fracture morphology. Key operational parameters impacting fracturing performance include fracturing fluid volume, total fluid volume, pre-fluid volume, construction displacement, fracturing fluid viscosity, and sand ratio. Geological factors affecting fracture morphology include vertical stress, minimum horizontal principal stress, maximum horizontal principal stress, and layer thickness. A multi-task prediction model was developed using random forest (RF) and particle swarm optimization (PSO) methodologies. The model independently predicts SRV and fracture morphology, achieving an R2 value of 0.981 for fracture volume predictions, with an average error reduced to 1.644%. Additionally, the model’s fracture morphology classification accuracy reaches 93.36%, outperforming alternative models and demonstrating strong predictive capabilities. This model offers a valuable tool for improving the precision of fracturing effect predictions, making it a critical asset for reservoir development optimization.

Characterize the influences of hydraulic fracturing on preventing rock burst from the stress and vibration fields

The thick and hard roof (THR) is a significant factor that induces rock burst incidents. Traditional deep-hole blasting methods struggle to effectively relieve pressure for the high-level THR on a large scale. Although the horizontal staged hydraulic fracturing technology can crack high-level rock stratas, its impact on roof fracture still needs to be clarified, and there need to be more effective methods to evaluate its pressure relief effect. This paper conducted a comparative engineering test of local hydraulic fracturing pressure relief and load reduction on the working face to address this gap. The key layer theory and mine earthquake distribution were used to identify potential hazards of rock strata and the fracturing strata. Revealed the spatial and temporal evolution rules of microseisms induced by mining work, the failure mechanism of high-energy mine earthquakes, the evolution characteristics of source mechanical parameters, and the evolution characteristics of the stope stress field. The results indicate that after fracturing microseisms during mining presented exhibit a uniform distribution of high frequency and low energy. The fracture fragmentation of the roof rock was reduced, and the range of mining disturbance was minimized. High-energy mine earthquakes induced by mining are transferred to the goaf. Simultaneously, the corner frequency and stress decrease while the rupture radius and the shear component of the failure mechanism increase. The integrity of the THR is compromised, and fracture propagates and slips along the pre-crack. The roof of the working face experiences localized pressure, with decreased periodicity and intensity, reducing the overall static load level of the coal seam under the fracturing area. The research findings serve as a valuable reference for further investigations into the mechanism and risk assessment of hydraulic fracturing in preventing and controlling rock burst.

Methane Desorption-Diffusion Behaviors in Micropores of Coal under Different Water Displacement Pressures.

Hydraulic fracturing not only enhances the flow conductivity of coal seams but also transforms the CH4 adsorbed in coal seams into free CH4 and then outputs it via the desorption-diffusion process, thus improving the output quantity and efficiency of CH4. In this paper, taking the coal from Changping mine in Shanxi as the research object, the 3D macromolecule model of coal was established by using analytical test experiments, and the molecular dynamics simulation method of desorption and diffusion was applied to study the characteristics of methane desorption rate and diffusion behaviors under different driving water pressures through the parameters of gas-water concentration distribution, desorption and diffusion rates, and the interaction energies between the coal and the gas-liquid. The results show that the water drive can increase the desorption rate of methane. With the increase of methane adsorption pressure, the desorption effect of water drive becomes stronger and then weaker. The desorption effect of water drive was best when the methane adsorption pressure was 5 MPa and the pressure difference was 2 MPa. Generally, the water drive promoted the methane diffusion, but if the water drive time was too long, it formed a water plug, and the water drive methane inhibited the diffusion. In shallow reservoirs, water drive can obviously promote the desorption-diffusion of methane. The binding energy between CH4 molecules is mainly composed of the repulsive force, while that between water molecules is mainly the adsorption force. In the binding energy between CH4 molecules and coal structures, the van der Waals (VDW) force accounts for 99% of the effect; in the binding energy between water molecules and coal structures, the electrostatic force contributes 84% to ∼88% thereto. The VDW force is significantly influenced by the pressure, while the electrostatic force is slightly affected. As the water displacement differential pressure is increased, the binding energy between CH4 molecules and coal structures decreases.

