页岩油气开采方式

Fault slips induced by hydraulic fracturing are the primary mechanism of casing de-formation during deep shale gas development in Sichuan’s Luzhou Block, where de-formation rates reach 51% and severely compromise productivity. To address a critical gap in existing research on quantitative risk assessment systems, we developed a probabilistic model integrating pore pressure evolution dynamics with Monte Carlo simulations to quantify slip risks. The model incorporates key operational parameters (pumping pressure, rate, and duration) and geological factors (fault friction coefficient, strike/dip angles, and horizontal stress difference) validated through field data, showing >90% slip probability in 60% of deformed well intervals. The results demonstrate that prolonged high-intensity fracturing increases slip probability by 32% under 80–100 MPa pressure surges. Meanwhile, an increase in the friction coefficient from 0.40 to 0.80 reduces slip probability by 6.4% through elevated critical pore pressure. Fault geometry exhibits coupling effects: the risk of low-dip faults reaches its peak when strike parallels the maximum horizontal stress, whereas high-dip faults show a bimodal high-risk distribution at strike angles of 60–120°; here, the horizontal stress difference is directly proportional to the slip probability. We propose optimizing fracturing parameters, controlling operation duration, and avoiding high-risk fault geometries as mitigation strategies, providing a scientific foundation for enhancing the safety and efficiency of shale gas development.

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Accurate estimation of the brittleness index (BI) is critical for optimizing hydraulic fracturing operations in shale gas reservoirs, as it directly influences fracture propagation and gas recovery efficiency. The BI quantifies the resistance of rock to fracturing, a key factor in determining the optimal depth for fracture stimulation. Prior methods of estimating BI, such as empirical correlations and other utilized machine learning (ML) techniques, often suffer from limited accuracy and generalizability, particularly in complex geological formations like the Fuling shale gas field. To address these limitations, ML techniques have gained prominence due to their ability to capture complex, nonlinear relationships within large data sets, improving predictive accuracy. In this study, we propose a novel approach that utilizes a hybrid group method of data handling based on discrete differential evolution (GMDH-DDE) to predict the BI. The GMDH-DDE model was compared with the group method of data handling (GMDH), random forest (RF), and multilayer perceptron (MLP). The results demonstrate that GMDH-DDE significantly outperforms these models, achieving a coefficient of determination (R2) of 0.9984, a root mean square error (RMSE) of 0.2895, and a mean absolute error (MAE) of 0.02543 to unseen data. The GMDH model ranked second in BI estimation, achieving an R2 of 0.9805, RMSE of 0.4635, and MAE of 0.04224. It was followed by the RF model, with an R2 of 0.9599, RMSE of 0.6034, and MAE of 0.0997. The MLP model, however, had the lowest performance, with an R2 of 0.9263, RMSE of 0.9566, and MAE of 0.1256. Additionally, the GMDH-DDE model demonstrates superior computational efficiency, requiring only 1.12 seconds. This is a significant advantage over other methods, with GMDH taking 4.82 seconds, RF requiring 11.23 seconds, and MLP taking 27.45 seconds. These findings highlight the potential of GMDH-DDE in providing accurate and computationally efficient BI estimations. The improved accuracy and efficiency of BI estimation by GMDH-DDE are expected to contribute to more effective and cost-efficient hydraulic fracturing operations, ultimately enhancing the economic viability of shale gas reservoirs.

Shale gas hydraulic fracturing usually activates nearby faults and makes them slip. In horizontal wells, fault slip can result in serious casing deformation. Casing deformation slows the fracturing process, lowers production, and raises the cost of a shale gas well. It is challenging to obtain underground data on fault activation because of the deep shale reservoirs. As a result, the current study needed to indicate how hydraulic fracturing affects fault activation length. This made it challenging to control casing deformation. The fluid-structure coupled finite element method was used in this study to create a coupled seepage-stress model for heterogeneous shale formation. With microseismic signs and hydraulic fracking for shale gas, this model examined the variation law of pore pressure and ground stress. The fault activation coefficient was created to assess the fault activation duration and the impact of hydraulic fracturing. The model was verified by the microseismic signal. The outcomes of the numerical simulation demonstrate how the rapid rise in formation pore pressure during hydraulic fracturing affected the ground stress at the fault interface. The influence of ground stress variation at the fault interface on fault activation could not be ignored. Increased fault elastic modulus, fracture pressure, fracture time, and the fault Poisson ratio result in longer fault activation lengths. The length of the fault’s activation was decreased by the increase in fracture stage, distance from the fault, friction angle within the fault, and fault angle. Finally, a shale gas horizontal well with casing deformation in block C was analyzed. The results showed that reducing the fracturing duration can reduce the activation length of the fault by 68.25%, resulting in a 9.1 mm fault slide and a 0.86 mm casing deformation, respectively. This study offers theoretical guidelines for preventing fault activation during hydraulic fracturing in horizontal shale gas wells.

Characterizing seismic responses to hydraulic fracturing (HF) in shale‐gas development is crucial for seismic‐hazard assessment and mitigation‐strategy design. Although intensive HF operations have led to severe induced seismic hazards in the Changning shale gas field (CSF) in China for over a decade, the typical spatiotemporal characteristics of induced seismicity during and after HF in this region remain unclear, due to a lack of detailed fluid‐injection data. Using a 70‐day‐long dense deployment of 336 nodal‐sensors in 2019, we develop an enhanced seismicity catalog and combine it with focal mechanism solutions, fluid‐injection time series, seismic‐reflection profiles, and geomechanical models to identify the distinct shallow and deep seismicity responses to HF. The first pattern consists of deep earthquake clusters that migrate along strike‐slip faults in the limestone formation ∼1 km below the treatment depth. These clusters contain frequent ML>2 ${M}_{\mathrm{L}} > 2$ earthquakes, including the largest ML3.3 ${M}_{\mathrm{L}}3.3$ event, and exhibit transient seismicity‐rate changes in rapid response to HF. In contrast, the second pattern consists of shallow clusters in the target shale formation that persist for over a year following HF. The shallow clusters include smaller earthquakes and exhibit thrust‐style faulting with no discernible spatial migration. Our geomechanical simulations suggest the deep fault reactivation is best explained by the combined effects of poroelastic‐stress loading and pore‐pressure increases. Stable seismicity rate and frequent casing deformation indicate post‐HF, long‐term aseismic deformation may drive the shallow seismicity. These distinct seismic responses during and after HF operations underscore the need for a spatiotemporally adaptive hazard mitigation strategy for the CSF.

During the hydraulic fracturing process, high speed fluid which contained solid particles would result in erosion between the fluid and the inner surface of the tubing or casing would cause great threat to the service safety of the downhole-tubular string. In this paper, the erosion experiment of the Q125HC casing steel were carried out in different carrying fluid velocity, erosion angle and sand content. The results showed that within the erosion angle of 0-90°, the erosion rate first increased, continuously come up to a "peak value", and then let up while the impact angle is increased, and also carrying fluid velocity has big impact on the erosion rate of the Q125HC casing steel.

Fault slip is the primary cause of casing deformation during the hydraulic fracturing process of shale gas horizontal wells. This paper investigates the mechanism of fault slip and its correlation with the integrity of the cement sheath. By establishing a numerical model of the casing-cement sheath-reservoir rock system, the effects of fracturing fluid pressure and temperature, mechanical parameters of the cement sheath, and the wall thickness of the casing and cement sheath on the integrity of the cement sheath were calculated. The results indicate that low-temperature fracturing fluids lead to changes in the stress state at the casing-cement sheath interface and the reservoir rock-cement sheath interface, with failure at the casing-cement sheath interface occurring approximately 600s after exposure. Increasing the temperature of the fracturing fluid, selecting a cement sheath with a lower elastic modulus and higher Poisson's ratio, and increasing the casing wall thickness can effectively enhance the integrity of the casing-cement sheath-reservoir rock system and prevent fault slip induced by fracturing fluids.

A hydraulic fracturing model of shale gas reservoirs at deep HPHT conditions was adapted and built using innovative computer modeling. The model is based on equations representing the effect of HPHT reservoir conditions on shale geo-mechanical properties and pressure losses in the tubing string for fracture network distribution. It is designed for tubing geometry, slurry properties, formation geo-mechanical properties under HPHT conditions and also for intensity of shale gas networks. Comparison to other models showed that when pressure losses equations for long tubing reaching deep reservoirs and effect of HPHT are taken into account, more accurate values for slurry pumped and future gas production are estimated from shale gas and less damage to surrounding formation is obtained. Effect of each factor on model results was discussed in detail.

The increasing burial depth of deep shale formations in the southern Sichuan leads to more complex in situ stresses and geological structures, which in turn raises the challenges of hydraulic fracturing. Although enlarging the treatment scale and injection rate can enhance reservoir stimulation, the intensive development of faults and fractures in deep shale formations aggravates stress instability, inducing casing deformation, fracture communication, and other engineering risks that constrain efficient shale gas production. In this study, a cross-scale geomechanical model linking the regional to near-wellbore domains was constructed. A dynamic evolution equation was established based on flow–stress coupling, and a numerical conversion from the geological model to the finite element model was implemented through self-programming, thereby developing a simulation method for dynamic geomechanical evolution during hydraulic fracturing. Results indicate that dynamic variations in pore pressure dominate stress redistribution, while near-wellbore heterogeneity and mechanical property distribution significantly affect prediction accuracy. The injection of fracturing fluid generates a high-pressure gradient that drives pore pressure diffusion along fracture networks and faults, exhibiting a strong near-wellbore but weak far-field non-steady spatial attenuation. As the pore pressure increases, the peak value reaches 1.4 times the original pressure. The triaxial stress shows a negative correlation and decreases. The horizontal minimum principal stress shows the most significant drop, with a reduction of 15.79% to 20.68%, while the vertical stress changes the least, with a reduction of 5.7% to 7.14%. Compared with the initial stress state, the horizontal stress difference increases during fracturing. Rapid pore-pressure surges and fault distributions further trigger stress reorientation, with the magnitude of rotation positively correlated with the intensity of pore-pressure variation. The high porosity and permeability characteristics of the initial fracture network lead to a rapid attenuation of the stress around the wellbore. In the middle and later stages, as the pressure balance is achieved through fracture filling, the pore pressure rises and the stress decline tends to stabilize. The findings provide significant insights into the dynamic stress evolution of deep shale reservoirs during fracturing and offer theoretical support for optimizing fracturing design and mitigating engineering risks.

When the shear stress borne by the molecular chains of drag reducing agent polymers increases to a force sufficient for breaking, the viscosity will reduce and impact the drag reduction rate and sand-carrying performance, directly determining the success or failure of execution of hydraulic fracturing and impacting the effective after hydraulic fracturing, aiming at the problem of poor shear stability of ordinary synthetic polymers, in order to change the molecular structure to obtain polymers with stronger shear resistance. By developing a method for synthesizing a star-shaped polymer, this study determined the core functional groups within dendritic polymer initiators and a synthesis method for initiating the polymerization of monomers, such as acrylamide. In addition, we completed the synthesis of a dendritic polymer initiator and a star-shaped polymer with an optimized initiator type and concentration and determined that PAMAM-TX (polyamidoamine-thioxanthone) as the initiator had a concentration of 0.09% with a monomer concentration of 20%, of which the AMPS (2-Acrylamido-2-methylpropane sulfonic acid) monomer was 3–5 mol. % and the concentration of the hydrophobic monomer DM-12 (methacry loyloxyethyldimethyldodecyl ammonium bromide) was 0.3–0.5 mol. %. For performance evaluation and field testing, the drag-reducing rate of star-shaped polymer is higher than 70%.

We present a case study using a full-section fiber-optic DAS array to monitor microseismicity during hydraulic fracturing and provide valuable insights into subsurface stress variations. Leveraging DAS data's high spatial resolution and migration-based techniques, we identified 163 microearthquakes, 46 of which were selected for moment tensor and stress inversion analysis. Independent inversions explain the source mechanisms of events in Fracturing stage 8, showing consistency with in-situ stress measurements and alignment with the regional stress field, as validated by the World Stress Map and the pilot hole. Seismic events were categorized into three swarms based on their focal mechanism characteristics: Swarm 1 exhibited significant stress anomalies, likely driven by rapid fluid-induced fracturing which alter local stress conditions. In contrast, Swarms 2 and 3 showed stress alignments with regional trends, indicating shear failure along pre-existing faults. We also employed focal mechanism tomography (FMT) to estimate pore fluid pressure thresholds for each swarm. Swarm 2 exhibited the lowest excess pore pressure (1.24 MPa), suggesting that high fluid pressure is prone to enhance the fracturing of pre-existing faults and induce earthquakes. Our findings provide new insights into the role of hydraulic fracturing in induced seismicity, demonstrating that stress anomalies arise from complex fracture geometries and dynamic pore pressure variations. This study highlights the potential of integrating DAS monitoring with stress inversion and FMT to advance our understanding of shale reservoir geomechanics and induced seismicity.

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The process of extracting shale gas, particularly the study of the utilization law of shale reservoirs modified by hydraulic fracturing technology, is crucial for understanding the effective development of shale gas. This understanding can significantly influence the estimated ultimate recovery of reserves. Our study focused on Longmaxi Formation shale in the Changning–Weiyuan block. To investigate the hydraulic fracturing expansion mechanism and utilization law, we employed shale reservoir physical and mechanical characterization, indoor triaxial hydraulic fracturing experiments, and numerical simulations. The findings are as follows. The rupture pressure of hydraulic fractures increases with the peripheral pressure, and high stress is conducive to the formation of internal microfractures. Additionally, a high rate of water injection enhances fracture extensions along the direction of fluid injection. Under varying injection pressures, the length of crack extensions and number of bond damages in shale are positively correlated with the injection pressure. Conversely, under different differential ground stresses, the length of crack extensions and number of bond damages are negatively correlated with the injection pressure. The six main factors affecting the effective utilization of shale gas are as follows: the stimulated reservoir volume, number of hydraulic fracture clusters, fracture length, fracture height, number of fracture stages, and cluster spacing, accounting for 27.13%, 14.74%, 10.31%, 9.58%, 9.53%, and 9.29%, respectively, with a cumulative contribution rate of 80.58%. This study clarifies the hydraulic fracturing mechanisms of shale reservoirs and the laws governing shale gas production, providing technical support for the development of shale gas reservoirs.

The global shale gas resources are huge and have good development prospects, but shale is mainly composed of nanoscale pores, which have the characteristics of low porosity and low permeability. Horizontal drilling and volume fracturing techniques have become the effective means for developing the shale reservoirs. However, a large amount of mining data indicate that the fracturing fluid trapped in the reservoir will inevitably cause hydration interaction between water and rock. On the one hand, the intrusion of fracturing fluid into the formation causes cracks to expand, which is conducive to the formation of complex fracture networks; on the other hand, the intrusion of fracturing fluid into the formation causes the volume expansion of clay minerals, resulting in liquid-phase trap damage. At present, the determination of well closure time is mainly based on experience without theoretical guidance. Therefore, how to effectively play the positive role of shale hydration while minimizing its negative effects is the key to optimizing the well closure time after fracturing. This paper first analyzes the shale pore characteristics of organic pores, clay pores, and brittle mineral pores, and the multi-pore self-absorption model of shale is established. Then, combined with the distribution characteristics of shale hydraulic fracturing fluid in the reservoir, the calculation model of backflow rate and shut-in time is established. Finally, the model is validated and applied with an experiment and example well. The research results show that the self-imbibition rate increases with the increase in self-imbibition time, and the flowback rate decreases with the increase in self-imbibition time. The self-imbibition of slick water is the maximum, the self-imbibition of breaking fluid is the minimum, and the self-imbibition of mixed fluid is the middle, and the backflow rates of these three liquids are in reverse order. It is recommended the shut-in time of Longmaxi Formation shale is 17 days according to the hydration and infiltration model.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 4043054, “Casing-Deformation-Risk Prediction With Numerical Simulation During Hydraulic Fracturing in Deep Shale Gas Reservoirs,” by Jianfa Wu, Xuewen Shi, and Qiyong Gou, PetroChina, et al. The paper has not been peer reviewed. In this study, a numerical simulation workflow was established based on comprehensive modeling of a time-lapse stress field, hydraulic fracturing simulation, natural fractures, and other weak interfaces to analyze casing-deformation mechanisms of shale gas horizontal wells during the multistage hydraulic fracturing process. The authors write that they aim to guide the prediction of, and provide mitigating solutions for, casing-deformation risks while improving stimulation efficiency. The burial depth of deep shale gas reservoirs in the southern Sichuan Basin is approximately 3500 to 4500 m. These have complex geological conditions with developed faults and fractures and high in-situ horizontal stresses. During multistage hydraulic fracturing operations in horizontal wells, establishing an effective prediction method for casing-deformation risks in these reservoirs is a challenge. An integrated workflow is proposed to evaluate and predict casing-deformation risks, effectively support hydraulic fracturing operations, and reduce and mitigate casing failure in these reservoirs. It is essential to consider the effects of multiscale natural fractures when constructing a 3D stress model. Natural-fracture stability can be evaluated and used to identify unstable fractures that may cause casing failures. The fundamental workflow of predicting and preventing the casing failure is as follows: 1. Build a 3D geological model characterizing the spatial distribution and geometry of faults and natural fractures 2. Construct a 3D stress model to characterize the in-situ stress state 3. Perform numerical simulations of hydraulic fracturing and 4D coupled stress simulation to obtain the stress field during and after hydraulic fracturing 4. Quantitatively analyze the shear slip risks of natural fractures by calculating slip tolerance as an indicator to determine risk levels of casing deformation 5. Optimize and adjust engineering parameters for hydraulic fracturing to reduce and mitigate casing deformation Natural-Fracture Distribution and Model Construction. In this study, natural fractures parameters such as density, strike, inclination, length of extension, and height were obtained. The natural fractures were calibrated and verified with cores and wellbore images. Natural-fracture distribution was then validated with the expected tectonic history and present-day stress regime. In Fig. 1, the left-hand plot depicts the ant-tracking results by seismic attribute, the central plot portrays natural fractures validated by microseismic events, and the right-hand plot illustrates the 3D natural-fracture model. Results showed two major fracture strikes, one in the northeast and the other in the northwest, forming a mesh network distribution that will be used in the stress model, fracturing simulation, and slip analysis.

Microseismic monitoring is an important technique that can be used to identify fractures in rock mass. The aim of this article is to identify, on the basis of the location of microseismic events, structures formed by hydraulic fracturing in the Wysin-2H/2Hbis horizontal well from the Baltic Basin in northern Poland, and to compare the patterns of these structures with the direction of regional stresses. The authors proposed a novel multi-step workflow for finding these structures. To be able to delineate the structures from microseismic events with greater accuracy, a collapsing algorithm was used. Then, based on the Hierarchical Density-Based Spatial Clustering of Applications with Noise (HDBSCAN) clustering algorithm and the elongation coefficient of each cluster, probable fissures were identified and compared against the maximum horizontal stress direction. In addition, based on the 3D seismic data from the Wysin and the calculated geomechanical parameters in the monitoring well, the probability classes of brittleness indices in the LMR (λρ-μρ) parameter domain were determined. A comparative analysis was performed between the two variants of microseismic event location (before and after the collapsing procedure) and the estimated probability of a given class of brittleness index. The comparison of the event location with the 3D seismic data was used to validate the results before and after collapsing due to the high resolution of the seismic method. It is shown that the collapsed events appeared in more rigid regions, where more energy release is expected.

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The rapid expansion of shale gas extraction worldwide has raised significant concerns about its impact on water resources. China is expected to undergo a shale revolution following the U.S. Most of the information on water footprint of shale gas exploration and hydraulic fracturing has been focused on the U.S. Here, we addressed this knowledge gap by establishing a comprehensive database of shale gas extraction in China, utilizing operational data from over 90 % of shale gas wells across the country. We present systematic analysis of water usage and flowback and produced water (FP water) production from all the major shale gas fields in China. Between 2012 and 2022, a total of 2740 shale gas wells were hydraulically fractured in China, primarily located in Sichuan and Chongqing Province. About 113 million m3 water was used for hydraulic fracturing, resulting in a cumulative shale gas production of 116 billion m3. As of 2022, the annual water use for hydraulic fracturing exceeded 20 million m3, and the annual FP water production reached 8.56 million m3. Notably, 80 % ~ 90 % of the FP water has been reused for hydraulic fracturing since 2020, accounting for 29 % to 35 % of the annual water usage for hydraulic fracturing. Water use per well in China varies primarily between 21,730 m3 to 61,070 m3 per well, and water use per horizontal length ranges primarily between 20 m3/m and 35 m3/m. The average ultimate FP water production per well in China was estimated to be 22,460 m3. The water use intensity (WUI) for shale gas extraction in China mainly ranges from 7 to 25.4 L/GJ, which is significantly higher than that of the U.S. This disparity is largely due to the lower Estimated Ultimate Recovery (EUR) of shale gas wells in China. Despite the considerable water consumption during the hydraulic fracturing process, shale gas has a relatively low water footprint compared to other conventional energy resources in China. The Produced water intensity (PWI) for shale gas extraction in China ranges from 3.9 to 7.3 L/GJ, which is consistent with the previously reported PWI values for shale gas extraction in the U.S. This study predicts water usage and FP production spanning the period 2023 to 2050 under two scenarios to assess the potential impact of shale gas extraction on water resources in the Longmaxi shale region in Sichuan Basin. The first scenario assumed a constant drilling rate, while the second assumed a yearly 10 % increase in drilling rate. With an assumed FP water reuse rate of 85 % for hydraulic fracturing, the estimated annual freshwater consumption for the two scenarios is 10.4 million m3 and 163 million m3, respectively. This accounts for only 0.28‱ and 4.4‱ of the total annual surface water resources in Sichuan and Chongqing Province. Our findings suggest that freshwater usage for hydraulic fracturing in humid Southern China is small relative to available surface water resources. However, prospective large-scale shale gas extraction in other arid and semi-arid regions may enhance the regional water scarcity. It is necessary to develop new hydraulic fracturing technologies that can use saline groundwater or other types of marginal water, and explore alternative management and treatment strategies for FP water.

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Although conventional hydraulic fracturing techniques have revolutionized shale gas development, they have raised concerns regarding water management and environmental impacts. This research introduces an innovative step-rectangular pulse hydraulic fracturing method to optimize water usage and reduce environmental hazards in shale gas extraction. The method involves the application of lower-energy fluid in a step-rectangular pulse pattern, which results in higher pressures, more intricate fractures, and improved water management. A comprehensive analysis of the propagation and attenuation characteristics of this technique is conducted using a combination of a two-dimensional pulse transient flow equation with damping, software numerical simulations, and theoretical analysis. The study reveals that the step rectangular pulse hydraulic fracturing method offers superior pressurization and more complex fracture networks in shale reservoirs while lowering water consumption by 20% less than conventional methods and increasing shale gas production by 12%. Through identifying optimal pulse parameters, this research provides valuable guidance for field implementation, promoting efficient water management and environmental sustainability in hydraulic fracturing operations. This novel approach to hydraulic fracturing has the potential to significantly advance the industry’s efforts to address water management challenges and mitigate environmental risks associated with shale gas extraction.

The distribution of matrix pressure and water saturation during the fracturing and shut-in period significantly impacts shale gas production. However, traditional numerical simulations primarily focus on the production period, often overlooking the impact of fracturing and shut-in on the seepage field and production rates. This study uses the dual-porosity/dual-permeability-embedded discrete fracture model (DPDK-EDFM) to characterize matrix mixed wettability and the natural/hydraulic fracture geometry. A multiscale numerical simulation model is constructed to encompass the whole life cycle of shale fracturing, shut-in, and production. The model provides a comprehensive understanding for considering the changes in rock properties and the diverse migration mechanisms. Subsequently, the life cycle model is used for sensitivity analysis on capillary pressure, shut-in time, and fracturing fluid volume. The findings demonstrate that (1) capillary pressure strongly impacts flowback rate. As surface tension increases from 0 to 72 mN/m, the flowback rate decreases from 113.00% to 68.25%. (2) The shut-in time strongly affects the uniformity of pressure distribution. (3) The fracturing fluid volume is directly proportional to the rise in formation pressure. This innovative model provides a robust framework for simulating and analyzing the seepage field behavior of shale gas reservoirs throughout the life cycle. Furthermore, through a comprehensive investigation of the main controlling factors, this study provides valuable insights into the efficient development of shale gas reservoirs, carrying both theoretical and practical significance.