Mechanical properties of shale during pyrolysis: Atomic force microscopy and nano-indentation study

Quantitative characterization of the geo-mechanical properties of shale and organic matter (OM) holds paramount significance in the assessment of shale gas reserves and the design of hydraulic fracturing. However, the mechanical evolution processes during shale hydrocarbon generation and its influencing factors have received limited attention. This study examines the changes in shale mechanical properties during pyrolysis at high temperatures (415–600 °C) and high pressure (50–125 MPa) for mature to over-mature stages. The nanoindentation and in-situ AFM-QNM analysis are utilized to characterize the changes in mechanical properties during evolution. Subsequently, gas adsorption, Fourier Transform infrared spectroscopy (FTIR), and laser Raman spectroscopy (Raman) are used to investigate the factors influencing the mechanical properties of shale and the associated OM, and establish a model for the evolution of the mechanical properties. The results demonstrate that with increasing maturity, the overall Young's modulus of the bulk shale gradually increases from 42.8 GPa to 58.4 GPa for the temperature increment from 415 °C to 600 °C. During the thermal maturation process, the mesopore structure and quartz content of the shale significantly influence its mechanical properties. Young's modulus of OM shows an S-shaped trend, with variations in the micromechanical properties of OM corresponding to stages of hydrocarbon generation. In particular, two peaks of Young's modulus increase are observed during the mature and over-mature stages. In the mature stage, the aromatization of the kerogen leads to substantial detachment of aliphatic side chains and oxygenated functional groups, resulting in a higher degree of aromatization. This reduces the kerogen spacing and consequently increases the Young's modulus. In the over-matured stage, the process of aromatics condensation leads to the orientation and arrangement of aromatic rings, reducing the number of key site vacancies and crystal defects, thereby forming large aromatic clusters and significantly increasing the graphite-like structure. This study will facilitate the analysis of shale matrix deformation mechanisms at the microscale, providing a fundamental theoretical and scientific basis for shale fracturing design, exploration, and development.

Measurement of Hydraulic Fracture Aperture by Electromagnetic Induction.

We present a new method for accurately measuring the aperture of a fluid-driven fracture. This method uses an eddy current probe located within a completion tool specifically designed to obtain the fracture aperture in the wellbore at the location where the fluid is injected into the fracture. The probe induces an eddy current in a target object, producing a magnetic field that affects the overall magnetic field. It does not have any limitations with respect to fluid pressure and temperature within a large range, making it unlike other methods. We demonstrate the accuracy and performance of the sensor under laboratory conditions. A hydraulic fracture experiment in a porous sandstone is conducted and discussed. The obtained measurement of the evolution of the fracture inlet aperture by the eddy current probe during the multiple injection cycles performed provided robust information. The residual fracture aperture (after the test) measured by the probe is in line with estimations from image processing of X-ray CT scan images as well as a thin-section analysis of sub-parts of the fractured specimen. The robustness and accuracy of this electromagnetic induction probe demonstrated herein under laboratory conditions indicate an interesting potential for field deployment.

Analysis of the Impact of Clusters on Productivity of Multi-Fracturing Horizontal Well in Shale Gas

Shale gas reservoirs with nanoporous media have become one of the primary resources for natural gas development. The nanopore diameters of shale reservoirs range from 5 to 200 nm, with permeability ranging from 1 × 10−9 to 1 × 10−6 μm2. The natural gas production from shale gas reservoirs is low, necessitating the use of multi-stage hydraulic fracturing in horizontal wells. Segmented multi-cluster perforation fracturing is an effective method for shale gas extraction in these wells. The number of clusters significantly impacts the productivity of horizontal wells. Therefore, it is essential to analyze the impact of cluster numbers on fracture productivity in shale gas reservoir development. In this study, the equivalent flow resistance method was applied to establish a productivity model for multi-stage hydraulic fracturing horizontal wells in shale gas reservoirs considering diffusion and slip. An approximate analytical solution was obtained, and the effects of cluster length, diffusion coefficient, and fracture network permeability on productivity were analyzed. The results show that gas production gradually increases with the increase in the number of clusters and cluster length. However, as the number of clusters increases, the interference between clusters leads to a decrease in the productivity of individual clusters. As the fracture permeability, fracture network permeability, and diffusion coefficient increase, shale gas production also gradually increases. The permeability of the fracture network has the greatest impact on productivity. These research results are beneficial for the design of clusters in horizontal well fracturing and are of great importance for the development and production of shale gas reservoirs.