Shale gas has a permeability of <0.1 mD and a porosity of around 2% - 8% to produce gas that rises to the surface through hydraulic fracturing and horizontal drilling. Geomechanics is one of the important factors that influence the success of a hydraulic fracturing job. Technology in fractures makes geomechanics a clear factor in predicting the success or failure of rocks in deformation and knowing the properties that will be faced by fracture fluids which will later be used to see the effectiveness of fracture fluids in resisting fractures. High operational costs need to be studied further to determine the parameters that affect hydraulic fracturing work, especially from the geomechanical aspect to minimize production failures and work safety. The research conducted this time focuses on the sensitivity of geomechanical parameters by using CMG (GEM) reservoir simulations for reservoir models and conducting Response Surface Methodology (RSM) in selection and ease when applied in the field prior to the hydraulic fracturing process. In this sensitivity study carried out on 5 parameters namely stress, Poisson's ratio, Young's modulus, biot coefficient, and pore pressure. The geomechanical parameter that has the most influence on hydraulic fracturing work based on the sensitivity results carried out through 500 data sets using the Analysis of Variance obtained R2 = 0.99 with the results based on the importance value of the pore pressure variable of 3.8. Then Young's modulus is 0.28, stress is 0.12, Poisson's ratio is 0.08, and biot coefficient is 0.04.

Physical simulation of hydraulic fracturing based on the feature of shale gas reservoir is an effective means to comprehend fracture geometry and extension mechanism, which is also one of the most effective methods for shale gas reservoir reconstruction. Take hydraulic fracturing construction as reference and select critical factor for object, shale gas hydraulic fracturing experimental system was designed. The system consists of true triaxial module, hydraulic servo pump module and acoustic emission module. By setting up different parameters of fracturing in simulation experiment, the influence of parameter factors on hydraulic fracturing effect is studied. The results show that type and quantity of perforation, size and direction of in-situ stress, fracturing fluid displacement and other parameters have different influence on the fracturing effect. This experiment provides a certain theoretical basis for shale gas hydraulic fracturing technology in construction site.

As an important supplementary energy resource, shale oil has attracted worldwide attention due to its huge reserves and rich comprehensive utilization levels. The world is rich in oil shale resources. According to statistics, if the oil shale of 33 countries and regions in the world is converted into shale oil, it will be about 400 billion tons. With the continuous maturity of horizontal well drilling and completion technology in shale oil gas reservoirs and the application of other advanced technologies in horizontal well drilling, mature shale oil gas drilling and completion matching technologies have gradually formed at home and abroad after years of research and drilling practice. In terms of measurement technology, China has been able to produce single-point, multi-point, wired, wireless inclinometers and MWD measuring instruments while drilling and has mastered their usage methods. In terms of control technology, various specifications and types of fixed-angle and ground-adjustable curved shell screw drilling tools have been produced in China. Large deformation analysis and trajectory prediction methods for lower drilling tool assemblies have been completed. Various lower drilling tool assemblies and their usage processes required for wellbore trajectory control have been improved and mastered. In the construction of inclined and horizontal sections, attention should be paid to the response law of drilling tool combinations to drilling pressure in different formations, especially the response law of composite drilling. Reasonable drilling tool combinations should be selected for the control of wellbore trajectory in stable and horizontal sections, especially in the long stable and horizontal sections.

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In 2022, a field pilot study was conducted on a shale oil platform in the Yingxiongling Block, Qinghai Oilfield, China, to evaluate the feasibility of replacing conventional oil-based mud (OBM) with an organic salt-based mud (OSBM) under high mud weight and wellbore instability conditions. The platform consisted of 8 horizontal wells drilled in 2 phases, with 4 wells using OBM and 4 using OSBM. Identical drilling tools and parameters were applied across comparable intervals to ensure a valid performance comparison. The results showed that both drilling fluid systems maintained excellent borehole stability and clean hole conditions, with no incidents of differential sticking or sloughing. However, OSBM consistently delivered superior drilling efficiency. In 8½-inch hole sections using a rotary steerable system (RSS) without positive displacement motors (PDM), the OSBM wells achieved an average rate of penetration (ROP) more than twice that of OBM wells. Even after PDMs were introduced to the OBM wells, OSBM still required fewer trips and maintained higher ROP. Overall, OSBM reduced the total drilling time by 18.56% compared to OBM, despite complex shale formations and high-density fluid requirements. This study demonstrates that OSBM is a reliable, high-performance, and environmentally advantageous alternative to OBM in demanding shale drilling operations.

In order to select a better design trajectory, it needs to spend a lot of energy on parameter adjustment and calculation. Therefore, this paper establishes the intel?ligent optimization design model of horizontal well trajectory in with the target length and drilling string drag under rotary drilling conditions as the targets, and takes the target entry accuracy as the complex constraints. Meanwhile, multi-ob?jective optimization algorithm and distributed calculation are used to realize the automatic optimization of the well trajectory. Under the given arithmetic conditions, compared with the original design trajectory, a horizontal well was designed with this method, the trajectory length is shortened by 92.1 m, and the maximum build-up rate is changed from 5.50? per 30 m to 4.97? per 30 m, reducing by 9.6%. Under the same BHA and boundary conditions, the drag becomes 232.42 kN, which is 6.8% lower than that before optimization.

Longmaxi shale formation has developed beddings and fractures in southern Sichuan, which is prone to well leakage and wellbore instability. In the drilling process of horizontal section of Ning 209H58-2 well, drilling fluid would loss during circulation and return after pump stopped in the same section, which was the obviously respiration effect. The larger amount of leakage and pumping back, the greater the difference of drilling fluid density would be, accompanied by the increasing value of the gas. In this paper, shale was determined to have “screen effect” by assuming methods, the drilling fluid would loss as the equivalent circulating density was greater than the crack opening pressure, and the crack width was just in the size range of barite particle, then the larger size barite cannot enter in shale cracks end gathered together, and low density drilling fluid would penetrated into the formation, and then the drilling fluid density would be high in the first and low then after circulation again. The equivalent circulating density would be controlled by reducing the drilling fluid density, the effects of microfracture opening and respiration would be avoided, and the drilling fluid density would return to normal after circulation. This paper illustrates that the shale screen effect was the main reason for the uneven density of drilling fluid, which was expected to provide technical support for the development of horizontal shale gas Wells.

Formation damage in drilling comes from drilling fluid invasion due to high differential pressure between a wellbore and the formation. This mechanism happens with fracture fluid invasion of multi-fractured horizontal wells in tight formations. Some multi-fractured wells show production rates and cumulative productions far lower than expected. Those damaged wells may sustain further impact such as well shutting due to unexpected events such as the COVID-19 outbreak and then experience a further reduction in cumulative production. This paper focuses on the root causes of formation damage of fractured wells and provides possible solutions to improve production. A simulation study was conducted using Computer Modelling Group software to simulate formation damage due to fracture fluid invasion and well shut-in. Simulation results revealed that the decrease in cumulative hydrocarbon production due to leak-off and shut-in of the simulated well could range from 20 to 41%, depending on different conditions. The results showed that the main causes are high critical water saturation of tight formations, low drawdown, and low residual proppant permeability under formation closure stress. The sensitivity analysis suggests two feasible solutions to mitigate formation damage: optimizing drawdown during production and optimized proppant pack permeability of the hydraulic fracturing process. Optimizing pressure drawdown is effective in fixing leak-off damage, but it does not mitigate shut-in damage. Formation damage due to shut-in should be prevented in advance by using an appropriate proppant permeability. These key findings enhance productivity and improve the economics of tight gas and shale oil formations.

Wellbore instability is a major constraint in large-scale shale oil extraction. This study focuses on the shale–sandstone interbedded shale oil reservoirs in the Chang 7 area, delving into the evolutionary principles governing wellbore stability in horizontal drilling operations within these formations. A geological feature analysis of shale–sandstone reservoir characteristics coupled with rigorous mechanical experimentation was undertaken to investigate the micro-mechanisms underpinning wellbore instability. The Mohr–Coulomb failure criterion applicable to sandstone and the multi-weakness planes failure criterion of shale were integrated to analyze the stress distribution of surrounding rocks within horizontal wells, facilitating the computation of collapse pressure and fracture pressure. A finite element model of wellbore stability in shale–sandstone horizontal drilling was established, and then we conducted a comprehensive analysis of the impacts of varying elastic moduli, Poisson’s ratio, and in-situ stress on wellbore stability. The findings reveal that under varying confining pressures, the predominant failure mode observed in most sandstone samples is characterized by inclined shear failure, coupled with a reduced incidence of crack formation. The strength of shale escalates proportionally with increasing confining pressure, resulting in a reduced susceptibility to failure along its inherent weak planes. This transition is characterized by a gradual shift from the prevalent mode of longitudinal splitting towards inclined shear failure. As the elastic modulus of shale rises, the discrepancy between circumferential and radial stresses decreases. In contrast, with the increasing elastic modulus of sandstone, the gap between circumferential and radial stresses widens, potentially inducing potential instabilities in the wellbore. An increase in sandstone’s Poisson’s ratio corresponds to a proportional increase in the difference between circumferential and radial stresses. Under reverse fault stress regimes, wellbore collapse and instability are predisposed to occur. Calculations of collapse pressure and fracture pressure reveal that the safety density window is minimized at the interface between shale and sandstone, rendering it susceptible to wellbore instability. These research findings offer significant insights for the investigation of wellbore stability in interbedded shale–sandstone reservoirs contributing to the academic discourse in this field.

Shale oil and gas reservoirs are characterized by low porosity and low permeability. The development of ultra-long horizontal wells can significantly increase reservoir contact area and enhance single-well production. Shale formations exhibit distinct bedding structures, high formation pressure, high rock hardness, and strong anisotropy. These characteristics result in poor drillability, slow drilling rates, and high costs when drilling horizontally, severely restricting efficient development. Therefore, accurately predicting the drillability of shale gas wells has become a major challenge. Currently, most scholars rely on a single parameter to predict drillability, which overlooks the coupled effects of multiple factors and reduces prediction accuracy. To address this issue, this study employs drillability experiments, mineral composition analysis, positional analysis, and acoustic transit-time tests to evaluate the effects of mineral composition, acoustic transit time, bottom-hole confining pressure, and formation drilling angle on the drillability of horizontal well reservoirs, innovatively integrating multiple parameters to construct a nonlinear model and introducing three intelligent optimization algorithms (PSO, AOA-GA, and EBPSO) for the first time to improve prediction accuracy, thus breaking through the limitations of traditional single-parameter prediction. Based on these findings, a nonlinear regression prediction model integrating multiple parameters is developed and validated using field data. To further enhance prediction accuracy, the model is optimized using three intelligent optimization algorithms: PSO, AOA-GA, and EBPSO. The results indicate that the EBPSO algorithm performs the best, followed by AOA-GA, while the PSO algorithm shows the lowest performance. Furthermore, the model is applied to predict the drillability of Well D4, and the results exhibit a high degree of agreement with actual measurements, confirming the model’s effectiveness. The findings support optimization of drilling parameters and bit selection in shale oil and gas reservoirs, thereby improving drilling efficiency and mechanical penetration rates.

The article analyzes resilience factors of tight oil and gas production in the USA. The US is the only country in the world that currently produces shale hydrocarbons on a commercial scale, though other petroleum states try to emulate their success in this sphere. The American shale revolution became possible due to a massive application of hydrofracking in combination with horizontal drilling to produce tight oil and gas. Therefore, the mighty technological potential of the American petroleum sector became the key success factor of the US shale revolution. However, technological breakthroughs are necessary, but not sufficient for ensuring a stable development of the shale industry. Of particular importance is the institutional framework of the US shale sector that is characterized by an efficient system of subsurface use, a powerful financial and industrial base, a long-term strategy of the state support for R&D, a reasonable fiscal policy, a transparent regulation, as well as a competitive and diversified structure of the shale sector. This unique combination of factors will be extremely difficult to replicate in other countries. When constructing long-term scenarios of oil and gas production, the US Energy Information Administration proceeds from the key assumptions of resource availability and rates of improving production technologies. The analysis of the shale phenomenon permits to conclude that these two factors are interconnected – the continuous technological progress of the sector ensures the enhanced oil and gas recovery ratio. As a result, the production growth is accompanied by the growth of resource availability. The limits to this trend are not visible yet, and, therefore, it means that the upside potential of shale production is not exhausted.

Drilling long horizontal wells in naturally cracked/fractured unconventional shale gas/oil formations presents a huge challenge to the energy industry because of wellbore clogging complications that cause pipe sticking problems. This work proposes to use smooth catenary well trajectories to reduce drilling friction to mitigate these problems. A mathematical model was developed in this study for designing well trajectory profiles with a smooth transition from the kick-out point (KOP) to the catenary section. This model consists of closed-form equations for the radius of curvature and inclination angle in the catenary section. Using the radius of curvature at the top point of the catenary section to design the arc section below the KOP eliminates the trial-and-error procedure required for achieving the smooth transition between the two sections. The result of a field case study with Tuscaloosa Marine Shale (TMS) data shows that the drilling drag (hook load) can be reduced by 15% to 30% with the use of smooth catenary well trajectories to replace the conventional arc-type well trajectories. Model-calculated reduction in the hook load drops linearly with the horizontal borehole friction coefficient (clog indicator). The reduction increases non-linearly from 15% to 30% with drill collar weight increasing from 20 lb/ft to 92 lb/ft.

Unconventional oil and gas resources, such as shale oil and gas, are gradually attracting great attention from all countries of the world. Horizontal drilling and large-scale hydraulic fracturing technology are used to efficiently extract oil from shale formation. Effective placement of the proppant in the fractures and high long-term conductivity are the keys to solve the problems of oil well flow rate increase in shale oil and gas fields. In this work, the sieve analysis method and FCMS-V fracture conductivity determination device, as well as scanning electron microscope are used. They are used to experimentally investigate the filtration characteristics of hydraulic fracturing fractures and establish the key factors affecting the filtration characteristics. The object of the study is the core of the oil-saturated DG shale formation of Songliao Basin. Also in this paper, the indentation and crushing mechanism of proppant under reservoir conditions is studied. The influence of various factors was evaluated qualitatively and quantitatively. The following studies were conducted: the effect of sand granule size on conductivity, the effect of grain size distribution on conductivity, the effect of proppant concentration on conductivity, the effect of fracture closure pressure on conductivity, and the effect of proppant indentation on conductivity. The granule sizes of the proppant used range from 30/50 to 70/140 mesh. Proppant concentration: 2,5; 5; 10 kg/m2. Ratios of granule sizes for used mixtures: 1:1:1, 1:2:7, 1:4:5.And crack clamping pressure from 20 to 40 MPa. As a result of the study, dependences of initial and long-term fracture conductivity on clamping pressure, granulometric composition of proppant and its concentration were obtained. Using a scanning electron microscope, the degree of indentation and crushing of proppant under reservoir conditions in two media, namely shale core and steel plates, was visually evaluated. The results of experimental studies can be used to optimize the shale oil development system and have scientific and practical significance for shale oil production in continental deposits.

Stick–slip vibration leads to accelerated wear of drilling tools and downhole tool failures, particularly in long horizontal sections. Existing drill-string dynamics models and control or digital-twin frameworks have significantly improved our understanding and mitigation of stick–slip, but most of them adopt simplified Newtonian or linear viscous damping and low-degree-of-freedom representations of the drill-string–fluid–BHA system, which can under-represent the influence of non-Newtonian oil-based drilling fluids and detailed BHA design in long horizontal wells. In this study, an n-degree-of-freedom torsional stick–slip vibration model for horizontal wells is developed that explicitly incorporates Herschel–Bulkley non-Newtonian rheological damping of the drilling fluid, distributed friction between the horizontal section and drill string, and bit–rock interaction. The model is implemented in a computational program and calibrated and validated against stick–slip field measurements from four shale-gas horizontal wells in the Luzhou area, showing good agreement in stick–slip frequency and peak angular velocity. Using the Stick–Slip Index (SSI) as a quantitative metric, the influences of rotary table speed, weight on bit (WOB), and bottom-hole assembly (BHA) configuration on stick–slip vibration in a representative case well are systematically analyzed. The results indicate that increasing rotary speed from 64 to 144 r/min progressively reduces stick–slip severity and eliminates it at 144 r/min, reducing WOB from 150 to 60 kN weakens and eventually removes stick–slip at the expense of penetration rate, drill collar length has a non-monotonic impact on SSI with potential high-frequency vibrations at longer lengths, and increasing heavy-weight drill pipe (HWDP) length from 47 to 107 m consistently intensifies stick–slip. Based on these simulations, SSI-based stick–slip severity charts are constructed to provide quantitative guidance for drilling parameter optimization and BHA configuration in field operations.

The low porosity and low permeability of shale gas reservoirs make fracturing technology an indispensable part of shale gas reservoir development. The initial stage of shale gas development is characterized by shallow direct wells, but with the advancement of drilling and completion technology in the development of unconventional oil and gas reservoirs, horizontal wells and fracturing technology have gradually become the key methods for the effective development of oil and gas reservoirs. “Geology-engineering integration” has gradually become a hot spot in the research of horizontal well fracturing. The factors affecting the development of shale gas reservoirs are subdivided into “geological sweet spot” and “engineering sweet spot” influencing factors. Geological sweet spot refers to the area where the reservoir is rich in hydrocarbons or organic matter; engineering sweet spot refers to the area with good fracturability in the later fracturing and reforming of the reservoir. The shale gas sweet spot area should have the characteristics of high gas content, high fracturable, and high efficiency. Comprehensively evaluating the physical properties and brittleness characteristics can provide certain guidance for shale gas horizontal well segmentation.

SY1H is the first shallow shale horizontal well deployed in Jilin Oilfield, with a depth of 1,150m in Qing1 section of the target layer, a designed horizontal section length of 2,000m, and a water-drag ratio of nearly 2:1, so the well is characterised by the difficulty of pressurising with a large digit-drag ratio, the high friction between the drilling and the lower casing, and the shale wall being easy to be destabilised and collapsed. There are no horizontal wells in the neighbouring wells with a section of green as the destination layer, and there is a lack of reference materials, and the stability of the shallow shale is not clear. In order to ensure that the well can be reached and drilled for a long time, a technical route was formulated with the objectives of effectively reducing drilling resistance, increasing drilling pressure, and rapid drilling and completion within the collapse cycle, and technical measures such as equipping with a top drive and a high-grade drilling rig to increase the drilling pressure, oil-based drilling fluids and rotary guiding to reduce drilling resistance and the ability to deal with complex situations, and floating casing process to ensure that casing can be smoothly lowered in place, etc., so as to achieve safe and rapid construction of SY1H and achieve a horizontal section of 2,000m. construction and achieve the geological target of 2000m horizontal section.

No abstract available

Shale gas reservoir at the outer edge of Sichuan basin belongs to normal pressure shale gas reservoir. In the analysis of the difference between the current and the pressure shale gas drilling, the technical measures to reduce the cost of drilling, the design of the well, the borehole trajectory, the drilling, the drilling fluid and the cementing process, the design of the three shafts, the design of the structure of the shaft, the design of the two dimensions of the well, the design of the two dimensions, the design of the orbital trajectory of the shafts, using the spin guide technology to control the orbital trajectories of the two shafts, the low-oil, and the optimal production of the concrete and the production of the drilling and the drilling costs, the technology and the measures, to provide the technical support for the economical and efficient development of the natural gas in the Sichuan basin.

Based on borehole instability problems, a new kind of composite plugging agent for oil-based drilling fluids was developed, and the influence of plugging agent on shale stability was evaluated. The results indicated that the oil-based drilling fluids containing composite plugging agent could produce an ultra-thin, tight and relatively impenetrable mud cake, and consequently provided an excellent sealing effect. The core displacement experiment indicated that this plugging agent could reduce the shale permeability by a significant amount, and thus stop fluid invasion and improve wellbore stability. Using this plugging agent to seal the shale is a very powerful and economical approach to address borehole instability problem in troublesome shale formations. This plugging agent is suitable for the drilling of long sections of horizontal laterals. In the future, this plugging agent might hold great promise to resolve shale instability problem.

Extended-reach horizontal wells in continental shale formations of the Fuxing Block, southeastern Sichuan Basin, face prominent challenges, including drag and torque exceeding 50 metric tons and difficulties in weight-on-bit (WOB) transfer. Continental shale is characterized by high porosity, high permeability, distinct amphiphilic properties, and rapid performance degradation of oil-based drilling fluids (OBDF). These features lead to the formation of thick filter cakes and compacted cuttings beds, which further exacerbate abnormal drag. Existing research often focuses on single technical aspects, lacking integrated, full-cycle multi-factor coupling analysis. Based on field data from 14 drilled wells in the block, this study standardizes key factors through data preprocessing, quantifies process weights using the Analytic Hierarchy Process (AHP) model, and fits censored drag data via the Reliability Analysis model. Results indicate that design optimization contributes most significantly to drag reduction (weight: 0.5499). The critical failure drag for encapsulated lubricants is identified as 61.74 t. For wells with horizontal sections exceeding 2500 m, the application of floating casing technology enhances drag control reliability.

: The horizontal section of the horizontal well is drilled to a certain length in the target, which increases the exposed area of the oil and gas reservoir. The basic purpose of the horizontal well is to increase oil and gas production or oil and gas recovery. With the development of Weiyuan shale gas horizontal wells, the development of drilling technology and the demand for higher precision formation analysis, as well as the demand of oil field companies to improve quality, efficiency and cost, the integration of various professional models has mushroomed. Several aspects, geological guidance based on petroleum geology, as well as practical applications, characteristics, and mud logging relationships are summarized. The cooperation of the three factors improves the comprehensive technical ability and production and management efficiency of the field geology.

This study analyzes the wellbore stability of Beipiao oil shale in Liaoning Province. XRD analysis and triaxial compression tests, conducted at bedding inclination intervals of 30° (0°, 30°, 60°, and 90°), characterize the samples as hard-brittle shale with significant mechanical anisotropy. Specifically, the cohesion and internal friction angle of the rock matrix are 17.15 MPa and 36.21°, respectively, while those of the bedding weak planes are significantly lower at 8.95 MPa and 25.85°. By coupling a transversely isotropic model with Jaeger’s criterion, the collapse pressure equivalent density was calculated under various in-situ stress regimes. The results indicate that the optimal drilling trajectory varies with the stress regime: under strike-slip and reverse faulting conditions, the optimal trajectory aligns with the maximum horizontal in-situ stress (σH), whereas under normal faulting conditions, it aligns with the minimum horizontal in-situ stress (σh). These findings provide a theoretical basis for trajectory optimization in hard-brittle laminated formations.

Problems such as well loss and collapses in deep shale gas drilling are most often due to the development of cracks in the shale formation, resulting in significant leaks of drilling fluid, the sticking and burrowing of drilling tools, and other engineering accidents. In addition, the horizontal sections of wells are very long and issues of friction, rock transport, and formation contamination loom large. As a result, the performance of drilling fluids directly affects drilling efficiency, engineering accident rates, and reservoir protection effects. We first analyze the mechanisms of each emulsifier in an oil-based drilling fluid formulation and the filtration reduction mechanisms, taking into account the collapse-prone and abnormally high-pressure characteristics of shale formations. We undertake an experimental evaluation and optimization of polymeric surfactants, such as primary and secondary emulsions for high-performance oil-based drilling fluids. The design of rigid and deformable nano-micron plugging materials with a reasonable particle size range was achieved, and we obtained a low Oil—Water ratio and high-density oil-based drilling fluid system, with temperature resistance of 200 °C, an Oil—Water ratio as low as 70:30, compressive fracturing fluid pollution of 10%, and a maximum density of 2.6 g/cm3. The reuse rate reached 100%. The developed oil-based drilling fluid system with strong plugging, a high density, and a low Oil—Water ratio suitable for deep shale gas can effectively seal the well wall, reduce liquid invasion, prevent the wall from collapsing, reduce mud leakage, reduce the consumption of oil-based drilling fluid, improve the utilization rate of old mud, and reduce drilling costs.

Unconventional tight oil and gas resources, including shale oil and gas, have become the main focus for increasing reserves and production. The safe and efficient development of unconventional oil and gas is a crucial demand for the energy development strategy. Deep tight oil and gas resource development generally adopts horizontal well drilling methods. During drilling, especially in long horizontal sections, the high temperature frequently causes failures of downhole drilling tools and rotary steering tools. The temperature rises sharply during rock breaking with the drill bit. Existing wellbore heat transfer models do not fully consider the impact of heat generated by the drill bit on the wellbore temperature field. This paper aims to experimentally study the temperature rise law of the cutting tooth of the bottom polycrystalline diamond compact (PDC) bit during rock breaking. A set of evaluation devices was developed to study the temperature field distribution characteristics at the bottom of the PDC bit during rock breaking under different experimental conditions. The results indicate that the flow rate of drilling fluid, bit rotation speed, and weight on bit (WOB) significantly affect the distribution of the temperature field at the well bottom. This experimental research on the temperature field distribution characteristics at the bottom of the PDC bit during rock breaking helps reveal the heat transfer characteristics of the long horizontal section wellbore, guide the optimization of drilling parameters, and develop temperature control methods. It is of great significance for the advancement of efficient development technologies for unconventional resources in long horizontal wells.

No abstract available

China has abundant shale gas resources with great potential, which may serve as a significant support for the development of a “low-carbon economy”. Domestic shale gas resources are buried deeply and difficult to exploit due to some prevalent issues, such as long horizontal sections, severe development of reservoir fractures, strong sensitivity to water, borehole instability, etc. Compared to water-based drilling fluids, oil-based drilling fluid exhibits better inhibition and good lubricity and is thus broadly used in shale gas drilling, but it is confronted with the challenge of removing the harmful solid phase. Selective chemical flocculation is one of the most effective methods of removing the harmful solid phase in oil-based drilling fluid. In this study, interactions between the flocculation gel for oil-based drilling fluid and clay minerals were investigated by molecular simulation, which revealed the molecular-scale selectivity of the flocculation gel for rock cuttings with negative charges. Calculations showed that the flocculation gel is highly effective for the flocculation of negatively charged cuttings, but it is ineffective for flocculating neutral cuttings. The flocculation gel is not very effective for cuttings with high hydrophilicity, and it is totally ineffective for flocculating cuttings with poor hydrophilicity. Within a limited concentration range, the flocculation effect can be enhanced by increasing the flocculation gel concentration. The performance of the flocculation gel declined at elevated temperatures.

No abstract available

Drilling and developing unconventional (UC) hydrocarbon resources present unique technical and operational challenges significantly distinct from conventional reservoirs. Unconventional formations—such as shale oil, shale gas, and tight gas reservoirs—are characterized by low permeability, significant geological heterogeneity, and expansive geographical footprints, necessitating specialized extraction methods including extended horizontal drilling and multi-stage hydraulic fracturing. Despite global availability of conventional reserves, economic and technological advances have increasingly driven exploration and development of unconventional resources. This paper explores specific strategies and technical considerations to optimize well construction and drilling performance in unconventional reservoirs. A structured approach emphasizing advanced drill-bit selection, tailored bottom-hole assemblies (BHAs), optimized drilling fluids, and precise wellbore trajectory control significantly enhances operational efficiency. Rotary steerable systems, combined with measurement-while-drilling (MWD) and logging-while-drilling (LWD) technologies, provide accurate real-time geosteering capabilities, ensuring optimal reservoir placement and simplifying subsequent fracturing operations. Additionally, proactive reduction of wellbore tortuosity, strategic casing designs, and robust cementing programs tailored specifically for high-pressure stimulation conditions are highlighted as critical factors in ensuring well integrity and fracturing effectiveness. Rig selection and equipment design tailored for unconventional drilling, including top-drive systems, high-capacity mud pumps, automation, and pipe handling systems, significantly enhance safety, efficiency, and drilling performance. The adoption of managed pressure drilling (MPD) and New technologies further optimizes operational safety and reduces non-productive time (NPT), demonstrating tangible economic benefits in diverse unconventional plays. Moreover, pad-drilling techniques, incorporating multiple horizontal wells from centralized surface locations, optimize operational logistics, reduce environmental impacts, and lower costs. Strategic infrastructure planning and optimized logistics management significantly streamline operations, minimizing downtime and enhancing overall project economics. Technical advancements must be complemented by a fundamental shift in organizational mindset, promoting continuous improvement, innovation, and multidisciplinary collaboration. Establishing integrated performance management systems, operational performance improvement plans (OPIP), and clearly defined key performance indicators (KPIs) fosters rapid decision-making and proactive operational optimization. Conclusively, targeted adjustments in drilling technology, operational strategies, and organizational culture directly result in reduced drilling durations, enhanced operational efficiency, minimized costs, and improved hydrocarbon recovery from unconventional reservoirs. The comprehensive technical strategies and organizational practices presented provide a clear roadmap toward achieving excellence in unconventional well construction and drilling operations.

To mitigate drilling risks and enhance the rate of penetration (ROP) in shale gas horizontal wells, wellbore stability analysis and geomechanical studies are essential. However, cluster development of horizontal wells within the same platform alters the original in-situ stress field, rendering the drilling mud weight window calculated based on static mechanical models inaccurate. This frequently leads to wellbore instability during drilling, posing risks to both drilling safety and environmental protection. This paper integrates actual drilling, fracturing, and production data to establish a multidimensional geomechanical model. Building upon a 1D static geomechanical model, it incorporates stress field variations in the target drilling area caused by fracturing and production operations from three previously completed horizontal wells in the northern cluster. Key findings include: 1. Dynamic Stress Field Analysis: After injecting approximately 100,000 m3 of fracturing fluid into three northern horizontal wells and considering cumulative production effects, the "fracturing-production" operations in the northern cluster induced a pore pressure increase of 0.6–1.6 MPa in the southern platform area. This corresponds to a mud weight increment of 0.07–0.1 g/cm3, necessitating adjustments to drilling fluid density for enhanced wellbore stability. 2.Target Formation Mechanical Properties: Poisson's ratio: 0.152–0.22. Young's modulus: 6.1–65.8 GPa. Rock strength: 60.7–117 MPa. The low Poisson's ratio and high Young's modulus indicate medium-hard formations with favorable drillability. 3.Formation Pressure Evolution: The Hanjiadian Formation exhibits gradual pressure buildup, with the Longmaxi source rock reaching a maximum pressure gradient of 1.49 g/cm3.This dynamic geomechanical model demonstrates strong applicability and accuracy in predicting wellbore stability and optimizing mud weight windows. It provides critical insights for drilling design, effectively addressing stress field perturbations caused by multi-well interference in cluster development. For instance, the quantified mud weight adjustment (0.07–0.1 g/cm3) directly translates to safer drilling practices while avoiding excessive mud costs – a balance crucial for both engineering safety and economic efficiency in shale gas operations.

Hydraulic oscillators can effectively reduce the frictional resistance of the horizontal well drilling column and increase mechanical drilling speed, but the influence of geological and operational conditions on the drag reduction performance of these tools has not been fully studied, resulting in the selection of hydraulic oscillators still relying mainly on field experience. This study investigates the effects of drill string material, drilling fluid, and tool type on the drag reduction capability of tools. Friction coefficients of two commonly used drill string materials (G105 steel, S135 steel) with three common formation types (sandstone, shale, and limestone) were measured under oil-based and water-based drilling fluid infiltration conditions at different speeds of movement. The experimentally obtained friction coefficients were incorporated into a nonlinear mechanical model of the drill string equipped with a hydraulic oscillator, which was solved using the finite difference method. The results showed that the drill string materials had a limited effect on tool drag reduction capabilities, while rock type and drilling fluid type had a more significant impact. The drag reduction effect of tools in oil-based drilling fluids was better than that of water-based drilling fluids. In shale, the drag reduction effect of tools was better than that in sandstone and limestone. Increasing the amplitude enhanced the drag reduction ability of tools more than increasing the vibration frequency. Increasing the amplitude and frequency of the tool in an oil-based drilling fluid environment produced a more significant increase in drag reduction than doing the same in a water-based drilling fluid environment. These findings can provide theoretical guidance for the design of output characteristics of hydraulic vibrators and field selection of tools under different drilling conditions.

This paper presents the design and execution of a high-temperature, high-performance water-based drilling fluid (HPWBF) to overcome challenges associated with handling limitations of oil-based waste in the area. The exploratory well targeted Formation Palermo Aike, an asset that is expected to have a high impact on the expansion of natural resources for the country to about 10 BBOE. This could make it the second most important unconventional resource after Formation Vaca Muerta in the country. The approach to this challenge involved the design of a drilling fluid that would enable the operator to acquire core samples and conduct electric logging in a pilot hole. This would lead to the flawless drilling of a horizontal well within a promising hydrocarbon-bearing formation section. Fluid qualification involved extensive and unique laboratory testing to address unknown shale formations, temperatures as high as 185°C (365°F), and pore pressures expected to reach 1.9 SG (15.9 ppg). Success criteria included the maintenance of wellbore stability. Specific goals included resistance to barite sag and the maximization of fluid stability for extended static periods during logging at anticipated high bottom hole temperatures. The vertical 8 ¾-in. pilot hole was drilled for approximately 670 m (2,198 ft) with 1.83 SG (15.3 ppg) fluid density. Core plugs were retrieved from 3,438 m (11,276 ft) to 3,474 m (11,394 ft). The 8 ¾-in. curve section was drilled for 635 m (2,080 ft) with 1.83 SG fluid density, landing at 90 degrees inclination. Lubricity was crucial to build angle, and the inherent lubricious nature of the fluid helped achieve the coefficient of friction (COF) target. The 6 1/8-in. lateral section was drilled for approximately 1,080 m (3,543 ft) with 1.83 SG fluid density. Fluid maintenance was difficult in water evaporation due to the high temperatures (164°C / 327°F). The engineered high-temperature HPWBF allowed the evaluation of Palermo Aike formation and helped retrieve quality cores for the evaluation of the producing formation. The team performed five logging runs with the well in static conditions for almost five days (116 hours) without any signs of fluid or formation instability. The logs allowed the collection of a large amount of geological information to establish areas with the greatest potential for production. They also provided insights into future targets for hydraulic fractures. The pilot, curve, and lateral sections were drilled with excellent performance for inhibition, fluid stability, and hole cleaning. The high-temperature, HPWBF was formulated with a novel dual function, high-temperature polymer that provides viscosity and filtration control. This new polymer allows for the removal of thermally labile biopolymers found in conventional high-performance WBFs without the addition of clay-based viscosifiers. Advanced lab testing was performed to evaluate the stability and pumpability of the fluid in long static conditions at bottom-hole temperature (BHT) as high as 185°C (365°F).

Water-based drilling fluids (WBDFs) cannot be effectively applied in long horizontal wells, such as shale gas wells, due to their high coefficient of friction (COF) and filtration loss that can strongly limit the efficient and environmentally friendly development of oil and gas resources. The objective of this study is the formulation of a WBDF characterized by ultra-low friction and ultra-low filtration properties, with a high-concentration polyepoxysuccinic acid (PESA) solution being utilized in the continuous phase. The research aims at the exploration of the feasibility of the method, the validation of the results, and the elucidation of the underlying mechanisms. The experimental results confirmed that the proposed WBDFs have excellent rheological properties, a COF of 0.016 and an API filtration of 0.4 mL. Microscopic analysis confirmed a direct and positive correlation between the macroscopic properties of the drilling fluids and their adsorption behavior at high PESA concentrations. This approach can be used to redesign traditional WBDFs and provide new possibilities to realize super performance in WBDFs that can be used to replace oil-based drilling fluids.

This case study presents the successful application of Managed Pressure Drilling (MPD) as a key enabler for delivering one of the deepest development wells in North Kuwait's Ratawi Field. The well, targeting the Ratawi Limestone formation at a total depth of 15,000 feet, posed significant operational challenges during the 9¼″ hole section, including high surface torque, elevated standpipe pressures (SPP) nearing rig pump limitations of 5000 psi, and complex wellbore stability issues due to over pressured shale and porous zones.In collaboration with Kuwait Oil Company (KOC) and Weatherford, a high-level MPD strategy was developed and executed using a Constant Bottom Hole Pressure (CBHP) approach. This enabled the use of a reduced base mud weight of 12.5 ppg compared to the client's mud weight range provided which reaches max 15.0 ppg, thereby maintaining effective well control through dynamic Equivalent Circulating Density (ECD) adjustments in real time. The result was a significant reduction in SPP—by 700 to 1000 psi—ensuring operations remained within rig capabilities without compromising formation integrity or safety. The operation also marked a first in applying MPD to lower SPP in high-pressure environments, setting a new benchmark in drilling efficiency, wellbore stability, and gas influx management. The 9¼″ section was drilled with improved BHA performance (2 runs vs. 3 planned runs), minimal non-productive time, and enhanced wellbore integrity over a 12-day exposure period in swelling shale zones. This paper highlights the strategic planning, real-time execution, and lessons learned from this pioneering MPD deployment in the Ratawi Field for KOC development drilling.

The integrity of shale gas wells is crucial in ensuring safety and efficiency throughout the development process. Such integrity spans the entire process of drilling and fracturing horizontal wells and is an essential indicator for ensuring safe and stable production throughout the lifespan of the well. This study investigates methods for assessing the integrity of shale gas wells by employing the analytic hierarchy process combined with experimental data to establish evaluation criteria and weights. The assessment is carried out specifically on shale gas wells in Changning Block. Results indicate that the integrity of these shale gas wells is influenced by various factors, such as drilling and fracturing processes. Moreover, the integrity assessment of indicators such as oil layer casing/technical casing, liquid carrying capacity, and tube column deformation is relatively low, indicating a need for enhanced monitoring and management. The comprehensive evaluation results indicate that, overall, the integrity rating of shale gas wells is generally considered “common,” but some potential safety hazards still remain that require timely attention and resolution. Case analysis reveals varying levels of integrity risks in shale gas wells. Case 1’s score of 93.51 warrants attention but is still deemed generally safe. However, Case 2’s score of 73.89 indicates a disaster level, emphasizing urgent intervention needs. Critical factors such as pressure, cementation quality, and corrosion demand proactive management for safe, sustainable operations.

Shale was initially regarded mainly as a source rock, but it is now recognized as both a source and reservoir. This shift has led to increased investigation into its geological properties. Extracting oil and gas from low-permeability shale formations is made possible by horizontal drilling, maximizing wellbore-rock contact, and hydraulic fracturing, which enhances permeability. The identification of sweet spot involves considering factors like source rock richness, natural fractures, core analysis, well-log data, and gas data to strategically position wellbores for optimal productivity. This paper aims to locate the sweet spot at the Ahnet Shale Gas Field by applying a comprehensive methodology, proving its accuracy in identifying geological and engineering sweet spots. Geological factors included organic matter quantity, maturity, composition, clay type, and reservoir characteristics. Engineering assessment considered rock mechanics and brittleness index, forming a robust evaluation system. Three significant sweet spot zones were pinpointed based on well-logging and geological data. The geochemical analysis emphasized high-quality Silurian shale rich in type II marine organic matter. Fluid characterization through chromatographic analysis and mechanical properties assessment reinforced the methodology's efficacy, aiding optimal shale gas exploration site selection.

This study examines the viability of using graphitic-Carbon Nitride (g-C3N4) nanomaterial as shale stabilizer drilling fluid additive having applications in the oil and gas wells drilling. Shale stability is important especially when drilling horizontal and extended reach wells with water-based muds (WBM) to tap unconventional reservoirs namely shale oil and shale gas. For this study, the g-C3N4 nanomaterial was produced by melamine pyrolysis, and characterized by X-Ray Diffraction, Scanning Electron Microscopy and Fourier Transform Infrared spectroscopy techniques. The developed g-C3N4 was used to formulate the WBM and its impact on the formulated mud system's rheological and filtration control characteristics as well as on shale stability was examined. In comparison to the base mud, the treated mud showed lower Fluid Loss (FL) and higher thermal stability. FL was reduced by 41.8 % and 68 % under Before Hot Rolling (BHR) and After Hot Rolling (AHR) conditions, respectively, with a maximum cake thickness of 1 mm. The Yield Point was improved by 52 % and 66 % under BHR and AHR conditions, respectively. The increase in Plastic Viscosity, and Apparent Viscosity was 23.8 %, and 38 %, respectively. Shale recovery was 99.6 % in g-C3N4 treated fluid compared to 88 % in the base fluid. The treated shale Brunauer-Emmett-Teller (BET) surface area and the pore volume were significantly reduced compared to the pure shale, indicating significant plugging of shale nano- and micro-pores. The BET surface area of the g-C3N4 treated shale sample was 0.0405 m2/g compared to pure shale sample's surface area 0.3501 m2/g. Correspondingly, the pore volume of treated shale was 0.000029 cm3/g compared to the pure shale sample's pore volume 0.000911 cm3/g. Therefore, based on the experimental results obtained, it is inferred that the developed g-C3N4 nanomaterial has potential applications in WBM systems for drilling long shale sections.

Unconventional oil and gas play a key role in the global transition to clean energy. Advances in horizontal drilling and hydraulic fracturing have enabled substantial hydrocarbon extraction from shale formations. However, the initial high production rates from these formations are not sustained over time, leading to a significantly lower recovery rates compared to conventional reservoirs. Hydrocarbon production in shale formations is governed by complex, multi-physical coupled mechanisms, including fluid diffusion in the tight matrix, multiphase flow in fractures, and stress dependent interactions between matrix and fracture. To address these challenges, we developed a high pressure ‘quad-pore’ triaxial cell and an in situ experimental protocol to simulate the live oil production scenarios. Under fully in-situ conditions, we saturated Wolfcamp shale with live oil, induced fractures, and conducted soaking, pressure drawdown, long term production, and stress dependent permeability evaluation. Through multiple tests, we found that shale gas production is mainly driven by pressure drawdown, long term production, and fracturing, while oil production was mainly produced during the long-term production and pressure drawdown. Soaking enhances hydrocarbon production through imbibition. Complex, branched fractures with larger surface areas are more effective in producing shale gas. As pressure decreases, the produced hydrocarbons becomes heavier, with higher concentrations of intermediate-chain and longer-chain hydrocarbons. Heavier oil dominates in the late production stage. The bubble point marks a critical threshold, beyond which a large amount of oil and gas are produced. These findings promote the development of a better strategy for unconventional oil and gas production and contribute to achieving important economic, energy security, and environmental benefits.

It is well known that the existing horizontal-well-drilling and hydraulic fracturing technology used to achieve large-scale, cost-effective production from immature to low–moderate-maturity continental shale in China, where the organic matter mainly exists in solid form, is fairly ineffective. To overcome the obstacles, in situ conversion technology seems feasible, while implementing it in the target layer along with estimating the amount of expected recoverable hydrocarbon in such shale formations seems difficult. This is because there are no guidelines for choosing the most appropriate method and selecting relevant key parameters for this purpose. Hence, based on thermal simulation experiments during the in situ conversion of crude oil from the Triassic Chang 73 Formation in the Ordos Basin and the Cretaceous Nenjiang Formation in the Songliao Basin, this deficiency in knowledge was addressed. First, relationships between the in situ-converted total organic carbon (TOC) content and the vitrinite reflectance (Ro) of the shales and between the residual oil volume and the hydrocarbon yield were established. Second, the yields of residual oil and in situ-converted hydrocarbon were measured, revealing their sensitivity to fluid pressure and crude oil density. In addition, a model was proposed to estimate the amount of in situ-converted hydrocarbon based on TOC, hydrocarbon generation potential, Ro, residual oil volume, fluid pressure, and crude oil density. Finally, a method was established to determine key parameters of the final hydrocarbon yield from immature to low–moderate-maturity organic material during in situ conversion in shales. Following the procedure outlined in this paper, the estimated recoverable in situ-converted oil in the shales of the Nenjiang Formation in the Songliao Basin was estimated to be approximately 292 × 108 tons, along with 18.5 × 1012 cubic meters of natural gas, in an area of approximately 8 × 104 square kilometers. Collectively, the method developed in this study is independent of the organic matter type and other geological and/or petrophysical properties of the formation and can be applied to other areas globally where there are no available in situ conversion thermal simulation experimental data.

Major Challenges while planning HPHT well in unconventional reservoir. The required mud weight to drill is 22ppg. were high torque, friction-factors. Well torque and drag simulations showed that planned completions were not deployable without rotation of the string and the deployment of the frac string required a very low friction factor that could only be reached by Oil based mud(OBM) or rotationwas huge impact. This paper describes the detailed key factors design criteria to deploy these risky completions. To drill cost-effective wells in a multi-disciplinary team was formed to review the design of unconventional wells and propose a cost-effective solution. Because of the complicated nature of the frac wells, they often use compression on the string to force it down which results in an excessive force which induces helical and sinusoidal buckling. The requirement of very low friction factors to deploy frac string with high mud weight; the new technology of floating the string,rotation of the string with low friction centralizers was introduced. The engineering design for the same was worked with risks of well control were mitigated. The well was a pilot to put concept to floatation inorder to deploy frac strings to Target depth(TD). The actual friction factor for Fluid systems with mud weight 20ppg and above is 0.45-0.5. The well architecture is complex and challenging due to its very short vertical section to landing point. This requires negative displacement to achieve the well objective with high dog leg severity per 100ft of 5 and above. The deployment of frac string can be achieved only by floatation or rotation. Rotation requires a high torque connection that directly impacts the well AFE. The floatation collar comprises of high-pressure glass disk that allows trapping air below the disk. The concept of flotation is to reduce drag and Friction factor of the frac string with the open hole which allows smooth deployment to TD. It is deemed necessary to use this technology along with low friction composite centralizers. The drilling fluid was customized to provide smooth ECD and circulating pressures targets to avoid increasing the risk of dynamic induced loss of circulation. The premium lubricant reduced the friction factor by 0.01. The cost of this technology is negligible compared to the risk associated with failure to deploy frac string. This was a new concept put to test which was the most cost effective with several new ideas and technologies being used. This service company idea bagged savings 30% cost by avoiding use of expensive high torque connections and systems. This concept will be applied to all future wells.