Prediction of shale bedding-parallel crack density based on the SH-SH wave inversion of the VTI media

Bedding-parallel cracks relate to hydrocarbon accumulation and can be beneficial for hydraulic fracturing. The prediction of bedding-parallel crack density (BCD) from seismic data is difficult because the development of bedding-parallel cracks has limited effects on the velocities and density of subsurface formation. Well logs of the Qingshankou (K2qn) shales in the Songliao Basin, northeast China, reveal that the target formations represent extremely strong seismic anisotropy (> 40%), and the magnitude of S-wave anisotropy highly relates to the density of bedding-parallel cracks (up to 2500 m−1). We present a novel BCD prediction method using the reflected seismic shear wave. The S-wave anisotropy parameter γ is first inverted from the SH-SH wave by using a stepwise inversion method based on a new shear wave reflection coefficient approximation. Furthermore, the highly correlated rock-physics relationship between BCD and the anisotropy parameter γ facilitates accurate BCD estimation. Field data application on a real seismic shear wave data set acquired from the study area demonstrates the viability of the proposed method. The investigation provides a useful tool for the characterization of ‘sweet-spots’ of shale-oil reservoir formation.

Применение новых технологий кислотной обработки пластов для восстановления продуктивности пласта

Oil recovery, measured by the oil recovery factor (ORF), is a key indicator of the efficiency of oil production. In Russia, the ORF decreased to 0.3 while in the United States this indicator increased to 0.4. About 90% of Russian oil is produced by large holdings, the structure of reserves is shifting towards hard-to-recover, which requires the use of new methods to increase oil recovery. Primary and secondary production allows only 20-50% of oil to be extracted, what makes the use of tertiary methods necessary. The development of horizontal wells with multistage hydraulic fracturing contributes to the development of new field sites, but requires careful preparation of wells to minimize risks and cost increases. Cleaning the bottomhole area using acidic formulations is often the only cost-effective way to restore the productivity of a horizontal well. The improved method of acid composition reduction using a guar gel with delayed “crosslinking”, which ensures uniform treatment of all productive zones of the formation is considered in article. The technology allows for continuous multi-stage acid treatment, temporarily blocking highly permeable areas and increasing the coverage of acidic effects on poorly drained areas. The calculation of the diverter volume considers the average efficiency of the liquid after mini-fracturing, adjusting the volume depending on the efficiency of the liquid at each port.

Developmental characteristics of vertical natural fracture in low-permeability oil sandstones and its influence on hydraulic fracture propagation

Vertical natural fractures (NFs) are prevalent in low-permeability sandstone reservoirs. Presently, the impact of NFs on the extension of hydraulic fractures (HFs) remains partially unveiled, which restricts the scientific development of strategies for low-permeability, fractured oil sandstones. In this study, taking the oil sandstone of the He-3 Member, Hetaoyuan Formation, southeastern Biyang Depression as an example, we conducted a comprehensive investigation into the factors influencing vertical fracture development and the interaction between natural and hydraulic fractures. The cohesive unit simulations indicate that geostress is the principal factor influencing HF expansion, more so than NFs, with this influence intensifying as natural fracture density increases. As natural fracture density grows, the potential for two sets of conjugate natural fractures to form short HFs arises, which are limited in expansion scope, suggesting a need to reduce well spacing accordingly. Conversely, areas with a single set of NFs are more prone to developing longer HFs, warranting an increase in well spacing to avoid water channeling. High natural fracture densities may constrain the effectiveness of HFs. In fractured reservoirs with a 10 MPa horizontal stress difference, the length of HFs is 1.52 times that of HFs with 0 MPa and 5 MPa differences. However, the hydraulic fracture effectiveness index (FE) of the latter is 1.74 times higher than the former. For fractured reservoirs, the expansion capacity of HF length within a 5 MPa horizontal stress difference remains relatively stable; beyond this threshold, the expansion capacity increases with the growing horizontal stress difference, and the fracturing effect eventually deteriorates. Furthermore, as the strength of NFs escalates, the length and modified area of HFs initially decrease significantly before stabilizing. The complexity and FE value of HFs formed under strong natural fracture conditions are heightened, indicating a more effective fracturing outcome.

Enhancing Fracturing Proppant Performance: Methods and Assessment

AbstractThe use of fracturing proppants is a key element of hydraulic fracturing operations in the oil and gas industry. The selection of proppants with superior performance is critical to ensure efficient and effective hydraulic fracturing. Proppant technologies are developing rapidly. Therefore, standardization of proppant evaluation is necessary to ensure accurate proppant evaluation during proppant production. Although the API and ISO have released a number of recommended practices for this purpose, there are still significant gaps in them. This is because several hypotheses regarding proppant performance, including proppant embedment and diagenesis, and their influence on proppant conductivity, are still not fully clear. Numerous proppants have been produced within the petroleum industry, featuring diverse compositions, sizes, shapes, and intended uses. While many proppants consist of silica or ceramics, there is growing interest in advanced types such as ultra-lightweight proppants. These innovations aim to minimize settling and enable transport using low-viscosity fluids. Moreover, to reduce expenditures, it is common practice in hybrid completions to mix proppant of different sizes according to stimulation design objectives and assumptions. Proppant can be equally mixed, separated by tail-in, or mixed with dominating concentrations of a specific size, depending on the type of fluids, viscosity, and anticipated settlement velocity. Surface modification involves altering the surface properties of the proppant to improve its adhesion to the fracture face and to reduce embedment and fines generation. Surface modification techniques include silane treatment, plasma treatment, and chemical treatment. The method can maintain oil flow channels after the hydraulic fracturing operation for a very long time. Proppant flowback, fines generation, and gel degradation are the key factors that contribute to a proppant pack losing permeability. Proppant pack conductivity can be increased, and well cleanup can be hastened, with the aid of a surface modification. This review paper aims to provide a comprehensive overview of proppant and its types, proppant performance assessment, and methods to enhance proppant performance. We discuss various techniques to evaluate proppant performance, including crush resistance, conductivity, embedment, and closure stress. Additionally, we highlight the importance of selecting the most appropriate proppant type for a particular well based on the formation properties and proppant characteristics. Furthermore, we explore recent advancements in proppant enhancement methods, such as coating, sintering, altering proppant surface, and consolidation, and their effectiveness in improving proppant performance. The comprehensive review provides insight into current industry practices and highlights potential areas for future research to improve fracturing proppant performance.

Unconventional Fracture Networks Simulation and Shale Gas Production Prediction by Integration of Petrophysics, Geomechanics and Fracture Characterization

The proficient application of multistage fracturing methods enhances the status of the Duvernay shale formation as a highly esteemed shale reservoir on a global scale. Nevertheless, the challenge is in accurately characterizing unconventional fracture behavior and predicting shale productivity due to the complex distributions of natural fractures, pre-existing faults, and reservoir heterogeneity. The present study puts forth a Geo-Engineering approach to comprehensively investigate the Duvernay shale reservoir in the vicinity of Crooked Lake. To begin with, on the basis of the experimental results and well-logging interpretations, a high-quality petrophysical and geomechanical model is constructed. Subsequently, the establishment of an unconventional fracture model (UFM) takes into account the heterogeneity of the reservoir and the interactions between hydraulic fractures and pre-existing natural fractures/faults and is further validated by 18,040 microseismic events. Finally, the analysis of well productivity is conducted by numerical simulations, revealing that the agreement between the simulated and observed production magnitudes exceeds 89%. This paper will guide the efficient development of increasingly important unconventional shale resources.

Numerical Simulation of Hydraulic Fracture Propagation in Unconsolidated Sandstone Reservoirs