With the rise of intelligent oilfields, the demand for wellbore intelligent monitoring and production management technology has become increasingly urgent. One highly anticipated approach is fiber optic monitoring outside the casing. However, due to the low maturity of fiber optic positioning and fiber-avoiding perforation technologies, previous horizontal well tests in China have encountered failures, primarily due to fiber breakage. This paper presents a successful case in China, where fiber optic monitoring outside the casing was implemented using reclosable casing sleeves for completion. In June 2021, fiber was laid outside the whole casing string with 28 reclosable casing sleeves to implement cementing completion in Well XX-12. Up to now, three monitoring periods have been completed, and two sleeve switch tests have been conducted in response to high water cut during production. By laying fiber outside the casing and utilizing DTS and DAS to carry out fracturing monitoring and production monitoring, the whole lifecycle intelligent monitoring of fracturing, draining and production has been achieved. The fiber optic monitoring results have provided real-time verification of wellbore isolation effectiveness. The yield and water cut of each stage were determined by fiber monitoring DTS quantitative inversion, which guided two sleeve switch operations. The well has been tracked for nearly 3 years. The interpretation results verification and wellbore production management tests will continue to be carried out to improve the accuracy of intelligent monitoring and the effectiveness of production management. The implementation of this case has provided valuable experience in process execution, continuous wellbore intelligent monitoring, and production management.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 220937, “A Comparative Analysis of Completion and Reservoir Data To Decipher Productivity Drivers in North American Tight and Shale Plays,” by Vincent Indina, SPE, Harpreet Singh, SPE, and Yu Liu, CNPC, et al. The paper has not been peer reviewed. The primary objective of the study described in the complete paper is to assess thoroughly the influence of various completions, fracturing stimulation, and intrinsic reservoir properties on the productivity of 10 major unconventional oil and gas plays while uncovering key insights and emerging trends unique to each play. This data-driven study offers important insights into factors affecting productivity in shale plays, aiding future well development and resource-extraction optimization, and provides technical guidance for unconventional oil and gas developments in North America while serving as a useful reference for similar projects globally. This study used publicly available data from Enverus specifically focusing on well-production data from January 2015 to June 2024. The data set covered 10 distinct unconventional plays across North America (Bakken, Barnett, Delaware, Duvernay, Eagle Ford, Haynesville, Marcellus, Midland, Scoop/Stack, and Utica). Among these are six oil plays (Bakken, Delaware, Duvernay, Eagle Ford, Midland, and Scoop/Stack) and four gas plays (Barnett, Haynesville, Marcellus, and Utica). A total of 91,519 horizontal wells were examined in this study. To maintain accuracy, the study excluded wells that began production before 2015. The analysis focused on four main aspects: well fracturing, downhole consumables, production, and geological properties. Specific data extracted from each well included the number of wells per pad, well density, horizontal and vertical spacing, stimulated lateral length, number of fracturing stages, clusters, perforations, proppant and fluid usage, chemical composition, fracturing-job types, pumping rates, and cumulative production in barrels of oil equivalent during the first 3 months. To enable comparisons of well performance across plays, the production within the first 3 months was normalized based on 1,000 ft of lateral length. Criteria for well selection and classification are provided in the complete paper. The complete paper contains detailed results from both oil plays and gas plays; this synopsis contains portions of the latter. Gas Play Key Findings. Table 2 of the complete paper presents the completion strategies and productivity of wells across four gas-dominated shale plays (Haynesville, Marcellus, Montney, and Scoop/Stack) from 2015 to 2023. It is observed that field operators are in favor of drilling longer lateral wells; the average lateral length almost doubled between 2015 and 2023. The number of fracturing stages and stage spacing also increased from 2015 to 2023. This tendency of drilling longer lateral wells by operators also was accompanied by the increase of proppant and fracturing-fluid consumption in the same period. The amount of proppant and fracturing fluid consumed in 2023 was almost quadruple the amount consumed in 2015.

Optimizing unconventional field development requires simultaneous optimization of well spacing and completion design. However, the conventional practice of using cross plots and sensitivity analysis via Monte Carlo simulations (MCS) for independent optimization of well spacing and completion design has proved inadequate for unconventional reservoirs. This is due to the inability of cross plots to capture non-linear cross-correlations between parameters affecting hydrocarbon production, and the computational expense and difficulty of Monte Carlo simulations. Recently, automated machine learning (AutoML) workflows have been used to tackle complex problems. However, applying AutoML workflows to engineering problems presents unique challenges, as achieving high accuracy in forecasting the physics of the problem is crucial. To address this issue, a new physics-informed AutoML workflow based on the TPOT open-source tool developed that guarantees the physical plausibility of the optimum model while minimizing human bias and uncertainty. The workflow has been implemented in a Marcellus Shale reservoir with over 1,500 wells to determine the optimal well spacing and completion design parameters for both the field and each well. The results show that using a shorter stage length (SSL) and a higher sand-to-water ratio (SWR) is preferable for this field, as it can increase cumulative gas production by up to 8%. Additionally, it is observed that fifty-percentile cumulative gas predictions are in close agreement with actual field productions. Thematic collection: This article is part of the Digitally enabled geoscience workflows: unlocking the power of our data collection available at: https://www.lyellcollection.org/topic/collections/digitally-enabled-geoscience-workflows

This paper is the inaugural installment in a series of white papers on current completion best practices. It summarizes key insights from notable SPE papers focused on perforation strategy for multistage hydraulic fracturing in horizontal wells completed in unconventional shale reservoirs (UCR). Our objective in this series is to provide a reference guide for helping engineers, particularly those new to unconventional completions, better understand best practices and technical considerations. Recent papers have highlighted the importance of key mechanisms such as limited-entry perforation friction, near-wellbore flow dynamics, perforation erosion and zonal isolation. All impact the distribution of fracturing fluid and proppant along the lateral. Insights from these papers have reshaped how the industry approaches perforation design. This paper draws from this knowledge base as well as the personal experience of the authors. Items covered in the paper include limited-entry perforating, perforation cluster spacing and density, and oriented perforating. We also reference laboratory research, yard tests, computational modeling and field surveillance such as perforation imaging, sealed wellbore pressure monitoring (SWPM), and fiber-optic-conveyed distributed acoustic and temperature sensing (DAS, DTS) to present a comprehensive overview.

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Hydraulic fracturing, a completion technique involving multi-stage treatments, is widely used to extract hydrocarbons from unconventional reservoirs. Microseismic monitoring is commonly used to evaluate the hydraulic fracturing effectiveness and conformance, but interpreting this data to assess stimulated reservoir volume (SRV) and fracture geometry remains challenging. This paper introduces techniques to enhance microseismic interpretability and link results to completion parameters. By referencing the microseismic hypocenters to their corresponding fracture injection point, the resulting image gains depth, clarity, and enhanced meaning. Additionally, a probabilistic approach produces time-lapse snapshots of fracture propagation, offering dynamic insights into stimulation evolution. Data from the Hydraulic Fracturing Test Site (HFTS-1) in the Midland Basin, Texas, were analyzed, comparing completion designs with varying perforation clusters, proppant, and fluid intensity. Results indicate that the cluster design and fluid/proppant intensity significantly influence SRV generation. A three-cluster-per-stage design [90 ft (27 m) spacing] creates approximately a 200% larger stimulated rock area (SRA) than a five-cluster design [53 ft (16 m) spacing], attributable to the larger fluid/proppant volumes per cluster, driving enhanced fracture expansion. Time-lapse microseismic event maps correlate strongly with cored intervals containing hydraulic fractures and dyed proppant packs, whereas the conventional stacked heatmap fails to effectively locate the proppant pack. This work emphasizes the importance of data preparation and mapping techniques to characterize the SRV characteristics (e.g., fracture geometry, spatial distribution, half length, height, growth direction), providing insights to optimize well spacing and completion designs. The dynamic fracture progression revealed by time-lapse analysis offers profound perspectives undetectable through static microseismic methods.

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The development of unconventional resources continues to be propelled by innovations that enhance economic efficiency and maximize reservoir contact within operational constraints. Among the most recent of these is the U-shaped, or “horseshoe,” well design, which connects two parallel horizontal laterals with a 180° turn, effectively doubling the reservoir exposure from a single wellhead. This paper provides a comprehensive literature review of the current state of knowledge on U-shaped well technology. It surveys the operational drivers for their adoption, the critical drilling, and completion technologies that have enabled its successful implementation and discusses key design considerations for a successful operation. Field data from major North American shale basins, including the Permian, Eagle Ford, Bakken, and Haynesville, demonstrate substantial economic benefits, such as capital cost savings of approximately 20–25% compared to traditional methods. Lifecycle assessments indicate notable environmental advantages, including a 29.3% reduction in carbon emissions, a 15.8% reduction in water use, and a 50% decrease in land disturbance. Despite these clear benefits, gaps remain regarding long-term performance validation, stimulation of curved sections, and fracture modeling accuracy. Addressing these gaps is essential to fully realize the potential of U-shaped wells as a sustainable and economically attractive approach in the evolving landscape of unconventional energy development.

While hydraulic fracturing is not a new technology or a new process, recent efforts to improve our understanding of hydraulic fracturing completion techniques by both private operators as well as consortium projects have provided significant information that does not agree well with any of our current simulation and modeling tools. Specifically, the number of fractures observed when coring through the stimulated region between wells shows that there are many more fractures being created than industry models predict. To date the industry has been attributing this very complex fracture behavior as interaction between the created hydraulic fracture and pre-existing natural fractures. When trying to duplicate the results observed in these experiments, however, it is not feasible to generate the degree of complexity observed using conventional fracture modeling techniques. We also have not seen the high natural fracture density in image logs that would support the number of fractures observed. To help understand this problem, the authors found it necessary to revisit the fundamental stress models and reassess several assumptions that have been made in the petroleum industry. In doing this it was found that the complexity of the stress and pressure interaction between different fractures and fracture swarms, stages and multiple wellbores is very significant. Not only are we adding a huge amount of compressive stress to the system, but we are also significantly altering the regional pore pressure regime and essentially creating a very complex and stress altered multi porosity system that behaves very differently from the theories used to predict conventional hydraulic fracture systems alone. While the industry talks about primary stress and principal stress rotation resulting in changing the preferred direction of hydraulic fractures, in these complex stress situations it can be shown that the concept of primary stress is an oversimplification that does not adequately capture the complex stress state of the rock when there is significant stress and pressure interference between multiple fractures and wells. The combination of compressive stress and shear becomes important and more complex, and multimode failure criteria must be considered that include Mode 1 (tensile), Mode 2 (shear) and Mode 3 (out of plane shear). While the intense microseismic activity observed in many of these projects clearly indicates the presence of shear failure, the authors will show that these Mode 2 shear failures can cause additional Mode 3 failures that can be described as out of plane shear failure or shear induced tensile failures. It is believed that the high density of observed fractures is the result of this multimode failure condition and that many of these fractures will remain in a compressed state until after the primary fracturing treatment is completed, at which time they will dilate and start to accept fluid, which also explains why there is not much proppant found in many of the observed fractures in the core-through experiments. The authors will present new fracture diagnostics interpretations that will support this theory, and discuss how this added knowledge may enable us to improve completions designs in the future by accounting for the total energy applied to a specific volume of rock and how this can be used to help understand extent of rock failure and the constraints or limits that must be considered when trying to optimize a complex multi well system.

The North Kuwait Jurassic Gas asset holds strategic importance for Kuwait's production strategy as it includes the only non-associated gas-producing fields in the country. Multistage completion technology has been implemented since the early development stages in 2009, with expansion starting 2019 in deviated wells. This paper demonstrates the added value, experience, challenges and lessons learned from the recent application expansion in deep, challenging, long horizontal wells in Jurassic unconventional reservoirs. This approach enhances overall well production potential and intervention operation efficiency through selective stimulation, overcomes reservoir and intervention operations challenges, and ensures early production delivery. These factors are crucial for achieving the asset's strategic production target by 2026. The Jurassic gas asset primarily produces from deep, high-pressure, high-temperature, conventional and unconventional tight carbonate reservoirs. Recovery from these complex, heterogeneous reservoirs is extremely challenging if conventional development strategies are applied. Due to the high reservoir tightness, permeability contrast among different flow units, and dual permeability effect (matrix and natural fractures), well productivity potential significantly depends on the effectiveness of subsequent stimulation treatments to improve well productivity and connect the natural fractures. This is especially important in nano-Darcy Najmah carbonate reservoirs, where development is set for horizontal wells with selective multistage stimulation. Najma Limestone (NJ-LS) is a tight gas-condensate reservoir with typical porosity ranging from 2 to 9% and very low matrix permeability (~0.01mD), with primary production through natural fractures. To increase the chances of success in encountering fracture corridors, long drain-hole horizontal wells were deemed necessary. Multistage open-hole completion has been considered as the primary completion option in these NJ-LS horizontal wells. The asset team has implemented a step change in completion strategy by adopting open-hole HPHT multistage drop-ball completions using state-of-the-art MSC technology. This includes closable frac ports, a full 3.5in monobore post milling, and a debris sub to protect the MSC string during upper completion operations. This approach addresses reservoir complexity, eliminates wellbore cleaning and multiple perforation intervention challenges and risks, resolves cement quality uncertainties, improves overall cost, and accelerates well delivery to production. This significantly reduces operation time from approximately one month using the plug-and-perf technique to less than one week with continuous and fewer subsurface intervention operations, particularly in deep, long horizontal wells. An integrated asset team has developed a structured workflow for multistage design, planning, and running protocol, incorporating best practices and lessons learned. A total of nine (9) new multistage completions were successfully installed in Jurassic deep horizontal wells over the last two years in the unconventional Najmah reservoir, ranging from four to thirteen stages, including selective acid stimulation. The production results were mixed due to the uncertainty of reservoir natural fractures. Based on experience gained from highly deviated wells (47wells) and more recently in long horizontal wells (9 wells) as of July 2024, an integrated protocol for multi-stage candidate well selection, staging design and installation procedures has been developed by the integrated multidisciplinary team. This ensures a standardized process across fields and can be applied for other assets.

The primary objective of this study is to thoroughly assess the influence of various completion, fracturing stimulation, and intrinsic reservoir properties affecting productivity of ten major unconventional oil and gas plays while uncovering key insights and emerging trends unique to each play. We examined a dataset comprising of 91,519 horizontal wells that began production on or after January 1st, 2015, across ten major unconventional oil and gas plays (Bakken, Delaware, Duvernay, Midland, Eagle Ford, Scoop|Stack, Haynesville, Marcellus, Montney, and Utica) in North America. The analysis centered on four main aspects: well fracturing, downhole consumables, production, and geological properties. The horizontal and vertical well spacings were based on the horizontal and vertical distance between the target wellbore and its closest near neighbor in any zone, respectively. The wells were classified as parent, child, or co-completed based on the distance and timeframe between their completion. The Bakken-US play shows the most remarkable increase in normalized production per 1000 ft of lateral, almost doubling from 2015 to 2024, while Scoop|Stack experienced a decline in normalized production. Bakken and Montney, with high TOC, had low normalized productivity, whereas Utica, despite low TOC, was highly productive, underscoring completion quality's importance over organic quality. Although high brittleness is usually seen as beneficial for promoting fracturing, it is intriguing to note that plays with fewer wells per pad (e.g., Scoop|Stack) exhibit a higher growth rate of fractures, even when they have a lower brittleness index (median < 0.34). Horizontal spacing plays a crucial role in optimizing performance. Less productive plays benefit from denser development. Co-completed wells outperform other sequencing, indicating their ability to mitigate "frac hits" or fracture-driven interactions. Longer laterals offer better resource contact, but productivity does not increase linearly. Sand remained the predominant proppant used in all plays due to cost-effectiveness. Freshwater remains the dominant frac fluid across all plays, and slickwater frac jobs consistently yield high productivity. The type of chemicals in terms of their dominant use varies across plays, but the trend in each play is largely unchanged since 2015. The number of clusters per stage varies across plays, and increasing the number of clusters may not always lead to enhanced productivity due to the stress shadowing effect. This study offers important insights into factors affecting productivity in shale plays, aiding future well development and resource extraction optimization. It provides technical guidance for unconventional oil and gas developments in North America and is a useful reference for similar projects globally, including in China.

The staged and layered fracturing technology plays an important role in unconventional tight reservoirs. And the gas well fracturing and completion integration is the core component to realize the fracturing and completion integration process, which can realize the integration of acid fracturing and later drainage production so as to reduce the secondary pollution to the reservoir. The packer rubber barrel’s performance directly affects the long-term effective sealing reliability itself in high temperature and high pressure environment. In this paper, the constitutive model of rubber tested from high temperature and high pressure curing kettle to simulate the high-temperature and highly corrosive environment of the formation. On this basis, the structure of the packer’s shoulder and the protective ring of the rubber barrels are optimized through Abaqus to reduce its stress failure under high pressure, and its corrosion resistance is improved by improving the rubber material. The sealing performance of the packer rubber cylinder under the field underground requirements is tested through laboratory evaluation test and field test. The results show that the protective ring and rubber tube shoulder at 30° angle are a reasonable result of optimization, and the optimized packer can meet the requirements of 154 °C temperature resistance, 79 MPa pressure bearing and long-term effective sealing. The successful development of packer rubber and the integrated analysis process can lay a solid foundation for the realization of integrated fracturing and completion process for exploration and development of deep volcanic or carbonate reservoirs.

Low-permeability coal seam gas (CSG) reservoirs are a significant worldwide, unconventional resource for the future. In low-permeability coals, a diagnostic fracture injection test (DFIT) has been identified as the most applicable method to characterise low-permeability CSG reservoir permeability based on the inherent limitations of conventional transient testing methods. Further, determining permeability anisotropy can assist development in spacing wells or evaluate completion technologies, such as fracture stimulation, horizontal wells and multistage hydraulic fracturing from horizontal wells. This paper uses representative interburden and coal reservoir properties from a Bowen Basin case to properly define an area and develop a working hydraulic fracturing model. This model can generate a series of fracture realisations, varying bulk permeability and pressure-dependent leak-off (PDL) values to provide scenarios for later multi-well interference test analyses. Previous studies have noted that a pressure-dependent permeability (PDP) capable reservoir simulator can be used to model and history-match the after-closure period and better constrain the reservoir model for forecasting PDP effects. Finally, a multi-well DFIT/interference test programme can be evaluated using techniques to back analyse the bulk permeability and anisotropy and establish the optimal well spacing between the DFIT and observation wells. This paper presents a holistic workflow and guidelines for implementing multi-well DFIT/interference testing for low-permeability CSG fields. It can also be applied to higher-permeability coals where compartmentalisation or permeability anisotropy is not aligned with the current, localised stress regime.

Engineering Visual Presentation E04 Low-permeability coal seam gas (CSG) reservoirs are a significant worldwide, unconventional resource for the future. In low-permeability coals, a diagnostic fracture injection test (DFIT) has been identified as the most applicable method to characterise low-permeability CSG reservoir permeability based on the inherent limitations of conventional transient testing methods. Further, determining permeability anisotropy can assist development in spacing wells or evaluate completion technologies, such as fracture stimulation, horizontal wells and multistage hydraulic fracturing from horizontal wells. This paper uses representative interburden and coal reservoir properties from a Bowen Basin case to properly define an area and develop a working hydraulic fracturing model. This model can generate a series of fracture realisations, varying bulk permeability and pressure-dependent leak-off (PDL) values to provide scenarios for later multi-well interference test analyses. Previous studies have noted that a pressure-dependent permeability (PDP) capable reservoir simulator can be used to model and history-match the after-closure period and better constrain the reservoir model for forecasting PDP effects. Finally, a multi-well DFIT/interference test programme can be evaluated using techniques to back analyse the bulk permeability and anisotropy and establish the optimal well spacing between the DFIT and observation wells. This paper presents a holistic workflow and guidelines for implementing multi-well DFIT/interference testing for low-permeability CSG fields. It can also be applied to higher-permeability coals where compartmentalisation or permeability anisotropy is not aligned with the current, localised stress regime. To access the Visual Presentation click on the link on the right. To read the full paper click here

This paper presents a calibration and optimization workflow using a fully coupled hydraulic fracturing, reservoir

Growth in a number of newly drilled wells in unconventional reservoir development results in tightly spaced horizontal wells, which consequently creates well interference (fracture hits) between parent and infill wells as a result of stress redistribution from localized pressure sink zone in parent wells. This directly affects the production performance of both parent and infill wells. In order to minimize this effect, it is sometimes more preferable to place an infill well in a different pay zone. However; due to poroelastic effect, pressure depletion from the parent well also affects stress distribution in different pay zones and yet only a few literatures focus on this effect. The main objective of this paper is to predict temporal and spatial evolution of stress field for Permian basin using an in-house 3D reservoir-geomechanics model and propose guidelines for determining lateral and vertical drilling sequence of infill wells to mitigate well interference. Embedded discrete fracture model (EDFM) is coupled with a sequentially coupled reservoir-geomechanics model to gain capability in simulating complex fracture geometries and high-density fracture system. Different scenarios with and without natural fractures were studied including a case where two parent wells are located in different layers (Wolfcamp A2 and B2) and a case where two parents are located in the same layer (Wolfcamp A2 and B2). Stress redistribution is then observed to determine the completion sequence of infill wells in different layers. Producing two parent wells in the same pay zone results in large stress redistribution mostly in the area close to fracture tips at an early time. As time progresses, stress redistribution area becomes larger and covers almost entire infill well zone in Wolfcamp B2. Stress changes can also be observed in Wolfcamp A2 and A3 despite producing wells are only located in Wolfcamp B2. However, when producing two parent wells in different pay zones, stress redistribution can only be observed near fracture tips in both Wolfcamp A2 and B2 with minimum stress change in the infill zone even at a later time in all Wolfcamps A2, A3, and B2. This allows the possibility of producing infill well in the un-depleted layers (i.e. A3) enhancing efficiency of infill well completion. Fracture penetration and larger fracture length also play a significant effect in stress reorientation and evolution. Presence of natural fractures causes stress reorientation to occur at an earlier time due to higher depletion rate. This paper presents the possibility of changing the sequence of stacked pay from lateral well layout to vertical well layout in order to mitigate well inference and improve production performance of both parent and infill wells. Less stress change in the infill zone for vertical well layout makes it become superior to lateral well layout in which large stress redistribution can be observed.

Most operators currently rely on decline curve analysis or data-driven methods to forecast the production of unconventional wells. These approaches are fast enough to handle thousands of wells but are not well suited for new well designs (longer laterals, refracs, etc.) or changing operating conditions (surface constraints, artificial lift). This paper proposes a new methodology to forecast unconventional wells that integrates reservoir simulation within a data-driven workflow to overcome these limitations. The forecast is provided by a single-well reservoir simulation model that includes the key physics needed for a robust prediction but simple enough to be computationally efficient. A data-driven engine is used to automatically create a model for each well based on its geologic, drilling, completion and production parameters. For each producing well, an automated algorithm is used to calibrate the model to the well production history. This creates a dataset of prior input parameters and corresponding calibrated model parameters for all producing wells. The model-building engine is then calibrated to this dataset so it can be used to automatically generate pre-calibrated models for undrilled wells. Three technical aspects of the approach are presented in this paper. First, we review and contrast the two types of simulation models that were considered: a two-dimensional quarter-fracture model and a one-dimensional model in Diffusive-Time-Of-Flight space. Second, we describe the various automated history-matching procedures that were tested (pattern search, genetic algorithm, particle swarm optimization and proxy-based gradient-descent) and compare their respective performance in terms of robustness and number of function evaluations. Third, we explain the automated model-building engine and its calibration process. The proposed methodology offers a way to forecast production from unconventional wells at scale and enables various operating strategies to be evaluated. Different forecasts can be built to compare flowback scenarios, artificial lift options or surface facility constraints. The novelty of the methodology resides in the practical combination of well-established technical elements to solve the business problem of physics-based production forecasting for unconventional wells. A key benefit of the proposed workflow is that the forecasting models created can also serve to diagnose subsurface characteristics and well behaviors. The models are fully explainable, and the history-matched parameters can be mapped to offer a production-corrected view of subsurface parameters. The paper concludes with a description of how these 1D or 2D individual well models can eventually be combined into a single 3D reservoir simulation model that integrates hundreds of wells, their lift system and associated production facilities, providing a path for basin-scale physics-based integrated simulations.

Unconventional wells with long laterals have great potential to further extend their lateral length to maximize reservoir contact. Torque and drag simulation and operational observations showed that current design suffers extreme drag, resulting in buckling-risk and insufficient hook load to run a completion to target depth. This paper highlights the achievement of running completions in the longest lateral wells (12,000 ft lateral) using a floatation collar for unconventional drilling. Buoyancy technology, specifically the floatation collar tool, was deployed within a 45-90° inclination. This device traps air between the floatation sub and the shoe, reducing the frictional forces acting on the casing through buoyancy effects. The floatation collar has a calibrated glass barrier, which is ruptured with surface applied pressure once the casing reaches the target depth, allowing suitable well circulation prior to the cementing operation. The floatation collar placement is optimized for maximizing the hook load available while crossing the curve section that has the highest dogleg severity. Using the floatation collar tool with the original completions and casing design across 12,000 ft of lateral length was successfully achieved. This is the longest horizontal drilled section for partial cementing of long string applications to date. Furthermore, multiple positive attributes were observed, including smooth deployment of the drill string over a curve section of a 7 deg/100 ft dogleg while the string reaches the bottom without lockup. In addition, the compressive forces improved by approximately 88 Klbf in comparison to simulated actual value with a mud weight of 12.83 ppg when the floatation collar (rated with 8000 psi) was placed within the mentioned inclination. These results were all accomplished while still maintaining the original casing design, and allowed for the possibility of more extended reach laterals. This method significantly improves the probability of reaching the target depth in challenging wells, while maintaining the original completion and casing design. This paper illustrates the benefits of utilizing a floatation collar to overcome the challenges of reaching the target long-lateral wells when running completions, by minimizing the risk of buckling and reducing the drag forces on the casing. Hence, the running time and cost of the well are reduced significantly.

Summary In this study, we conducted an analysis of reservoir quality and completion quality indicators for Carlile Shale using data from a well at Teapot Dome, Wyoming, to determine its suitability for production simulation. The method was based on creation of reservoir quality (RQ) and completion quality (CQ) flags over the interval of the shale body to establish minimum cut-offs as an unconventional resource. Intervals in which both flags equal 1 will give a value of 1for the product of RQ and CQ known as RQC (reservoir quality and completion). Results from this example showed that the average shale thickness is approximately 240 ft., and the shale volume fraction is between 0.40 and 0.80. The quantity of shale hydrocarbon potential is indicated by the average TOC value of 0.08 w/w. Based on reservoir and completion quality assessment using the binary RQ and CQ flags, the Carlile Shale in this part of Teapot Dome was found to have good RQ in the upper section of the shale body, but the CQ was generally poor. This result suggested that the potential for an economic success during hydraulic fracturing is negligible.

Hyperspectral core imaging is a non-destructive, infrared-wavelength technology traditionally used by mining operators as a method of identifying key lithological facies and mineral textures and alterations. An emerging technology with respect to Oil/Gas exploration, when integrated with traditional lab analyses and petrophysical methods hyperspectral core imaging will refine interpretations to accurately identify drilling and completion hazard as well as reservoir and fracture propagation models. Incorporating additional lab analyses such as X-ray diffraction, porosity/permeability analysis, rock mechanics, organic geochemistry, and thin sections interpretation along with hyperspectral imaging can clarify previously tenuous evaluations associated with well log responses in unconventional shale or carbonate plays. By providing high-resolution images of mineralogy in relation to depositional fabric and textures within continuous conventional core, hyperspectral imaging allows for a more inclusive, cohesive grouping and correlation between log-derived electrofacies and sedimentological facies. Strengthening this correlation will increase the capacity to identify drilling and fracking hazards that can cause costly rig delays, including well instability and bit-deviation. Differential cemented facies, recrystallized bedding or the widespread occurrence of expandable smectite are all common origins of drilling and fracking risks that can be better understood and mitigated by integrating hyperspectral imaging with traditional energy exploration techniques. Hyperspectral imaging is invaluable when developing models to characterize specific lithology packages. In turn, these packages are used to identify potential horizontal landing zones, hydrocarbon pay zones, drilling and completion hazards (borehole stability, and fracking hazards) and flow barriers, ultimately reducing cost and increasing production. For example, hyperspectrally-defined lithological packages combined with density and resistivity logs can reveal potential flow barriers that in other wells had remained undetected. Hydrocarbon pay zones can be defined by the lithological packages where hydrocarbons and hydrocarbons enmeshed with other minerals are detected by hyperspectral imaging. This same method of classification is used to evaluate cores in producing wells for behind the pipe pay to be further pursued or to validate new calculations of reserve estimations.

Multi-well systems are essential for unconventional asset development by optimizing the reservoir drainage, well productivity, and cumulative recovery to maximize the economics of the project. Although the underlying principles of infill drilling and multi-well production is the same as that for conventional reservoirs, in unconventional reservoirs, the contrast between the stimulated and unstimulated volumes (SRV and ORV, respectively) of the reservoir, differences in well completions and resulting SRV vs. ORV properties, asynchronous start of production, different production conditions, and unmatching schedules of production and shut-in periods further complicate the design (the spacing, completion, and production conditions) of the multi-well systems. Moreover, development decisions are usually made with uncertainties caused by the complexity of well-interferences in the existence of extreme reservoir heterogeneity. Therefore, to make multi-well unconventional reservoir development decisions, both the knowledge of the interwell reservoir characteristics and their effect on the multi-well productivity of the system must be known. These requirements call for models that are accurate and efficient for estimating reservoir and completion parameters by pressure- and rate-transient analysis (PTA and RTA, respectively) and capable of efficiently evaluating multiple development scenarios subject to the uncertainties of reservoir characteristics. We have developed robust semi-analytical models to analyze the performances of multi-well systems in single and multi-layer completion conditions in unconventional reservoirs. This paper discusses the diagnostic features of pressure- and rate-transient behaviors of multiple wells in single- and multi-layer unconventional-reservoir, delineates the sensitivities of well performances to well spacing, stimulation treatment, and production conditions of interfering wells, and demonstrates the application of the models to PTA and RTA of field cases. The PTA/RTA methodology presented in this work consists of obtaining initial estimates of the well completion and reservoir properties through diagnostic and straight-line analysis of specific flow regimes, guided by the multi-well solution, and refining the estimates by matching the transient well responses by the semi-analytical model. This methodology provides a remarkably efficient and reasonably accurate estimation of properties within the bounds of the system uncertainties.

There is a strong global demand for oil and gas resources, and forecasts indicate robust growth in oil demand in the coming years. Meeting this demand necessitates the exploitation of unconventional resources and enhancing the recovery of existing oil and gas fields. Field trials indicate that traditional gas injection in shale wells has low sweeping efficiency. Emerging technologies play an exceedingly significant role in solving the challenges of gas EOR in shale and tight formations. Among these advancements, smart or intelligent well technology has emerged as a promising solution to enhance field development outcomes. This study focuses on improving gas flooding efficiency in the Bakken formation by utilizing smart completions to reduce the gas–oil ratio (GOR) and increase oil recovery. An economic assessment of gas re-injection is conducted, considering both gas storage and enhanced oil recovery, with analysis incorporating capital expenditures, operating costs, and revenue from increased production. Reservoir simulations were employed to determine the most effective gas injection scenarios for maximizing recovery and storage efficiency. Simulation results demonstrate that 20% of perforated laterals account for 80% of the injected gas. To address this challenge, this work proposes using smart completions to segregate lateral sections, thereby optimizing gas injection efficiency, and unlocking additional oil in tight formations. Segregating horizontal laterals for gas re-injection using smart completion technology can achieve gas injection efficiencies of up to 0.25 barrels per Mcf of gas injected, with lower incremental gas production. The optimal injection rate is between 1 MMcfd and 3 MMcfd, with an injection period ranging from one to three years. It was also found that injecting gas into the toe section results in high bottom hole pressure but lower oil recovery due to reduced gas injection efficiency. From an economic perspective, the project yielded favorable outcomes, with a positive net present value (NPV) at a 7% discount rate. Even at lower oil prices (USD 50 per barrel), the Internal Rate of Return (IRR) was calculated to be 170%, indicating strong potential profitability.

Permanent magnet motors (PMM) have been around for two decades in the electrical submersible pumps (ESP) industry. PMM are shorter-lighter-higher power density in design and offer more than just energy savings with reduced carbon footprint; it is a technology enabler to achieve asset optimization and yet is underutilized. This paper discusses the early reporting on the first company organic PMM safely installed in a Permian Basin unconventional resource well to extract more reservoir production. The benefit to the reader is stronger confidence to apply this green technology in their wells safely and economically. To achieve sustainable first use of PMM, the ESP design and safety implications required collaboration of disciplines involving teams of Instrumentation & Electrical, Production and Completion engineers, the ESP Center of Excellence, the Technical Center, Health-Safety-Environmental, and a variety of vendors over a 2-year period. Pump design and drawdown scenarios were examined while multiple safety trainings were conducted, including live demonstrations with PPE, proving the safe mitigation of hazardous voltage through proper shunting, grounding, and isolating standard operating procedures. Additionally, multiple safety devices were added (surface and subsurface) to manage the safety aspects of this technology. A final risk assessment was conducted and approved to clear the way for PMM installation. Compared to the conventional induction motor, the PMM enabled nearly 50% more power downhole for equal fluid density, comparable production and water cut without a change in pump design. Energy savings and carbon footprint reduction is 19%. Since installation, the ESP system has reduced head pressure more than 300 psi and continues to see increased production. Standard operating procedures for PMM were executed successfully and safely without incident using the free hub second source power mitigator. Four electrical technologies are included in this paper for safety of personnel and the asset as PMM bring the risk of electrical shock due to two sources of power: planned power from the grid and unplanned power from the well; the latter case the PMM is a generator and this risk is mitigated with the use of both completion and production tools such as the free hub. Additionally, the non-intrusive power measurement technology at the surface keeps personnel safe from arc-flash and electrical shock without the use of cumbersome CAT-2 PPE, a health risk in hot climates. A contactor switch at the surface helps to protect life and asset. Lastly, a common mode filter was run for carrier frequencies less than 4000 Hz to reduce or eliminate high frequency induced failures such as bearing fluting.

As an important unconventional gas resource, shale gas has become an important part of gas production in recent years with the advantage of horizontal well drilling and large-scale multi-stage hydraulic fracturing completion technologies. The shale gas reservoir numerical simulation advances were reviewed and a multi-stage fractured horizontal well numerical simulation was performed to qualitatively modeling the well productivity in over-pressured shale gas reservoir based on actual shale properties and well completion parameters. A single horizontal well model was established on the basis of dual-porosity model and logarithmically spaced grid refinement. A comprehensive comparison and analysis of the initial average gas production, daily gas production, cumulative gas production, adsorbed gas and free gas cumulative production were provided to investigate the influence of matrix permeability, SRV permeability, hydraulic fracture conductivity and half length, SRV size, bottomhole pressure on the well performance. The research shows that for the high matrix permeability (Km > 10−7 mD) and low SRV permeability (KSRV < 0.01 mD), the SRV permeability has a significant impact on the initial average gas production. For the high matrix permeability (Km > 10−7 mD) and medium SRV permeability (0.01 mD < KSRV < 0.5 mD), the initial average gas production is controlled by both the matrix and SRV permeability. For the high matrix permeability (Km > 10−7 mD) and high SRV permeability (KSRV > 0.5 mD), the initial average gas production is mainly controlled by the matrix permeability. When the matrix permeability is lower than 10−9 mD, the cumulative gas production is too low to be of economic interest. For the matrix permeability (10−9 mD < Km < 10−5 mD), the matrix permeability and SRV permeability are all important factors that influence the cumulative gas production. For the matrix permeability (Km > 10−5 mD), the matrix permeability has much more impact on cumulative gas production than that of SRV permeability. The daily gas production and cumulative gas production are independent of hydraulic fracture conductivity and half length. The initial gas production of multi-stage fractured horizontal well is also independent of SRV sizes. The SRV size mainly controls the gas production decline characteristic. With the increase of the SRV size, the daily gas production declines slowly. The SRV size determines the cumulative gas production directly. With the increase of the SRV size, the cumulative gas production increases linearly. The bottomhole pressure has a significant impact on cumulative gas production. With the decrease of the bottomhole pressure, the cumulative gas production of 20 years increases linearly.

Fracture-driven interaction FDI (colloquially called “Frac-hit”) is the interference of fractures between two or more wells. This interference can have a significant impact on well production, depending on the unconventional play of interest (which can be positive or negative). In this work, the surrogate model was used along with metaheuristic optimization algorithms to optimize the completion design for a case study in the Bakken. A numerical model was built in a physics-based simulator that combines hydraulic fracturing, geomechanics, and reservoir numerical modeling as a continuous simulation. The stress was estimated using the anisotropic extended Eaton method. The fractures were calibrated using Microseismic Depletion Delineation (MDD) and microseismic events. The reservoir model was calibrated to 10 years of production data and bottom hole pressure by adjusting relative permeability curves. The stress changes due to depletion were calibrated using recorded pressure data from MDD and FDI. Once the model was calibrated, sensitivity analysis was run on the injected volumes, the number of clusters, the spacing between clusters, and the spacing between wells using Sobol and Latin Hypercube sampling. The results were used to build a surrogate model using an artificial neural network. The coefficient of correlation was in the order of 0.96 for both training and testing. The surrogate model was used to construct a net present value model for the whole system, which was then optimized using the Grey Wolf algorithm and the Particle Swarm Optimization algorithm, and the optimum design was reported. The optimum design is a combination of wider well spacing (1320 ft), tighter cluster spacing (22 ft), high injection volume (1950 STB/cluster), and a low cluster number per stage (seven clusters). This study suggests an optimum design for a horizontal well in the Bakken drilled next to a well that has been producing for ten years. The design can be deployed in new wells that are drilled next to depleted wells to optimize the system’s oil production.

The Bone Spring Formation in the Delaware Basin has more than 23,000 economic drilling locations remaining in the basin. How do you identify and high-grade those remaining drilling opportunities? While spacing and completion still matter, the best wells will be in the right facies within the desired bench. This study demonstrates a methodology for building a predictive tool to assess remaining drilling locations by employing a multivariate analysis on geological and geophysical data to delineate areas of optimal reservoir properties. This analysis focuses on the Leonardian-age clastics, carbonates and shales of the 2nd and 3rd Bone Spring Sand in a study area in southern Lea County, NM. The goal of this study was to accurately predict the first 12-month BOE and first 12-month water using a multivariate model comprised of data from wireline logs and rock properties derived from 3D seismic data. The most significant subsurface variables for predicting hydrocarbon production are Phi-H, sonic, impedance, temperature, and TOC; for water production the important variables are Phi-H, total water saturation, and clay volume. The sweet spot is not controlled by one variable, but by understanding the optimal mix of these properties. This approach demonstrates a predictive workflow for quantifying the local impact of facies and property variation on well performance that can be used quantitively for forecasts, lookbacks, and scenario evaluations.

Horizontal well fracturing has become a key completion and stimulation technology for unconventional reservoirs. In reservoirs with well-developed natural fractures and faults, high-intensity reservoir stimulation significantly increases the probability of fault slip induced by artificial fractures, leading to casing deformation. To prevent casing shear deformation caused by hydraulic fracturing, numerical simulations were employed to predict casing deformation risk points and develop mitigation measures. Taking the 2H well group as a case study, a geomechanics-engineering integrated model and ant tracking technology were used to identify casing deformation risk points. The Mohr-Coulomb criterion and optimized fracturing parameters were then applied to effectively mitigate these risks. The results show that the integrated geomechanics-engineering model combined with ant tracking technology can effectively identify faults and natural fractures encountered along wellbore trajectories, predicting casing deformation risk points in the 2H well group. By utilizing the Mohr-Coulomb criterion, the critical pressure of fault activation and slip was determined to be 72.5 MPa. During the fracturing operation of the 2H well group, a "reduced displacement + reduced scale" strategy was implemented, and no casing deformation occurred during the fracturing process. A casing deformation risk prediction and prevention technology was developed, with key mitigation measures summarized as follows: (1) Avoid drilling in areas with high fault activation and slip risk; if avoidance is impossible, select locations as far from fault centers as possible. (2) Optimize wellbore parameters and adjust wellbore orientation to reduce shear stress acting on the casing, thereby mitigating deformation. (3) Optimize fracturing parameters by increasing the avoidance perforation distance, reducing single-stage fracturing pressure, and increasing stage length to effectively lower casing deformation risk. This technology effectively ensures the safety of horizontal well fracturing, enhances reservoir stimulation efficiency, and provides technical guidance for casing deformation prediction and prevention measures.

As most readers can appreciate, stimulation of a multi-staged fractured horizontal well requires the injection of a water/slurry, combined with proppant, to create a fracture network for fluid flow to the wellbore. After this stimulation and general completion activities, much of the injected fracture fluid, along with reservoir fluids, are produced by virtue of drawdown and a declining flowing bottom hole wellbore pressure over the well's life. The well's production life naturally adheres to the law of "material balance" under all circumstances. This paper captures this flow physics from fracture flowback to online production all while establishing a novel relationship of the fracturing fluid and the produced reservoir hydrocarbons. Leveraging existing collected data, this proposed methodology can reliably forecast the primary phase of the reservoir for 10 years or more even with as little as 6 months of production history being used. More than 4500 tight/shale oil wells from both the Canadian and US shale plays (Bakken, Montney, Duvernay, Barnett, Eagle Ford, Permian) that have at least 10 years of production history have been tested and validated employing a ‘hindcasting’ technique. Thus, these case studies provide data-based evidence to compare actual field production data vs. the forecast from the novel proposed technique. The results from this study show that over 70% of the sample set of gas wells producing unconventional wells, all of which are limited to the first 6 months of production history, have 10-year forecasts within a 10% variance of field actuals. If 1.5 years of history is used, over 90% of the case study sample set have variances of 10% or less. For those oil producers using 6 months of history, over 80% of wells are within a 10% variance; however, with 1.5 years history also over 90% of the wells fall within 10% error. Conformance variances are very strongly dependent on data quality. In other words, where variances exceeded 10%, the historical production data was inherently very noisy and of low quality. Those wells are mostly attributed to some changing element of operating conditions. As in classical decline curve analysis, the historical operating conditions need to be maintained go-forward otherwise re-initialization would be required.

In shale reservoirs, one of the primary challenges is to properly understand and manage well-to-well connectivity to optimize the field development strategy. Interactions between wells are, to some extent, a desirable phenomenon, as their absence may introduce uncertainty regarding potential unstimulated and undrained areas of the reservoir. Assessing frac hits is essential at every stage of field development, and the earlier this understanding is gained, the better the completion design can be optimized. YPF has been systematically monitoring frac hits using wellhead gauges during fracturing operations over the past six years, as this low-cost, simple, and reliable data acquisition technique provides valuable insights into well performance and behavior across various contexts (pad configuration, completion designs, field depletion grade, etc.). Nevertheless, other technologies are also applied in unconventional formations to assess fracture-driven interactions (FDI) and improve the understanding of connectivity between nearby wells. This paper highlights the milestone of deploying the first disposable fiber optics in the Vaca Muerta play. In this application, fiber was installed in a confined well to monitor strain responses induced by fractures in adjacent wells, after varying fracture designs on the active wells. This study focuses on real-time responses monitored using fiber optics, assessing the behaviors observed under variations in design drivers in active wells, and evaluating the degree of correlation with wellhead gauge data. Across the monitored stages, fiber responses were observed in 80% of the cases. Preliminary findings indicate that varying volume per cluster significantly impacts interactions between sibling wells. Although this represents the first application of disposable fiber optics in the basin, it will certainly not be the last; and current (and future) applications will help to validate and complement the conclusions drawn from this and other studies. This becomes not only a technological leap, but also a symbolic transition: from interpreting indirect pressure signals, to illuminating the underlying mechanisms of fracture-driven interactions.

Hydraulic fracturing has been widely used to increase reservoir productivity in unconventional resources such as tight and shale oil/gas reservoirs. Estimating fracture geometry is important for optimizing development design, including the well allocation and completion. However, hydraulic fracturing is operated in the field at depths of 2,000 - 4,000 m below the surface, and direct observation is impossible. To address these challenges, we conducted a small-scale field experiment to visualize the spatial distribution and propagation characteristics of hydraulic fractures using coagulable fluorescence resin and analyzed the correlation with the distribution of Acoustic Emission (AE) hypocenters. A hydraulic fracturing experiment using the coagulable fluorescence resin (resin fracturing) was conducted against metamorphic bedrocks in the Kamioka mine, Japan, from 2022 to 2023. Following the resin fracturing in a 76 mm diameter vertical hole, a 205 mm diameter core was recovered through coaxial overcoring, aligned with the original resin-fracturing borehole. Then, the fractures filled with resin were visible on the surface of the recovered hollow core under black light (Takeuchi et al., 2025, Geosciences 15, 103). To investigate the feature of the extension of the fractures, six 205 mm diameter vertical cores were newly recovered continuously from the resin-fracturing hole towards the horizontal direction, where hydraulic fractures propagate based on the distribution of AE hypocenters in 2025. The vertical fractures with NE-SW trend created by resin fracturing were observed on the overcoring core. The extensions of NE-SW vertical fractures were also confirmed on the two cores drilled adjacent to the resin-fracturing hole. It was revealed that the vertical fracture did not reach the further northeastern region, where the AE hypocenters were not distributed. On the other hand, we observed the resin-filled fractures in the eastern region, where AE hypocenters were concentrated. Low dip angle fractures formed at a depth of 2.8 m, shallower than the injected section of resin fracturing at a depth of 3.3 m, were confirmed by the fluorescent resin filling. The extensions of these low dip angle fractures were confirmed by the presence of fluorescent resin seen in two cores drilled at the eastern area from the resin-fracturing hole, where AE hypocenters were intensively distributed. Our experiment of resin fracturing in the Kamioka mine successfully distinguished the fractures generated by hydraulic fracturing from the existing natural fractures. We revealed that the distribution of AE hypocenters around the resin-fracturing hole corresponds to the formation of vertical fractures. We also found that AE didn't always occur when resin filled pre-existing geological weak surfaces. However, AE was observed intensively in certain regions, such as the eastern area. This analogue study will contribute to improving the accuracy of hydraulic fracture evaluation using AE monitoring, that is, microsiesmic monitoring in field application.

Individual well performance in the Marcellus Shale of northeastern Pennsylvania varies markedly, even in areas where the lithology, fluid composition, and completion design are consistent. A primary reason for this is the natural fracture system, which influences hydraulic fracture growth, dynamic fluid flow, reservoir pressure and stress behavior. Chief Oil and Gas (Chief) contracted Schlumberger to conduct an integrated study using an innovative modeling approach to quantify the impact of these natural fractures and optimize field development. Working together, the team created an approach that consisted of constructing and coupling three models: a 3D geomechanical model, an unconventional fracture model (UFM), and a 3D dynamic dual-porosity model. The geomechanical model is composed of a discrete fracture network (DFN) containing both regional (J1 and J2 sets) and tectonic fractures. These are interpreted from seismic attributes (anisotropy azimuth, seismic velocity anisotropy) and ant tracking. The UFM model simulates the growth of hydraulic fractures and their interaction with natural fractures in the DFN. Portions of the natural fracture network are assumed to be open tectonic fractures, and their flow properties are adjusted (porosity and permeability) to match well performance. Adjustments are also made to account for production-related perturbations in dynamic stress magnitude and azimuth, which impact later wells. These modifications to the fracture network are critical for history matching the dual-porosity model. The production history match showed that hydraulic fractures and open tectonic natural fractures are key production drivers in the study area, and that the spatial variability of the natural fracture network exerts more influence on well performance than initially thought. The connection between the hydraulic fracture network and portions of the open tectonic natural fracture system enhances parent well access to larger drainage areas. This controls the strongly variable well production observed in the study area. Subsequent stress perturbation resulting from parent well depletion is detrimental to the completion efficiency of the child wells, even even though they have better frac designs with higher proppant loading. The modeling work also shows that the gas-in-place is consistent with volumetric and rate transient analysis (RTA) estimates. The coupling of the three models reasonably approximated changing reservoir conditions and created a nexus of domain expertise including geology, geophysics, geomechanics, stimulation, completions engineering and reservoir engineering. This enabled an understanding of the complex reservoir behavior of the naturally-fractured Marcellus Shale and generation of an optimized fit-for-purpose development plan. Chief was already implementing changes in spacing and increasing the distance between offset PDP (Proved Developed Producing) wells and this study affirmed that revised development plan.