In order to comprehensively understand the complex fracture mechanisms in thick and loose sandstone formations, we have carefully developed a coupled finite element numerical model that captures the complex interactions between fluid flow and solid deformation. This model is the cornerstone of our future exploration. Based on this model, the crack propagation problem of hydraulic fracturing under different engineering and geological conditions was studied. In addition, we conducted in-depth research on the key factors that shape the geometry of hydraulic fractures, revealing their subtle differences and complexities. It is worth noting that the sharp contrast between the stress profile and mechanical properties between the production layer and the boundary layer often leads to fascinating phenomena, such as the vertical merging of hydraulic fracture propagation. The convergence of cracks originating from adjacent layers is a recurring theme in these strata. Sensitivity analysis clarified our understanding, revealing that increased elastic modulus promotes longer crack propagation paths. As the elastic modulus increases from 12 GPa to 18 GPa, overall, the maximum crack width slightly decreases, with a less than 10% reduction rate. The increased fluid leakage rate will significantly shorten the length and width of hydraulic fractures (with a maximum decrease of over 70% in fracture width). The increase in viscosity of fracturing fluid causes a change in fracture morphology, with a reduction in length of about 32% and an increase in fracture width of about 25%. It is worth noting that as the leakage rate of fracturing fluid increases, the importance of the viscosity of fracturing fluid decreases relatively. Strategies such as increasing fluid viscosity or adding anti-filtration agents can alleviate these challenges and improve the efficiency of fracturing fluids. In summary, our research findings provide valuable insights that can provide information and optimization for hydraulic fracturing filling and fracturing strategies in loose sandstone formations, promoting more efficient and influential oil and gas extraction work.

Geological and Engineering Integration Fracturing Design and Optimization Study of Liushagang Formation in Weixinan Sag

The Weixinan Sag in the Beibuwan Basin is rich in shale oil resources. However, the reservoirs exhibit rapid phase changes, strong compartmentalization, thin individual layers, and high-frequency vertical variations in the thin interbedded sandstone and mudstone. These factors can restrict the height of hydraulic fracture propagation. Additionally, the low-porosity and low-permeability shale oil reservoirs face challenges such as low production rates and rapid decline. To address these issues, the Plannar3D full 3D fracturing model was used to simulate hydraulic fracture propagation and to study the main controlling factors for fracture propagation in the second member of the Liushagang Formation. Based on the concept of geological–engineering integration, a sweet spot evaluation was conducted to identify reservoirs with relatively better brittleness, reservoir properties, and oil content as the fracturing targets for horizontal wells. The UFM model was then applied to optimize fracturing parameters. This study indicates that the matrix-type oil shale has a high clay mineral content, resulting in a low Young’s modulus and poor brittleness. This makes hydraulic fracture propagation difficult and leads to less effective reservoir stimulation. In contrast, hydraulic fractures propagate more easily in high-brittleness interlayer-type oil shale. Therefore, it is recommended to prioritize the extraction of shale oil from interlayer-type oil shale reservoirs. The difference in interlayer stress is identified as the primary controlling factor for cross-layer fracture propagation in the study area. Based on the concept of geological–engineering integration, a sweet spot evaluation standard was established for the second member of the Liushagang Formation, considering both reservoir quality and engineering quality. Four sweet spot zones of interlayer-type oil shale reservoirs were identified according to this evaluation standard. To achieve uniform fracture initiation, a differentiated segment and cluster design was implemented for certain high-angle sections of well WZ11-6-5d. Interlayer-type oil shale was selected as the fracturing target, and the UFM was used for hydraulic fracture propagation simulation. Fracturing parameters were optimized with a focus on hydraulic fracture characteristics and the estimated ultimate recovery (EUR). The optimization results were as follows: a single-stage length of 50 m, cluster spacing of 15 m, pump injection rate of 10 m3/min, fluid intensity of 25 m3/m, and proppant intensity of 3.5 t/m. The application of these optimized fracturing parameters in field operations resulted in successful fracturing and the achievement of industrial oil flow.

Organic geochemical characterization and hydrocarbon generation modeling of Paleozoic-Paleogene shales, Wadi Sirhan basin, south-eastern Jordan

The Wadi Sirhan Basin in Jordan originated from the Arabian Platform and served as a stable shelf during the Paleozoic era. The Lower Paleozoic-Eocene sequence in the Wadi Sirhan Basin contains numerous shales, found, in ascending order the Upper Ordovician Dubeidib, Lower Silurian Mudawwara, Maastrichtian Ghareb, Paleocene Taqiyeh, and Eocene Sara fms. These strata warrant investigation of their source-rock potential and hydrocarbon generation modeling, to precisely elucidate the timing of petroleum generation. To achieve this, datasets were utilized from various analytical approaches, including Rock-Eval pyrolysis, visual kerogen analysis, pyrolysis-GC, and lipid biomarker geochemistry. The aim of this study is to assess these source rocks regarding organic matter quantity and quality, paleoenvironmental implications, thermal maturity, and petroleum generation depth/time. The Lower Paleozoic Dubeidib and Mudawwara shales are identified as effective source rocks, containing kerogen types II, II-III, and III. A high proportion of well-preserved, weakly fluorescent amorphous organic matter suggests an origin from marine plankton-derived alginite in an oxygen-deficient setting. These formations reached the peak oil window during the Devonian (∼405-380 Ma) and Carboniferous (∼320-300 Ma). The Dubeidib Fm experienced late-stage oil generation during the Early Triassic (∼255-250 Ma), with a transformation ratio (TR) of 68%. The Ghareb Fm predominantly contains type II kerogen, while the Taqiyeh and Sara fms mainly contain type I kerogen with minor type II kerogen. Thermal maturity assessments using integrated parameters indicate that the Dubeidib and Mudawwara shales have entered the main phase of hydrocarbon generation, while the Ghareb, Taqiyeh, and Sara shales remain immature. Furthermore, analysis of biomarker ratios reveals the dominance of marine over terrestrial organic matter in the studied strata. These clay-rich sediments were deposited under reducing conditions, which further facilitated the rearrangement of steranes into diasteranes. The modeled TRs indicate the generation and subsequent expulsion of hydrocarbons, but the absence of suitable reservoirs and/or improper trapping system, owing to the major Hercynian unconformity, led to an incomplete petroleum system in the basin. Additional investigation is required to evaluate the potential of the Early Paleozoic shales as subsurface unconventional resources, considering parameters such as brittleness index and hydraulic fracturing. This study holds important implications for future hydrocarbon exploration and development in the Wadi Sirhan Basin. The insights gained from such investigations could help mitigate the risk of petroleum exploration failures in the Wadi Sirhan Basin, guiding future exploration and development efforts towards promising approaches.

Shallow Reverse Moderate Earthquakes in the Weiyuan Shale Gas Field, Sichuan Basin, China, Related to Hydraulic Fracturing

Abstract The Weiyuan shale gas field in the stable southern Sichuan basin, China, has experienced increasing seismicity since systematic hydraulic fracturing (HF) operations in 2015. Three Mw≥4.4 shallow earthquakes occurred in the Weiyuan area between September 2019 and February 2020, yet their seismogenic faults, rupture models, and relationship with HF are unknown. In this study, we first obtain the high-resolution coseismic deformation fields of these three events and then invert their slip distribution. The result shows that all three events are shallow high-dip reverse events under the contractional Weiyuan anticline environment with peak slips of 158, 68, and 34 cm and at depths of 4, 3, and 1.6 km, respectively. The spatial relationship between seismogenic faults, horizontal wells, as well as geological data reveals that pore-pressure diffusion due to the HF may be the main mechanism of the 8 September 2019 and the 18 December 2019 events, whereas the 16 February 2020 event may be attributed to the poroelastic stress perturbation caused by the HF. Our study highlights that HF activities and regional geological characteristics jointly influence the properties of earthquakes in the Sichuan basin.

Multi-scale model for evaluating stress fluctuation in shale gas reservoirs considering geomechanical heterogeneity

In this article, a numerical model considering multi-scale flow and heterogeneity of shale reservoirs is developed to analyze the spatiotemporal evolution of the stress field in shale gas production. After considering the geomechanical heterogeneity, the variation in the local rock mechanical parameters of the reservoir, and the increase in the effective stress of the reservoir will cause local stress fluctuations. In the hydraulic fracture control area, the average stress fluctuation coefficient is higher, indicating a stronger “stress heterogeneity.” When the homogeneity increases from 5 to 100, the fluctuation range of the minimum horizontal principal stress increases by 28.89 MPa, and the fluctuation range of the principal stress difference increases by 7.35 MPa. The presence of natural fractures can significantly impact the coupled hydraulic-mechanical processes of the reservoir, increasing the number of high-speed permeation channels penetrating the system. The greater the density and permeability, the smaller the minimum horizontal principal stress and the larger the principal stress difference. The angle of natural fractures directly influences the direction of stress drop, with an average minimum horizontal principal stress occurring when the angle of natural fractures is at 60°/120°.