It has been proved that the well production in unconventional reservoirs is controlled by reservoir quality and completion quality. The lateral heterogeneity is influenced by the structural complexity, fracture distribution, and facies variation. The fracture evaluation is one of the key elements for optimizing completion design and multiple stage hydraulic fracturing operations. High-resolution borehole images are the established and efficient tools for fracture evaluation. The major challenges are the associated risk of wireline logging in horizontal wells and the relatively lower rate of drilling penetration required in logging while drilling borehole imaging. We propose a solution for accurate fracture evaluation with structural delineation in unconventional reservoirs using a novel borehole resistivity image. In horizontal wellbores, bedding boundaries are usually parallel to well trajectory, making bed boundary identification difficult due to the lack of clear sinusoidal signatures in the log view. A true-dip plane-based dip picking algorithm has been developed and applied on a new throughthe-bit borehole resistivity image (TBEI) for bed boundary picking of different shapes, such as bull’s eye, reverse bull’s eye and wellbore parallel bedding features. Lithology-bound fractures can also be picked and classified in conjunction with this new method, enabling more accurate fracture characterization within the modeled structure. In our case study, fracture aperture computation from the TBEI is verified by the resistivity image from the FMI full-bore formation micro-imager run in the same well. Although the structures in many unconventional reservoirs are relatively flat, there are still many small-scale, sub-seismic structures and faults controlling the fracture distribution. The near-well structure can be reconstructed from the bed boundaries and faults with an improved structural modeling method. The relationship between fractures and geological structures and faults is then analyzed for optimization of completion design. Breakout and drilling induced fractures can also be confidently identified from the TBEI image and used to determine the stress regime for consideration in hydraulic stimulation. A case study has been used to demonstrate the benefits of this innovative, new borehole image-based workflow to an unconventional reservoir in the STACK Play of the Anadarko Basin, Oklahoma, USA. The enhanced understanding of natural fracture distribution along the horizontal wellbore, through more accurate structural delineation, to ultimately optimize completion performance and well productivity. The new TBEI imager consists of three sondes containing 12 pads with 12 buttons per pad, one power supply cartridge and three acquisition cartridges with an inclinometer module from accelerometers (Bammi at al., 2016). The tool mechanics are significantly improved in terms of tolerance of conveyance with only 2.125-in. outer diameter. The measurement principle used by this new tool is similar to that of the FMI microimager. The alternating electric field current generated from upper insulated section with low frequency travels symmetrically from pads, conductive mud and formation back to upper/lower return electrodes (Figure 1). The passive focusing technology is used to resolve high-resolution features of formation resistivity by maintaining the same EMEX (émetteur d'excitation, excitation transmitter) potential on all pad surfaces including buttons and metallic surfaces. The tool response consists of two components: a low frequency component modulated by the conductivity of the formation at the depth of investigation (Doll, 1951) and a high-resolution component modulated by the formation micro-conductivity in the very shallow near-wellbore region directly in front of each button. Speed Correction for Long-Spaced Multiple Sondes Speed correction is very challenging for the image measurement from this tool because of the six different pad levels and more than 66-inch distance between the closed two sondes. The speed correction designed for continuous wireline logging with a Kalman-filter and is not suitable for through-the-bit logging with pipe changes. A new speed correction has been developed to incorporate the pipe changes and is based on time domain data directly (Figure 2). The pipe changing interval is calculated from measured acceleration, and sticking zones are identified accurately in each of logging intervals. True Dip-Based Dip Picking in a Horizontal Well In a horizontal well the shape of most bed boundary dips is not sinusoidal, but appears as a bull’s eye, reverse bull’s eye, or wellbore parallel bedding features. The conventional dip-picking method cannot handle these shapes properly. A new dip picking based on true dip matches the intersection of a plane with the borehole, considering the variations of the borehole deviation and azimuth. Three points are manually picked on the borehole image to define a true plane dip. Each point is translated into spatial coordinates (in true dip space), and the triplet defines a spatial plane (Figure 3a). The continuous points can be picked by following the image features and a potential trend is also displayed as reference (Figure 3b). The true dip is calculated automatically by following the continuous picked points. Formation Correlation Analysis with True Stratigraphic Thickness Index The drilling polarity is easily computed based on the angle between the well trajectory and the pole of formation dip (Figure 4a). When this angle is more than 90°, it indicates drilling down; an angle less than 90° indicates drilling up. Then the true stratigraphic thickness (TST) is computed from apparent formation dip and drilling polarity accordingly with following equation: where i is each position of picked dip, MD is measurement depth and, α is the angle between well trajectory and the pole of formation dip in Figure 4-b. After the TST computation, the gamma ray (GR) or other logs can be displayed in TST reference. The log response can be varied for the same layer along a long horizontal section but usually the relatively high clay content layers are stable, and the lithology overlaying pattern is comparable (Figure 6). We assume that the thickness of the same layer bedded by a high clay content layer is relatively stable in the near wellbore region. Any thickness change is likely caused by the fault or uncorrected dips. A fault can be easily identified from the borehole image and the dip should be adjusted accordingly. The formation correlation can be achieved by adjusting the two sides of the fault by following the above rules, and then the fault throw can be estimated from TST change as well as the fault type identification (Figure 6). Quick Structural Delineation with Picked Dips and Faults To achieve a more realistic geological cross section with continuous formation layering, a novel solution is applied with following steps (Ma et al., 2018): 1) Dips are picked automatically from images in horizontal wells using the true dip-based method. Structure analysis is employed using the automatic structure zonation based on the great circle-fitting criteria. 2) The fault throw is estimated based on correlation analysis of changing TST, and the fault type can be identified by combining the fault dip picked from the image. The fault ordering is done based on the estimated fault throw after one of the major faults is selected as the major projection plane. 3) All dips are projected along the major fault plane vertically by following the similar or parallel fold principle (Etchecopar and Bonnetain, 1992; Yamada et al., 2016); then the projected dips are projected into the plane perpendicular to structural axis or a user-defined cross section. If the cross section is not perpendicular to the structural axis, the projected dips are projected again along with structural axis. 4) After the display layer is defined, the fault throw is applied for the layers and truncated by the extended fault plane. For each truncated area, a B-spline method is applied ensure smoothed layers. Fracture Evaluation from Borehole Images Including aperture estimation in fracture evaluation is critical for unconventional reservoir characterization. Because the TBEI imager is based on the same measurement principle as the FMI imager, the fracture aperture computation parameters were kept the same with reverse forwarding modeling in one well logged with the FMI imager and the new TBEI (Figure 5). The fracture aperture difference is less than 10% statistically for the same fractures in the same interval based on mean values. In Figure 5, we can see that there is little difference for each of fracture segment’s aperture, but the relative order is kept for closed fractures. It can be concluded that the tool parameters from the FMI are suitable for fracture aperture computation from the TBEI image. A Geological Characterization Case Study from Oklahoma This case study is from the STACK Play of the Anadarko Basin, Oklahoma, USA. The horizontal target zone is within the Mississippian age Lower Meramec Formation. The Meramec is generally considered to have been deposited as prograding lowstand clinoforms of predominantly detrital siliciclastics, with shales and minor detrital carbonates, from a carbonate-siliciclastic rimmed shelf. The bedding boundaries, cross beddings and faults are picked with the true dip-based picking method. The TST index is computed from bedding boundaries. Correlation analysis from the GR displayed as TST reference is challenging. The relatively high GR is taken as a local geological marker, and GR shape is the secondary reference. Layer thicknesses change relatively quickly, either because of the depositional environment variation or because of incorrect dip picking. Based on the above principles, the formation correlation is achieved and shown in Figure 6: the top geological marker is define

Production from unconventional resources is from permeability challenged reservoirs. Such reservoirs vary from conventional oil and gas trapped in ultra-tight or tight formations to the source rock plays. Tight reservoirs are an extension of the uneconomic conventional plays with the promise of economic production through hydraulic fracturing and multistage stimulation. The tight and ultra-tight reservoirs are referred to as hybrid reservoirs. The production mechanism of hybrid reservoirs is similar to that of unconventional source/shale plays but the reservoir performance differs from that of source rock plays. The success in the development and production from the tight reservoirs in the United States has been mostly through trial and error methods. During the last decade, improvement and advances in the areas of reservoir evaluation, well completion methods, hydraulic fracturing, and operational efficiencies resulted in the economic production of gas/oil from the hybrid reservoirs.

Reactivating oil and gas wells, increasing oil and gas production, and improving recovery provide more opportunities for energy supply especially in the extraction of unconventional oil and gas reservoirs. Due to changes caused by well completion and production in pore pressure around oil and gas wells, subsequently leading to changes in ground stress, and the presence of natural and induced fractures in the reservoir, the process of refracturing is highly complex. This complexity is particularly pronounced in shale oil reservoirs with developed weak layer structures. Through true triaxial hydraulic fracturing experiments on Jimsar shale and utilizing micro-CT to characterize fractures, this study investigates the mechanisms and patterns of refracturing. The research indicates: (1) natural fractures and the stress states in the rock are the primary influencing factors in the fracture propagation. Because natural fractures are widely developed in Jimsar shale, natural fractures are the main influencing factors of hydraulic fracturing, especially in refracturing, the existing fractures have a greater impact on the propagation of secondary fracturing fractures. (2) Successful sealing of existing fractures using temporary blocking agents is crucial for initiating new fractures in refracturing. Traditional methods of plugging the seam at the root of existing fractures are ineffective, whereas extensive injection of blocking agents, forming large “sheet-like” blocking bodies in old fractures, yields better sealing effects, promoting the initiation of new fractures. (3) Moderately increasing the pumping rate and viscosity of fracturing fluid is advantageous in forming “sheet-like” temporary blocking bodies, enhancing the complexity of the network of new fractures in refracturing. (4) When there is a high horizontal stress difference, after sealing old fractures, the secondary hydraulic fractures initiate parallel to and extend from the old fractures. In cases of low horizontal stress difference, the complexity of secondary hydraulic fractures increases. When the horizontal stress changes direction, the secondary hydraulic fractures also change direction. It is recommended to use high-viscosity fracturing fluid and moderately increase the pumping rate, injecting blocking agents to seal old fractures, thereby enhancing the complexity of the network of refracturing. These findings provide important technical guidance for improving the efficiency of shale oil reservoir development.

Abstract Reservoir stimulation for in-situ oil shale conversion employed hydraulic fracturing, as demonstrated in the Nong’an oil shale in-situ conversion project. This study examines the extent of reservoir stimulation and the associated changes in permeability. Hydraulic fracturing significantly increased the reservoir stimulation volume, raising the permeability in the stimulated area to 324.6 mD. Subsequent water replacement involved injecting lower-temperature nitrogen, which mitigated volume shrinkage and closed microfractures. However, this process reduced permeability by 80.54%, decreasing the seepage area to 2660.7 m3. The gas injection and mining process encompassed two stages: warming and cracking. The former aimed to enhance the drying of the formation in the stimulation area, restoring 22.87% of the permeability of the original area. The latter stage facilitated organic matter decomposition to release hydrocarbons, increasing the permeability of the reformed region to 704.842 mD. The reservoir-stimulated area can be categorized into cracking, high seepage, or low seepage zones, depending on the difficulty of injected gas flow and the extent of high-temperature influence.

In response to the special requirements for shale gas reservoir stimulation, a novel environmentally responsive fracturing fluid thickener was designed and developed in this paper. N,N-dimethylhexadecylallylammonium chloride (C16DMAAC), N-vinylpyrrolidone (NVP), 2-acrylamido-2-methylpropanesulfonic acid (AMPS), and Acrylamide (AM) were used as functional monomers, and the synthesis of the target product was achieved successfully through free radical polymerization in an aqueous solution. The findings indicated that in the optimized situation, where the total monomer mass fraction was 25%, the ratio of AM:AMPS:C16DMAAC:NVP was 15:10:3:2, the initiator mass fraction was 0.3%, the pH was 6.5, and the temperature was 60 °C, the thickener achieved a number-average molecular weight of 1.13 × 106. Furthermore, its remarkable thermal stability was manifested, as it only experienced a 15% mass loss in the temperature interval spanning from 40 °C to 260 °C. Performance evaluation results indicated that, at 120 °C, the viscosity of the thickener under study increased by over 49% compared to the control group. Simultaneously, in a 0.4 wt% CaCl2 environment, it retained a high viscosity of 54.75 mPa·s. This value was 46.61 mPa·s greater than that of the control group. Furthermore, under the conditions of a temperature of 170 °C, the fracturing fluid viscosity remained above 68 mPa·s. Regarding the flow performance, within the flow rate range from 110 to 150 L/min, it showed a remarkable drag reduction effect, achieving a maximum drag reduction rate of 70%. At 150 °C, the fracturing fluid exhibited superior proppant-carrying efficacy, with a settlement rate that was 26.1% lower than that of the control group. The viscosity and residue content of the gel-broken fracturing fluid exceeded the requirements of industry standards. In particular, the residue content of this fracturing fluid was 21% lower than that of the control group. The research results provide an environmentally responsive fracturing fluid thickener with excellent performance for shale gas reservoir stimulation.

The advancement of unconventional hydrocarbon reservoirs, especially shale gas, has revolutionized energy production, offering a cleaner alternative to traditional fossil fuels. Despite its potential, shale gas extraction faces significant challenges due to the ultra-low permeability of formations, complex pore structures, and issues like water blocking caused by hydraulic fracturing fluids. This study explores the innovative application of microwave heating (MWH) as a Formation Heat Treatment (FHT) technique to mitigate these challenges and enhance shale gas recovery. Microwave heating operates by converting electromagnetic energy into heat, leveraging the dielectric properties of reservoir materials to generate rapid, uniform, and volumetric heating. Numerical simulations were conducted to evaluate the effectiveness of MWH under varying frequencies (915 MHz, 2450 MHz, and 5800 MHz), focusing on temperature distribution, water volume reduction, and gas production. Results demonstrate that higher microwave frequencies, particularly 5800 MHz, lead to significant temperature increases, effective water vaporization, and permeability improvements. This process facilitates gas desorption from the shale matrix, enhances diffusion, and improves cumulative gas recovery. The study highlights the environmental advantages of MWH, including reduced water usage and avoidance of groundwater contamination, positioning it as a sustainable alternative to traditional hydraulic fracturing. Furthermore, insights into shale reservoirs' thermal and electromagnetic properties are provided, offering guidance for optimizing MWH application in field conditions. This research underscores the potential of MWH to address critical operational challenges in unconventional reservoirs, paving the way for its integration into advanced shale gas recovery strategies.

The shale oil reservoirs in the Liang Gaoshan area of the Sichuan Basin exhibit extremely low porosity and permeability, as well as significant heterogeneity. Consequently, hydraulic fracturing of horizontal wells is critical for achieving effective production enhancement. Early diagnostic monitoring revealed substantial variations in fracture propagation. Some hydraulic fractures extended beyond the target layer into adjacent river sandstone, leading to increased fracturing costs and reduced reserve utilization rates. To address these challenges, temporary plugging fracturing (TPF) was implemented to optimize fluid distribution among fracture clusters. However, previous TPF operations in this basin relied heavily on empirical methods, resulting in a relatively low sealing success rate of approximately 70%. This study proposes a fracture propagation model that incorporates stress interference dynamics induced by temporary plugging fracturing agents. Additionally, through laboratory experiments, a high-pressure (30.2 MPa) degradable temporary-plugging agent was selected for use in horizontal well fracturing. Key process parameters, including the insertion timing, dosage, and distribution strategy of the temporary-plugging agent, were optimized using a numerical simulation system. The results indicate that injecting 50% of the fracturing fluid followed by the simultaneous deployment of 12 temporary blocking nodes ensures uniform fracture cluster extension while maximizing the reconstruction volume. Furthermore, deploying all temporary blocking nodes at once reduces the fracturing operation time by approximately 20%. These findings were validated via field applications at Well NC1. Microseismic monitoring during fracturing confirmed the accuracy of the research outcomes presented in this paper. After temporary plugging, the extension uniformity of each fracture cluster significantly improved, with the stimulated reservoir volume (SRV) of a single section reaching 530,000 cubic meters. These results provide a foundation for optimizing horizontal well fracturing in Liang Gaoshan shale oil reservoirs within the Sichuan Basin, facilitating efficient and economical fracturing operations.

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Attributed to the extreme geological environment of deep shale reservoirs, characterized by high temperature and stress, hydraulic fracturing reservoir stimulation often faces a series of problems, such as high breakdown pressure and unclear hydraulic fracture propagation law. The purpose of this study is to restore the propagation and evolution characteristics of hydraulic fractures in a deep shale reservoir environment, and to clarify the difficulty of opening hydraulic fractures and the law of propagation. For this purpose, outcrop cores were collected from the main shale gas-producing areas in China, and physical simulation tests of hydraulic fracturing with different displacement, temperature and stress states under in-situ temperature and stress conditions in deep shale reservoirs were carried out. The test results reveal that, within the actual in-situ reservoir environment, the fracturing pump injection curve primarily exhibits characteristics of high and low fluctuations, followed by a sustained high-pressure plateau post-peak. Notably, the post-peak fluctuations serve as a crucial indicator of increased complexity in the hydraulic fracture network. As the temperature increases, the breakdown pressure gradually decreases in a linear manner. The increase in displacement will enhance the thermal shock effect and aggravate the decrease of breakdown pressure. Stimulated rock area (SRA) is an effective index to measure the complexity of hydraulic fractures. The SRA of a single fracture is close to 1, while that of a complex fracture is between 1.5 and 2.

No abstract available

Deflagration fracturing is a gas-dominated, water-free reservoir stimulation technology that has shown strong potential in unconventional, low-permeability, or water-sensitive reservoirs such as coalbed methane and shale gas formations. Accurate prediction of fluid pressure variations, critical for optimizing fracture propagation and stimulation performance, is challenging. While field experiments and numerical simulations offer reliable predictions, they are hindered by high risks, costs, and computational complexity due to multi-physics coupling, Moreover, purely data-driven machine learning methods often exhibit poor generalization and may produce predictions that deviate from fundamental physical principles. To address these challenges, a physics-guided graph neural network (PG-GNN) is proposed in this study to predict the evolution of fluid pressure, the key driving factor governing fracture propagation, from a mechanistic perspective. The proposed method integrates governing equations and physical constraints to construct geometric, physical, and hybrid features and employs a graph neural network encoder to capture the spatial correlations among these features, thereby forming a deep learning framework with strong physical consistency. A multi-task loss function is further employed to balance predictive accuracy and physical rationality. Finally, the proposed model is validated using a high-resolution dataset generated by a CDEM-based numerical simulator, achieving a minimum MAPE of 0.313% and a minimum MSE of 2.309 × 10−4 on the test dataset, outperforming baseline models in both accuracy and stability and demonstrating strong extrapolation capability.

The resource potential of shale in Fengcheng formation in Mabei is huge, but it must rely on efficient hydraulic fracturing technology to obtain reservoir stimulation and achieve economic development. The propagation of hydraulic fractures in shale oil reservoir is significantly affected by natural fractures, and the interaction mechanism between hydraulic fractures and natural fractures is the key of realizing the optimal fracturing design. In particular, shale oil reservoir has complex conditions, such as interlayer blocking effect, differentiation of natural fracture development and variation of formation dip angle. In that case, the influence law of natural fracture on hydraulic fracture propagation is not clear, which restricts efficient development of shale oil. Therefore, based on the mechanical properties of shale in the Fengcheng formation, numerical model of the intersection of natural fractures and hydraulic fracture has been built. This intersection behaviors with different approach angle, interlayer stress and strength, natural fracture development degree and formation inclination have been fully analyzed. The results indicate that the hydraulic fracture is more favorable to penetrate the natural fracture with the increasing of the approaching angle. The barrier layer is conducive to the hydraulic fracture penetrating the natural fracture, restricting activation of the natural fracture. Also, the stress barrier effect is greater than the strength barrier effect. With the increase of the development degree of natural fractures, a large number of fractures weaken the overall strength of the formation, which is more conducive to the propagation of hydraulic fractures. When formation dip is large and propagation from weak strength to strong strength formation, hydraulic fracture is more susceptible to the influence of natural fractures and show the characteristics of turning along natural fractures. Outcomes deepen the understanding of the interaction mechanism between natural fracture and hydraulic fracture, which is beneficial for the optimal fracturing design and providing theoretical support for shale oil exploitation.

No abstract available

China's continental shale oil reserves face geological challenges from complex, weak structural planes (i.e., lithology interfaces and bedding planes) and discontinuous interlayers (i.e., shale and sandstone), which limit the effective stimulation of multiple pay layers. This study investigates hydraulic fracture (HF) cross-layer propagation behaviors in the Chang 7 Member sand-shale reservoirs, integrating fracturing experiments and numerical simulations to analyze impact of vertical stress difference (KV), interlayer stress contrast (Δσh), injection rate (Q), fluid viscosity (μ), weak plane shear strength (IS), weak plane tensile strength (IT), and cyclic injection. Results reveal that HF height extension is governed by interlayer obstruction and weak plane activation, forming three fracture propagation patterns: activated bedding planes, passivated fractures, and cross-layer fractures. Enhanced HF penetration occurs with higher KV, Q, μ, IS, IT, and reduced Δσh. Conversely, fractures become passivated with the weak plane activation. The dominant factor of fracture height is Δσh, followed by the IS, IT, KV, Q, and μ. Compared with conventional injection, cyclic injection improves fracture height and fracture area by 200% and 23%, respectively. Reduced cyclic amplitude or extended cycle duration promotes bedding activation. To achieve vertical connection of multiple pay layers, it is recommended to perform hydraulic fracturing with 30 mPa s guar gum at a flow rate above 8.3 m3/min. These findings are expected to provide hydraulic fracturing guidance for the interlayered shale oil reservoirs.

No abstract available

No abstract available

Foam gel fracturing fluid has the characteristics of low formation damage, strong flowback ability, low fluid loss, high fluid efficiency, proper viscosity, and strong sand-carrying capacity, and it occupies a very important position in fracturing fluid systems. The rheological properties of gel fracturing fluid with different foam qualities of CO2, under different experimental temperatures and pressures, have not been thoroughly investigated, and their influence on it was studied. To simulate the performance of CO2 foam gel fracturing fluid under field operation conditions, the formula of the gel fracturing fluid was obtained through experimental optimization in this paper, and the experimental results show that the viscosity of gel fracturing fluid is 2.5 mPa·s (after gel breaking at a shear rate of 500 s−1), the residue content is 1.3 mg/L, the surface tension is 25.1 mN/m, and the interfacial tension is 1.6 mN/m. The sand-carrying fluid has no settlement in 3 h with a 40% sand ratio of 40–70-mesh quartz sand. The core damage rate of foam gel fracturing fluid is less than 19%, the shear time is 90 min at 170 s−1 and 90 °C, the viscosity of fracturing fluid is >50 mPa·s, and the temperature resistance and shear resistance are excellent. The gel fracturing fluid that was optimized was selected as the base fluid, which was mixed with liquid CO2 to form the CO2 foam fracturing fluid. This paper studied the rheological properties of CO2 foam gel fracturing fluid with different CO2 foam qualities under high temperature (65 °C) and high pressure (30 MPa) and two states of supercooled liquid (unfoamed) and supercritical state (foamed) through indoor pipe flow experiments. The effects of temperature, pressure, shear rate, foam quality, and other factors on the rheological properties of CO2 foam gel fracturing fluid were considered, and it was confirmed that among all the factors, foam quality and temperature are the main influencing factors, which is of great significance for us to better understand and evaluate the flow characteristics of CO2 foam gel fracturing fluid and the design of shale gas reservoir fracturing operations.

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.

With the application of CO2 fracturing, CO2 huff and puff, CO2 flooding, and other stimulation technologies in shale reservoirs, a large amount of CO2 remained in the formation, which also lead to the serious corrosion problem of CO2 in shale reservoirs. In order to solve the harm caused by CO2 corrosion, it is necessary to curb CO2 corrosion from the cementing cement ring to ensure the long-term stable exploitation of shale oil. Therefore, a new latex was created using liquid polybutadiene, styrene, 2-acrylamide-2-methylpropanesulfonic acid, and maleic anhydride to increase the cement ring’s resistance to CO2 corrosion. The latex’s structure and characteristics were then confirmed using infrared, particle size analyzer, thermogravimetric analysis, and transmission electron microscopy. The major size distribution of latex is between 160 and 220 nm, with a solid content of 32.2% and an apparent viscosity of 36.8 mPa·s. And it had good physical properties and stability. Latex can effectively improve the properties of cement slurry and cement composite. When the amount of latex was 8%, the fluidity index of cement slurry was 0.76, the consistency index was 0.5363, the free liquid content was only 0.1%, and the water loss was reduced to 108 mL. At the same time, latex has a certain retarding ability. With 8% latex, the cement slurry has a specific retarding ability, is 0.76 and 0.5363, has a free liquid content of just 0.1%, and reduces water loss to 108 mL. Moreover, latex had certain retarding properties. The compressive strength and flexural strength of the latex cement composite were increased by 13.47% and 33.64% compared with the blank cement composite. A long-term CO2 corrosion experiment also showed that latex significantly increased the cement composite’s resilience to corrosion, lowering the blank cement composite’s growth rate of permeability from 46.88% to 19.41% and its compressive strength drop rate from 27.39% to 11.74%. Through the use of XRD and SEM, the latex’s anti-corrosion mechanism, hydration products, and microstructure were examined. In addition to forming a continuous network structure with the hydrated calcium silicate and other gels, the latex can form a latex film to attach and fill the hydration products. This slows down the rate of CO2 corrosion of the hydration products, enhancing the cement composite’s resistance to corrosion. CO2-resistant toughened latex can effectively solve the CO2 corrosion problem of the cementing cement ring in shale reservoirs.

Estimating the Stimulated Reservoir Volume (SRV) is vital for optimizing well performance and enhancing hydrocarbon recovery in unconventional reservoirs. Accurate SRV estimation offers crucial insights into fracture networks and the extent of reservoir stimulation, which are fundamental for effective reservoir management. Traditional methods, such as microseismic monitoring, rate transient analysis (RTA), and fracture simulation models, provide different perspectives on fracture propagation but are often hindered by high costs and limitations in resolution. This paper introduces a novel approach for modeling dynamic fracture propagation. The proposed method leverages Continuous Wavelet Transform (CWT) to analyze fracture-treating pressure signals, functioning as a "mathematical microscope" to detect subtle pressure changes and trends during the hydraulic fracture propagation, thus offering a more nuanced view of fracture evolution. By continuously convoluting the complex Morlet wavelet with the hydraulic fracture treating pressure data, CWT effectively captures the nuances of fracture dynamics with high resolution, allowing for real-time monitoring and analysis. A unique representation, the normalized CWT scalogram, has been developed for each fracture propagation mode observed during hydraulic fracturing. The proposed framework transforms treating pressure data into a dimensionless, normalized CWT scalogram, providing a detailed analysis of fracture propagation across varying wavelet scales, capturing even the most subtle fracture behaviors. This scalogram is utilized to train a deep learning model with microseismic event data, enabling precise prediction of the microseismic event cloud corresponding to each hydraulic fracturing treatment, particularly within the same geological formation. The method's effectiveness is validated through a comparison of SRV estimates with results from RTA based on three years of production data. The complete dataset of treating pressure, and production data are publicly accessible via the Marcellus Shale Energy and Environment Laboratory (MSEEL). Integrating CWT with deep learning offers a comprehensive and cost-effective tool for enhancing the understanding of dynamic fracture events, leading to more accurate SRV estimations for the Marcellus shale formation. This methodology is scalable and can be extended to other unconventional reservoirs, promising broader applicability in unconventional reservoir management.

To address the issue of low production output, additional stimulation measures are always adopted.This study analyzes the complex characteristics of the Chang-7 shale gas reservoir in the central Tianhuan Syncline, Ordos Basin. Facing challenges from reservoir heterogeneity, we implemented a multi-stage fracturing pilot in the first horizontal well (DPX) of the Chang-7 reservoir using drillable bridge plug technology and customized fracturing designs based on horizontal well multi-stage stimulation theory and multi-fracture interference mechanisms. Research shows: Fracture parameters (stage count, geometry, length) and operational parameters (perforation scheme, fracturing scale, fluid type, injection rate) designed according to overall reservoir characteristics are significantly affected by heterogeneity during implementation, resulting in substantial variations in operational difficulty and outcomes across stages. Therefore, for reservoirs with strong heterogeneity, stage-specific designs must account for localized features to enhance success rates and production gains.

To address the challenges in interpreting fracturing treatment curves and the ambiguity in evaluating stimulation performance in shale gas fracturing, this study develops a comprehensive post-fracturing evaluation approach based on field data from shale gas wells in Block X of the Sichuan Basin, aiming to identify the key controlling factors influencing the stimulated reservoir volume (SRV). Using 295 fracturing stages, log–log pressure curve analysis was applied to process treatment data and optimize slope classification thresholds. The fracturing effectiveness of different curve types was compared with SRV results derived from microseismic monitoring, and the dominant factors were identified through grey relational analysis combined with normalized weighting calculations. The results show that fluid intensity, shut-in pressure, and proppant intensity are positively correlated with SRV. In highly brittle reservoirs, a rock property exemplified by Block X in the Sichuan Basin, increasing proppant concentration and optimizing treatment parameters in real time can effectively enlarge the stimulated reservoir volume. This study establishes a log–log pressure curve analysis and evaluation framework applicable to shale gas wells in Block X of the Sichuan Basin, providing a practical reference for improving fracturing design and stimulation effectiveness.

Compared to conventional fracturing techniques, foam fracturing has numerous advantages, including good shear resistance, strong sand carrying capacity, low fluid loss, low damage, and fast return rates. It is particularly suitable for stimulation in low pressure, low permeability, and water-sensitive formations. Specifically, CO2 foam fracturing is crucial in energy savings and emission reductions, controlling the expansion of reservoir clay minerals, reducing crude oil viscosity, and improving the production of water-locked reservoirs. In this paper, we investigate the foam fracturing fluid and evaluate its performance. We selected thickeners with good foaming stability and foaming agents with excellent performance at low dosage levels, based on experimental evaluation. We finally determined the formulation of the foam fracturing fluid by analyzing the experimental data, such as foam half-life, foam mass, and viscosity. We experimentally evaluated the viscosity, static sand settling properties, and rheological properties of the fluid. After being tested on the reservoir core, the foam fracturing fluid has a viscosity of 2 mPas. Moreover, the residue content is 1.1 mg/L, the surface tension is 24.5 mN/m, and the interfacial tension is 1.5 mN/m. The fluid-carrying sand experiment of 40–70 mesh ceramic particles, commonly used in shale gas fracking, was evaluated. The sand-to-liquid ratio was set at 40% for the static sand-carrying experiment. The flow of the fluid-carrying sand was good, and the settling property was satisfactory for 3 h. We used shale reservoir cores from well W-1 to assess the rate of foam fracture, which was less than 19%. Under the experimental conditions of a shear rate of 170 S−1 and a temperature of 90°C, the viscosity of fracturing fluid was measured to be greater than 50 mPas, 90 min after shear, demonstrating the excellent temperature and shear resistance of the foam fracturing fluid. Using CO2 foam fracturing fluid can significantly improve the reconstruction effect of low permeability hydrocarbon reservoirs (especially unconventional reservoirs) and solve problems related to water resources and environmental protection during the process of oil and gas reservoir development. It will be a major factor in improving construction impacts and addressing water and environmental concerns for low permeability hydrocarbon reservoirs, particularly unconventional ones that utilize CO2 foam fracturing fluids.

As a waterless fracturing fluids for gas shale stimulation with low viscosity and strong diffusibility, supercritical CO2 is promising than the water by avoiding the clay hydration expansion and reducing reservoir damage. The permeability evolution influenced by the changes of the temperature and stress is the key to gas extraction in deep buried shale reservoirs. Thus, the study focuses on the coupling influence of effective stress, temperature, and CO2 adsorption expansion effects on the seepage characteristics of Silurian Longmaxi shale fractured by supercritical CO2. The results show that when the gas pressure is 1–3 MPa, the permeability decreases significantly with the increase in gas pressure, and the Klinkenberg effects plays a predominant role at this stage. When the gas pressure is 3–5 MPa, the permeability increases with the increase in gas pressure, and the influence of effective stress on permeability is dominant. The permeability decreases exponentially with the increase in effective stress. The permeability of shale after the adsorption of CO2 gas is significantly lower than that of before adsorption; the permeability decreases with the increase in temperature at 305.15 K–321.15 K, and with the increase in temperature, the permeability sensitivity to the temperature decreases. The permeability is closely related to supercritical CO2 injection pressure and volume stress; when the injection pressure of supercritical CO2 is constant, the permeability decreases with the increase in volume stress. The results can be used for the dynamic prediction of reservoir permeability and gas extraction in CO2-enhanced shale gas development.

Abstract This study aimed to investigate the fracture extension pattern of the Gulong shale oil reservoir through rock mechanical tests, fracturing physical simulation experiments, and on-site tracer fracture monitoring to enhance fracturing stimulation effectiveness. The results of the rock mechanical tests revealed the anisotropic mechanical properties of the rocks attributed to the lamellation structure. Fracturing physical simulation experiments were conducted to determine the fracture extension pattern in the laboratory, indicating that increasing the fracturing fluid viscosity and injection rate could help overcome the vertical extension limitations caused by the lamellation structure. For the first time, on-site tracer fracture monitoring was implemented to study the hydraulic fracture extension pattern of the Gulong shale oil reservoir. The findings suggested that utilizing stages with three or four perforation clusters, a 50% slick water ratio, and temporary plugging could enhance fracture initiation efficiency and promote uniform extension. After modifying the parameters based on the research results, the on-site fracturing wells exhibited excellent fracturing stimulation effects. This study is significant for understanding the unique fracture extension pattern of the Gulong shale oil reservoir both in laboratory settings and on-site, providing technical recommendations for improving fracturing stimulation in other reservoirs with similar characteristics.

Multistage fracturing technology is the primary means of reservoir stimulation in shale gas wells. However, the productivity contribution of each stage varies greatly. It is essential to evaluate the fracturing effect in order to make an optimized treatment design. In this study, we adopted an integrated workflow to assess the main control factors of geological and engineering parameters and a novel approach was proposed for post-fracturing evaluation. For this purpose, the H block in Zhaotong shale gas demonstration zone in Sichuan, China, has been taken as an object of study. The production predicting model was built based on the reservoir fracability index (RFI) which took both fluid type and proppant size differences into consideration. The results demonstrated that (1) if the reservoir quality index (RQI) in the target zone is greater than 5.0, then the area has good reservoir quality and development potential. (2) The RFI of H Block is generally at 4.0–6.0, it can be used as the key parameter to screen out the sweet spot. This method not only serves as a set of practical fracturing evaluation methods but also as a set of productivity prediction and fracturing optimization methods, which can provide strong support for the development of shale gas reservoirs.

Hydraulic fracturing of horizontal well is the key technology to develop unconventional resources. Simultaneous fracturing in horizontal well is the prevalent method applied in the field practice. To achieve successful and desired stimulated rock volumes and fracture networks, it is necessary to understand the influence of stress on fracture geometry. This paper proposed a 2D model to simulate the fracture propagation in simultaneous hydraulic fracture operation based on Finite Discrete Element Method (FDEM). In this model, the fracturing fluid leak-off and natural fractures are coupled. The simulation results demonstrated that the induced stress field can not only affect the fracture extended length, but also the width of fracture. The outer fractures dominate the inner fractures in growth. And the central fractures stop propagating after they reached a certain length due to the induced stress field. These simulations are meaningful for stimulation design and required spacing conditions to acquire the desired fracture lengths, proppant placement, and production rates.

Low-resistivity & low-quality reservoir has been successfully developed in ONWJ area by using hydraulic fracturing stimulation method to optimize production gain due to low-permeability reservoir property. The purpose of this research is to understand implication of shale structure for increasing gain production after hydraulic fracturing stimulation. Implementation of hydraulic fracturing was first completed at BerylE-1 and the well could produce 455 BOPD at 560 psi in reservoir 33 and 35. This reservoir was found in Upper Cibulakan Formation that consists of various lithology’s such as very fine-grained sandstone, shale, siltstone & thin tight carbonate that deposited in shallow marine neritic to littoral environment. Production anomaly occurs after hydraulic fracturing stimulation. Some of well in this reservoir show good incremental production, but in the other well there was no significantly incremental production in this reservoir. There were three types of shale structure classification based on effective porosity distribution: laminated shale, structural shale and dispersed shale. Shale structure for each well has been defined based on Thomas Stieber plot and calibrated using petrographic analysis from 8 sample depth point. Based on this method, reservoir 33 is dominated by structural shale while reservoir 35 is dominated by laminar shale. Production data and shale type from each well has been compared and it shows that hydraulic fracturing simulation will increase effective porosity and will also increase effective permeability value. In BerylD-1 well hydraulic fracturing only completed in reservoir 35 and produced 340 BOPD with initial water cut 0 %. Laminar shale that dominates in reservoir 35 has high factor to increasing production gain after hydraulic fracturing was applied. Release of clay that caused by hydraulic fracturing will increase effective porosity and permeability.

No abstract available

Hydraulic fracturing of gas and oil reservoirs is the primary stimulation method for enhancing production in the field of petroleum engineering. The hydraulic fracturing technology plays a crucial role in increasing shale gas production from shale reservoirs. Understanding the effects of reservoir and fracturing conditions on fracture propagation is of great significance for optimizing the hydraulic fracturing process and has not been adequately explored in the current literature. In the context of shale reservoirs in Yibin, Sichuan Province, China, the study selects outcrops to prepare samples for uniaxial compression and Brazilian splitting tests. These tests measure the compressive and tensile strengths of shale in parallel bedding and vertical bedding directions, obtaining the shale’s anisotropic elastic modulus and Poisson’s ratio. These parameters are crucial for simulating reservoir hydraulic fracturing. This paper presents a numerical model utilizing a finite element (FE) analysis to simulate the process of multi-cluster hydraulic fracturing in a shale reservoir with natural fractures in three dimensions. A numerical simulation of the intersection of multiple clusters of 3D hydraulic fractures and natural fractures was performed, and the complex 3D fracture morphologies after the interaction between any two fractures were revealed. The influences of natural fractures, reservoir ground stress, fracturing conditions, and fracture interference concerning the spreading of hydraulic fractures were analyzed. The results highlight several key points: (1) Shale samples exhibit distinct layering with significant anisotropy. The elastic compressive modulus and Poisson’s ratio of parallel bedding shale samples are similar to those of vertical bedding shale samples, while the compressive strength of parallel bedding shale samples is significantly greater than that of vertical bedding shale samples. The elastic compressive modulus of shale is 6 to 10 times its tensile modulus. (2) The anisotropy of shale’s tensile properties is pronounced. The ultimate load capacity of vertical bedding shale samples is 2 to 4 times that of parallel bedding shale samples. The tensile strength of vertical bedding shale samples is 2 to 5 times that of parallel bedding shale samples. (3) The hydraulic fractures induced by the injection well closest to the natural fractures expanded the fastest, and the natural fractures opened when they intersected the hydraulic fractures. When the difference in the horizontal ground stress was significant, natural fractures were more inclined to open after the intersection between the hydraulic and natural fractures. (4) The higher the injection rate and viscosity of the fracturing fluid, the faster the fracture propagation. The research findings could improve the fracturing process through a better understanding of the fracture propagation process and provide practical guidance for hydraulic fracturing design in shale gas reservoirs.

With the ongoing development of oil and gas resources, low-permeability tight reservoirs have become a focal point of research and technological innovation. To effectively address the challenges associated with fracture fluid retention, this study investigates the role of CO2 in reservoir stimulation and productivity enhancement. The results reveal that liquid CO2 induces a rapid temperature reduction in shale samples during the initial phase of injection with a temperature decrease of 16.1 °C observed within the first 10 min. However, the cooling rate diminishes significantly in the later stages, with only a 0.8 °C decrease recorded over the subsequent 10 min which indicating a distinct endothermic effect. The high diffusivity and low viscosity of CO2 are key to its effectiveness in enhancing reservoir pressure and improving fracture conductivity. Additionally, the expansion-induced cooling effect of CO2 lowers wellbore temperatures, thereby lowering the viscosity of the fracturing fluid and improving its mobility. A stable pressure gradient provides the driving force for efficient fracture fluid recovery, which significantly boosting recovery efficiency and productivity. The results further indicate that at injection rates of 5000 m3/d, 10,000 m3/d, and 15,000 m3/d, the recovery volumes are 97%, 96%, and 88% higher than those achieved with water-based fracturing fluids, respectively. These findings demonstrate the significant advantages of CO2 injection in increasing reservoir pressure and promotes the flow of oil and gas at the well bottom. The promising application potential of CO2 in low-permeability tight reservoirs underscores its value as an innovative approach to reservoir stimulation and productivity optimization. This study provides the first comprehensive analysis of CO2's dual role in enhancing flowback efficiency through thermal, mechanical, and fluid dynamic interactions, offering a paradigm shift from conventional water-based fracturing.

The effectiveness of hydraulic fractures is one of the critical factors determining the production performance of shale oil wells. To investigate the influence of fluid–shale interaction during formation stimulation on the effectiveness of hydraulic fractures and shale oil production, first, a series of conductivity tests were performed on shale cores after soaking in different fluids, revealing the evolution rules of conductivity of propped fracture under different fluid-shale interaction mechanisms. Furthermore, by considering the fluid–shale interaction in the reservoir numerical simulation model, the impact of hydraulic fracture effectiveness evolution on shale oil well productivity and its differences in reservoirs with different permeability anisotropy were analyzed. The research results indicate that the softening of fracture surfaces caused by fluid-shale interaction causes fracture conductivity damage, and the longer the soaking time, the more severe the damage. Generally, the degree of damage on the fracture conductivity caused by water–shale interaction is higher than that caused by supercritical CO2 shale interaction under the same soaking time. When considering the damage of hydraulic fracture effectiveness caused by fluid–shale interaction, the production of shale oil wells is significantly reduced. For shale reservoirs with strong permeability anisotropy, the cumulative oil production loss caused by fluid–shale interaction is more severe than that with weak permeability anisotropy.

Appropriate shut-in after hydraulic fracturing can enhance shale oil production, but the underlying mechanisms remain unclear. This study investigates three cores from shale oil well Y of Huazhuang (HSY) in southern China. Hydration–imbibition experiments were conducted under simulated reservoir conditions, combined with Computed Tomography scanning and digital rock reconstruction, reveal the microscopic mechanisms of shut-in stimulation, and propose a method to optimize shut-in duration. Results show that fracturing fluid infiltrates the cores, causing clay minerals to swell and exchange ions, disrupting their laminar structure. This inducing propagation and widening of existing fractures as well as the formation of new fractures significantly improve flow pathways and enable effective fluid migration and oil–water contact for subsequent imbibition. The imbibition process is jointly driven by capillary force, osmotic pressure, and wettability, enabling efficient displacement of pore oil. The synergy between hydration-induced permeability enhancement and imbibition displacement constitutes the core mechanism for production increase during shut-in. This effect is jointly controlled by hydrophilic clay content, water wettability, and initial pore–fracture structures. Higher clay content, stronger water wettability, larger matrix porosity, and more complex fracture networks correlate with shorter optimal shut-in times and greater production improvement. The three cores comprehensive performance ranks as core #1 > core #2 > core #3, with corresponding optimal shut-in times of 14, 18, and 19 days. Field application at well HSY with a 16-day shut-in confirmed the experimental predictions, validating the method's reliability and practical value. This study offers guidance for optimizing shut-in strategies in shale oil reservoirs.

Tight shale formations have emerged as a cornerstone of the United States’ unconventional hydrocarbon resources, offering significant potential for long-term energy security. However, unlocking these reserves requires advanced stimulation technologies to overcome the inherent low permeability of shale reservoirs. Multistage hydraulic fracturing has become a vital strategy to enhance reservoir contact and stimulate hydrocarbon flow. This paper explores the optimization of multistage hydraulic fracturing techniques aimed at improving recovery efficiency in various shale plays across the United States, including the Permian Basin, Bakken, Eagle Ford, and Marcellus formations. Emphasis is placed on understanding how fracture geometry, spacing, sequencing, and proppant distribution influence production outcomes. The study highlights key geological and operational factors that affect fracture propagation and reservoir connectivity, focusing on how these can be aligned to achieve higher recovery rates. Moreover, the integration of real-time monitoring, data analytics, and reservoir characterization tools is discussed as a means to support decision-making in complex shale environments. The research underscores the critical need for site-specific fracturing strategies that balance economic viability with environmental considerations. By optimizing multistage fracturing designs tailored to geological heterogeneity, the United States can continue to lead in unconventional resource development while maximizing output and minimizing operational risks in tight shale formations.

The persistent challenge of fracture-driven interference (FDI) during large-scale hydraulic fracturing in the southern Sichuan Basin has severely compromised shale gas productivity, while the existing research has inadequately addressed both FDI risk reductions and the optimization of reservoir stimulation. To bridge this gap, this study developed a mechanistic model of the competitive multi-cluster fracture propagation under non-uniform perforation conditions and established a perforation-based design methodology for the mitigation of horizontal well interference. The results demonstrate that spindle-shaped perforations enhance the uniformity of fracture propagation by 20.3% and 35.1% compared to that under uniform and trapezoidal perforations, respectively, with the perforation quantity (48) and diameter (10 mm) identified as the dominant control parameters for balancing multi-cluster growth. Through a systematic evaluation of the fracture communication mechanisms, three distinct inter-well types of FDI were identified: Type I (natural fracture–stress anisotropy synergy), Type II (natural-fracture-dominated), and Type III (stress-anisotropy-dominated). To mitigate these, customized perforation schemes coupled with geometry-optimized fracture layouts were developed. The surveillance data for the offset well show that the pressure interference decreased from 14.95 MPa and 6.23 MPa before its application to 0.7 MPa and 0 MPa, achieving an approximately 95.3% reduction in the pressure interference in the application wells. The expansion morphology of the inter-well fractures confirmed effective fluid redistribution across clusters and containment of the overextension of planar fractures, demonstrating this methodology’s dual capability to enhance the effectiveness of stimulation while resolving FDI challenges in deep shale reservoirs, thereby advancing both productivity and operational sustainability in complex fracturing operations.

The reservoir stimulation technology based on horizontal-well hydraulic fracturing has become one of the key means for efficient development of shale gas reservoir. Accurately describing the geometric shape and statistical characteristics of fractures is an indispensable key point. In this paper, a novel regularization model is proposed to inverse the fracture parameters with joint constraints of production data and microseismic data. Fractal theory is firstly introduced to model the fracture network and the geometric shape can be controlled by several parameters. Fractures are adaptive at the height in same rank and then a novel inversion model is presented based on regularization theory. An alternative iterative algorithm is presented to approximate the optimal solution. Relative errors of 4.94% and 6.78% are found with the results of two synthetic tests. The mean square relative error of the history match is about 7.73% in the test on real data. The numerical experiments show the accuracy and efficiency of the proposed model and algorithm.

The mechanisms underlying formation energy depletion after initial fracturing and post-refracturing production decline in shale oil horizontal wells remain poorly understood. This study proposes a novel numerical simulation framework for refracturing processes based on a three-dimensional fully coupled hydromechanical model. By dynamically reconfiguring the in situ stress field through integration of production data from initial fracturing stages, our approach enables precise control over fracture propagation trajectories and intensities, thereby enhancing reservoir stimulation volume (RSV) and residual oil recovery. The implementation of fully coupled hydromechanical simulation reveals two critical findings: (1) the 70 m fracture half-length generated during initial fracturing fails to access residual oil-rich zones due to insufficient fracture network complexity; (2) a 3–5° stress reorientation combined with reservoir repressurization before refracturing significantly improves fracture network interconnectivity. Field validation demonstrates that refracturing extends fracture half-lengths to 97–154 m (38–120% increase) and amplifies RSV by 125% compared to initial operations. The developed seepage–stress coupling methodology establishes a theoretical foundation for optimizing repeated fracturing designs in unconventional reservoirs, providing critical insights into residual oil mobilization through engineered stress field manipulation.

Mechanical properties are significantly influenced by highly developed bedding planes in shales. This leads to incorrect prediction of fracturing parameters, which results in inefficient fracturing reconstruction of shale reservoir. Therefore, it is of great significance to investigate the effect of bedding planes on the mechanical properties of shales and the mechanism of fracturing efficiency. In this paper, uniaxial compression experiments under variable bedding angles are carried out based on the outcrop shale of the Longmaxi Formation in Sichuan, China. Thereafter, the Aramis system is employed to examine the deterioration process and morphology of the specimens, and the Mechanical properties obtained are utilized to investigate the mechanisms through which the bedding plane influences the hydraulic fracturing stimulation. The findings of the study indicate that the compressive strength and modulus of elasticity of the specimens initially decrease and then increase with an increase in bedding angle. When the bedding angle at the range of 0°–15°, the predominant failure mode observed in the specimens is a mixed failure involving tension and shear, which penetrates the bedding plane. The failure mode observed in the specimen, with a bedding angle of 30°–60°, is predominantly shear failure along the bedding plane. In specimens subjected to a bedding angle of 75°–90°, failure modes are typically tensile failure parallel to the bedding plane and shear failure along the bedding plane. During hydraulic fracturing, the initial expansion of fractures occurs in a direction perpendicular to the minimum horizontal principal stress. In the event that the model contains bedding planes, the hydraulic fracture tends to expand along the bedding plane following an intersection with the plane. This phenomenon serves to promote a significant extension of the hydraulic fracture. Furthermore, the model incorporating bedding planes exhibits reduced apertures of hydraulic fractures and diminished pressures during the propagation stage of the fractures in comparison to the base model. The research results contribute to a comprehensive understanding of the evolutionary mechanisms governing the mechanical properties of shale reservoirs, as well as the expansion patterns of fractures under hydraulic fracturing stimulation.

Horizontal well hydraulic fracturing technology has been widely used in the efficient development of shale gas to address the challenges posed by these reservoirs’ low permeability and porosity. Despite the availability of numerous models for evaluating shale gas productivity post-fracturing, the effect of gas dynamic viscosity has been neglected. This study establishes a multiple-media and multiple-permeability coupled flow model based on the Barnett Shale and introduces Lee’s correlation for gas viscosity. The model’s feasibility and accuracy were verified by comparing the simulation results with the Barnett Shale data. The effects of reservoir damage, stimulation intensity, and fracture spacing on shale gas productivity are discussed. The results demonstrated that shale gas productivity decreased by more than 50% with intensified reservoir damage. Increasing stimulation intensity in the reservoir volume enhanced shale gas productivity. When the stimulation coefficient for the reservoir was increased from 0 to 2.5, the productivity increased by over 25%. A larger fracture spacing resulted in a smaller increase in shale gas productivity. Conversely, excessively narrow spacings significantly hindered productivity, resulting in an approximate 25% decrease. This study provides a theoretical reference for the productivity evaluation of horizontal wells in shale gas reservoirs.

During shale gas production, old wells often experience rapid capacity decline and difficulty in effectively utilizing the reservoir after the initial fracturing stimulation, which severely impacts production. The refracturing technology can reactivate low-producing wells to a certain extent through the secondary reconstruction of the residual reserve area. However, due to changes in the stress field after reservoir production, the fracture propagation law is often unclear. Therefore, this study uses a fully coupled flow-geomechanics model combined with the extended finite element method to numerically simulate the stress disturbance and refracturing fracture propagation under single- and double-fracture production scenarios. The results show that after production, the stress field near the fractures changes direction, causing the refracturing fractures to deviate significantly after initiation. As production time increases, the amplitude and range of stress deviation first increase rapidly, then decrease slowly. The fracture deviation amplitude and range follow the same trend, and the fracture pressure increases accordingly. When moving away from the production fracture, the stress deviation gradually slows down, weakening its influence on fracture propagation, and the fracture pressure increases steadily. Furthermore, during double-fracture production, as the distance between production fractures decreases, the area unaffected by stress deviation gradually shrinks. When the distance between production fractures is less than 15 m, the central region will still experience the influence of stress deviation during refracturing. In conclusion, to avoid intersection with the primary fracture during refracturing, it is recommended to choose areas far from the production fractures and with longer production times for fracturing stimulation. The simulation results can provide theoretical guidance to some extent for selecting the location and timing of perforations in field refracturing operations.

Shale gas is considered a crucial global energy source. Hydraulic fracturing with multiple fractures in horizontal wells has been a crucial method for stimulating shale gas. During multi-stage fracturing, the fracture propagation is non-uniform, and fractures cannot be induced in some clusters due to the influence of stress shadow. To improve the multi-fracture propagation performance, technologies such as limited-entry fracturing are employed. However, perforation erosion limits the effect of the application of these technologies. In this paper, a two-dimensional numerical model that considers perforation erosion is established based on the finite element method. Then, the multi-fracture propagation, taking into account the impact of perforation erosion, is studied under different parameters. The results suggest that perforation erosion leads to a reduction in the perforation friction and exacerbates the uneven propagation of the fractures. The effects of erosion on multi-fracture propagation are heightened with a small perforation diameter and perforation number. However, reducing the perforation number and perforation diameter remains an effective method for promoting uniform fracture propagation. As the cluster spacing is increased, the effects of erosion on multi-fracture propagation are aggravated because of the weakened stress shadow effect. Furthermore, for a given volume of fracturing fluid, although a higher injection rate is associated with a shorter injection time, the effects of erosion on the multi-fracture propagation are more severe at a high injection rate.

Casing deformation is evident during the development of shale oil and gas wells in the Sichuan and Junggar Basins in China. Their casing deformation characteristics, distribution law of deformation points, and main controlling factors were analyzed. According to the analysis results, shear is the main cause of casing deformation of shale oil and gas wells in the Sichuan and Junggar Basins in China and has the characteristics of “a dense heel end and a sparse toe end”. Faults account for 75% of casing deformation points, and fault slip caused by multi-stage fracturing is the primary factor responsible. The calculation model for fault slip that takes into account fracturing fluid invasion was established, and the dynamic variation law of fault slip was clarified: the fracturing fluid intruded into the fault, the relative dislocation of the damaged fault was caused by gravity, and the fault slippage was caused by the increase in fault activation length. This resulted in a linear increase in fault slippage, and the slippage reached its maximum when the fracturing fluid completely penetrated the fault and reached the fault boundary. The slip amount has a positive correlation with the fault length and the in situ stress difference; it increases first and then decreases with the increase in the fault dip angle. The slip amount reaches its maximum when the fault dip angle reaches 45°.

As the retrieval of unconventional oil and gas resources extends to the deep and ultra-deep domains, the issue of cement sheath failure in shale oil wellbores seriously endangers wellbore safety, making it imperative to uncover the relevant damage mechanism and develop effective assessment approaches. In response to the limitations of conventional finite element methods in representing mesoscopic damage, in this study, we determined the mesoscopic parameters of cement paste via laboratory calibrations; constructed a 3D casing–cement sheath–formation composite model using the discrete element method; addressed the restriction of the continuum assumption; and numerically simulated the microcrack initiation, propagation, and interface debonding behaviors of cement paste from a mesomechanical viewpoint. The model’s reliability was validated using a full-scale cement sheath sealing integrity assessment apparatus, while the influences of fracturing location, stage count, and internal casing pressure on cement sheath damage were analyzed systematically. Our findings indicate that the DEM model can precisely capture the dynamic evolution features of microcracks under cyclic loading, and the results agree well with the results of the cement sheath sealing integrity evaluation. During the first internal casing pressure loading phase, the microcracks generated account for 84% of the total microcracks formed during the entire loading process. The primary interface (casing–cement sheath interface) is fully debonded after the second internal pressure loading, demonstrating that the initial stage of cyclic internal casing pressure exerts a decisive impact on cement sheath integrity. The cement sheath in the horizontal well section is subjected to high internal casing pressure and high formation stress, resulting in more frequent microcrack coalescence and a rapid rise in the interface debonding rate, whereas the damage progression in the vertical well section is relatively slow.

No abstract available

The heterogeneous simulation zones will be caused by large-scale horizontal wells volume fracturing. The multiple multi-stage fractured horizontal wells interference has been observed in shale gas reservoirs. The adjacent well production and injection have obvious influence on test well wellbore pressure. The aim of this work is to establish a semi-analytical mathematical model of multiple multi-stage fractured horizontal wells interference with non-uniform simulated reservoir volume. The mathematical model is solved by coupling reservoirs and fracture and sub-zone interface model. This model solution is in agreement with numerical solution, and the calculation efficiency is higher than numerical solution. The result shows that adjacent well production leads to upturned pressure derivative curves and adjacent well injection leads to concave pressure derivative curves. Other vital parameters (such as fracture location, sub-region permeability, and width) have obvious influence on wellbore pressure and derivative curves. This can provide guides for fracturing optimization and optimal carbon dioxide injection rate.

Development of unconventional shale gas reservoirs (SGRs) has been boosted by the advancements in two key technologies: horizontal drilling and multi-stage hydraulic fracturing. A large number of multi-stage fractured horizontal wells (MsFHW) have been drilled to enhance reservoir production performance. Gas flow in SGRs is a multi-mechanism process, including: desorption, diffusion, and non-Darcy flow. The productivity of the SGRs with MsFHW is influenced by both reservoir conditions and hydraulic fracture properties. However, rare simulation work has been conducted for multi-stage hydraulic fractured SGRs. Most of them use well testing methods, which have too many unrealistic simplifications and assumptions. Also, no systematical work has been conducted considering all reasonable transport mechanisms. And there are very few works on sensitivity studies of uncertain parameters using real parameter ranges. Hence, a detailed and systematic study of reservoir simulation with MsFHW is still necessary. In this paper, a dual porosity model was constructed to estimate the effect of parameters on shale gas production with MsFHW. The simulation model was verified with the available field data from the Barnett Shale. The following mechanisms have been considered in this model: viscous flow, slip flow, Knudsen diffusion, and gas desorption. Langmuir isotherm was used to simulate the gas desorption process. Sensitivity analysis on SGRs’ production performance with MsFHW has been conducted. Parameters influencing shale gas production were classified into two categories: reservoir parameters including matrix permeability, matrix porosity; and hydraulic fracture parameters including hydraulic fracture spacing, and fracture half-length. Typical ranges of matrix parameters have been reviewed. Sensitivity analysis have been conducted to analyze the effect of the above factors on the production performance of SGRs. Through comparison, it can be found that hydraulic fracture parameters are more sensitive compared with reservoir parameters. And reservoirs parameters mainly affect the later production period. However, the hydraulic fracture parameters have a significant effect on gas production from the early period. The results of this study can be used to improve the efficiency of history matching process. Also, it can contribute to the design and optimization of hydraulic fracture treatment design in unconventional SGRs.

Purpose. Research is aimed at integrating multi-stage hydraulic fracturing in horizontal wells with hydrodynamic simulation as a mandatory part of planning the mining of any shale oil or gas reservoir. Methods. Geological and hydrodynamic reservoir modeling is part of the research. The properties and geometries of the hydraulic fracture network and its representation in the dynamic reservoir model were assessed. The comparative characterization was carried out based on the two methods of fracture modeling: cell dimension reduction for explicit fracture modeling (LGR – local grid refinement) and implicit fracture modeling method, presented in this paper, with additional pseudo-connections between well and reservoir. Findings. A hydrodynamic model for low-permeable reservoir, produced by horizontal well, hydraulically fractured with 5 stages, has been generated. This model is calibrated to the production history and flowing bottom hole pressure by applying two methods of fracture modeling. Modeling results show that it is possible to replicate historical well production by using both methods. However, the proposed method with pseudo connections has several advantages compared to the generally accepted, local grid refinement (LGR) method. Originality. For the first time, a system of pseudo connections between well and reservoir was constructed to model a multi-stage hydraulic fracturing for a hydrodynamic model of tight reservoir. Hydrodynamic simulation results were refined and calibrated to the history of hydrocarbon production and flowing bottom hole pressure data using the pseudo-connections and LGR methods. The similarity of the results by applying LGR and pseudo-connections methods was revealed. Practical implications. The use of pseudo connections for hydraulic fracturing modeling can reduce simulation run time for cases where multi-stage hydraulic fracturing has already been carried out or is planned in the future. Additionally, the use of this method allows testing a larger number of realizations and scenarios, including hydraulic fracturing design (number of stages, size and conductivity of resulted fracture systems, fracture orientation, etc.), well placement and fracture growth relative to well trajectory. Also, there is no need to rebuild a model every time for each realization, as is the case with the LGR method.

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.

In order to improve the shale oil production rate and save fracturing costs, based on dynamic production data, a production-oriented optimization method for fracture spacing of multi-stage fractured horizontal wells is proposed in this study. First, M. Brown et al.’s trilinear seepage flow models and their pressure and flow rate solutions are applied. Second, deconvolution theory is introduced to normalize the production data. The data of variable pressure and variable flow rate are, respectively, transformed into the pressure data under unit flow rate and the flow rate data under unit production pressure drop; and the influence of data error is eliminated. Two kinds of typical curve of the normalized data are analyzed using the pressure and flow rate solutions of M. Brown et al.’s models. The two fitting methods constrain each other. Thus, reservoir and fracture parameters are interpretated. A practical model has been established to more accurately describe the seepage flow behavior in shale oil reservoirs. Third, using Duhamel’s principle and the rate solution, the daily and cumulative production rate under any variable production pressure can be obtained. The productivity can be more accurately predicted. Finally, the analysis method is applied to analyze the actual dynamic production data. The fracture spacing of a shale oil producing well in an actual block is optimized from the aspects of production life, cumulative production, economic benefits and other influencing factors, and some significant conclusions are obtained. The research results show that with the goal of maximum cumulative production, the optimal fracture spacing is 5.5 m for 5 years and 11.4 m for 10 years. All in all, the fracture spacing optimization and design theory of multi-stage fractured horizontal wells is enriched.

The development of shale gas reservoirs often involves the utilization of horizontal well segmental multi-stage fracturing techniques. However, these reservoirs face challenges, such as rapid initial wellhead pressure and production decline, leading to extended periods of low-pressure production. To address these issues and enhance the production during the low-pressure stage, pressurized mining is considered as an effective measure. Determining the appropriate pressurization target and method for the shale gas wells is of great practical significance for ensuring stable production in shale gas fields. This study takes into account the current development status of shale gas fields and proposes a three-stage pressurization process. The process involves primary supercharging at the center station of the block, secondary supercharging at the gas collecting station, and the introduction of a small booster device located behind the platform separator and in front of the outbound valve group. By incorporating a compressor, the wellhead pressure can be reduced to 0.4 MPa, resulting in a daily output of 12,000 to 14,000 cubic meters from the platform. Using a critical liquid-carrying model for shale gas horizontal wells, this study demonstrates that reducing the wellhead pressure decreases the critical flow of liquid, thereby facilitating the discharge of the accumulated fluid from the gas well. Additionally, the formation pressure of shale gas wells is estimated using the mass balance method. This study calculates the cumulative production of different IPR curves based on the formation pressure. It develops a dynamic production decline model for gas outlet wells and establishes a relationship between the pressure depletion of gas reservoirs and the cumulative gas production before and after pressurization of H10 −2 and H10 −3 wells. The final estimated ultimate recovery of two wells is calculated. In conclusion, the implementation of multi-stage pressurization, as proposed in this study, effectively enhances the production of, and holds practical significance for, stable development of shale gas fields.

Shale gas is an unconventional gas source that has great potential to be developed and produced in the future. One area that has great potential in Indonesia is in the South Sumatra basin. For good hydrofracturing planning, we used samples from core rock specimens from field well B in the Talangakar formation at a depth of 2289 m with shale lithology located within the South Palembang sub-basin in the South Sumatra basin. We tested the sample by multi-stage triaxial (MST). MST is a compression test requiring only one rock specimen to be tested in three cycle stages with different confined pressures From this test, the curve of Stress-Strain, yield point, elastic zone and plastic zone is obtained. Then it can also be generated Mohr-Coulomb curve, elastic parameters, i.e: Young’s modulus, Poisson’s ratio, etc. The results of this measurement are also useful for predicting the minimum horizontal stress which is very important in the design of hydraulic fracturing in shale gas.

The deep shale gas resources in the Luzhou area of the southern Sichuan Basin are abundant and have been identified as a key replacement field for natural gas development following the medium-to-shallow shale gas fields in Changning and Weiyuan. However, the frequent occurrence of “pre-deformation without fracturing” in horizontal wells has significantly restricted large-scale production. In this study, the Lu203 and Yang101 well areas were analyzed to investigate the characteristics of casing deformation and the correlation with faults and natural fractures (fracture systems). A numerical model of multi-stage fracturing for platform wells was established based on microseismic event data, and the effects of fracturing on the stress and casing stress of adjacent wells were simulated and analyzed. The results indicate that the development of fracture systems is the primary cause of the “pre-deformation without fracturing” phenomenon. The propagation of fracturing fluid through fractures significantly increases the stress and loading around adjacent wells, causing casing stress to exceed its yield strength. To mitigate this issue, a method involving the injection of approximately 10 MPa of internal casing pressure into unfractured wells was proposed, effectively reducing the risk of casing deformation and failure. This provides technical support for the efficient development of deep shale gas.

In the process of developing tight oil and gas reservoirs, multistage fractured horizontal wells (NFHWs) can greatly increase the production rate, and the optimal design of its fracturing parameters is also an important means to further increase the production rate. Accurate production prediction is essential for the formulation of effective development strategies and development plans before and during project execution. In this study, a novel workflow incorporating machine learning (ML) and particle swarm optimization algorithms (PSO) is proposed to predict the production rate of multi-stage fractured horizontal wells in tight reservoirs and optimize the fracturing parameters. The researchers conducted 10,000 numerical simulation experiments to build a complete training and validation dataset, based on which five machine learning production prediction models were developed. As input variables for yield prediction, eight key factors affecting yield were selected. The results of the study show that among the five models, the random forest (RF) model best establishes the mapping relationship between feature variables and yield. After verifying the validity of the Random Forest-based yield prediction model, the researchers combined it with the particle swarm optimization algorithm to determine the optimal combination of fracturing parameters under the condition of maximizing the net present value. A hybrid model, called ML-PSO, is proposed to overcome the limitations of current production forecasting studies, which are difficult to maximize economic returns and optimize the fracturing scheme based on operator preferences (e.g., target NPV). The designed workflow can not only accurately and efficiently predict the production of multi-stage fractured horizontal wells in real-time, but also be used as a parameter selection tool to optimize the fracture design. This study promotes data-driven decision-making for oil and gas development, and its tight reservoir production forecasts provide the basis for accurate forecasting models for the oil and gas industry.

Compared with conventional gas reservoirs, deep shale gas reservoirs are characterized by developed faults and fractures, strong heterogeneity, high stress sensitivity, and complex in situ stress distribution. To address traditional 3D static models’ inability to predict in situ stress changes in strongly heterogeneous reservoirs during fracturing, this study takes the deep shale gas in the Zigong block of the Sichuan Basin as an example. By comprehensively considering the heterogeneity and anisotropy of geomechanical parameters and natural fractures in shale gas reservoirs, a 4D in situ stress multi-physics coupling model for shale gas reservoirs based on geology–engineering integration is established. Through coupling geomechanical parameters with fracturing operation data, the dynamic evolution laws of multi-scale stress fields from single-stage to platform-scale during large-scale fracturing of horizontal wells in deep shale gas reservoirs are systematically studied. The research results show the following: (1) The fracturing process has a significant impact on the magnitude and direction of the stress field. With the injection of fracturing fluid, both the minimum and maximum horizontal principal stresses increase, with the minimum horizontal principal stress rising by 1.8–6.4 MPa and the maximum horizontal principal stress by 1.1–3.2 MPa; near the wellbore, there is an obvious deflection in the direction of in situ stress. (2) As the number of fracturing stages increases, the minimum horizontal principal stress shows an obvious cumulative growth trend, with a more significant increase in the later stages, and there is a phenomenon of stress accumulation along the wellbore, with the stress difference decreasing from 15 MPa to 11 MPa. (3) The on-site adoption of the fracturing operation method featuring overall flush advancement and inter-well staggered fracture placement has achieved good stress balance; comparative analysis shows that the stress communication degree of the 400 m well spacing is weaker than that of the 300 m well spacing. This study provides a more reasonable simulation method for large-scale fracturing development of deep shale gas, which can more accurately predict and evaluate the dynamic stress field changes during fracturing, thereby guiding fracturing operations in actual production.

Shale plays with pre-existing natural fractures can yield significant production when operating horizontal wells with multi-stage hydraulic fracturing (HWMHF). This work proposes a general, robust, and integrated framework for estimating optimal HWMHF design parameters in an unconventional naturally fractured oil reservoir. This work considers uncertainty in both the distribution of the natural fractures and uncertainty in three geo-mechanical parameters: the internal friction factor, the cohesion coefficient, and the tensile strength. Because a maximum of five design variables is considered, it is appropriate to apply derivative-free algorithms. This work considers versions of the genetic algorithm (GA), particle swarm optimization (PSO), and general pattern search (GPS) algorithms. The forward model consists of two linked software programs: a geo-mechanical simulator and an unconventional shale oil simulator. The two simulators run sequentially during the optimization process without human intervention. The in-house geo-mechanical simulator model provides sufficient computational efficiency so that it is feasible to solve the robust optimization problem. An embedded discrete fracture model (EDFM) is implemented to model large-scale fractures. Two cases strongly verified the feasibility of the framework for the optimization of HWMHF, and the average comprehensive NPV increases by 35% and 102.4%, respectively. By comparison, the pattern search algorithm is more suitable for HWMHF optimization. In this way, oil and gas scientists are contributing to the energy industry more accurately and resolutely.

Multi-stage hydraulic fracturing is a key technology adopted in the energy industry to make shale gas and shale oil fields profitable. Post-frac fluid soaking before putting wells into production has been found essential for enhancing well productivity. Finding the optimum time to terminate the fluid-soaking process is an open problem to solve. Post-frac shut-in pressure data from six wells in two shale gas fields were investigated in this study based on pressure transient analysis (PTA) to reveal fluid-soaking performance. It was found that pressure-derivative data become scattering after 1 day of well shut in. The overall trend of pressure-derivative data after the first day of well shut in should reflect the effectiveness of fluid soaking. Two wells exhibited flat (zero-slope) pressure derivatives within one week of fluid soaking, indicating adequate time of fluid soaking. Four wells exhibited increasing pressure derivatives within one week of fluid soaking, indicating inadequate time of fluid soaking. This observation is consistent with the reported well’s Estimated Ultimate Recovery (EUR). This study presents a new approach to the assessment of post-frac fluid-soaking performance with real-time shut-in pressure data.

: This study investigates the unsteady flow characteristics of shale oil reservoirs during the depletion development process, with a particular focus on production behavior following fracturing and shut-in stages. Shale reservoirs exhibit distinctive production patterns that differ from traditional oil reservoirs, as their inflow performance does not conform to the classic steady-state relationship. Instead, production is governed by unsteady-state flow behavior, and the combined effects of the wellbore and choke cause the inflow performance curve to evolve dynamically over time. To address these challenges, this study introduces the concept of a “Dynamic IPR curve” and develops a dynamic production analysis method that integrates production time, continuity across multi-stage state fields, and the interactions between tubing flow and choke flow. This method provides a robust framework to characterize the attenuation trend of reservoir productivity and to accurately describe wellbore flow behavior. By applying the dynamic IPR approach, the study overcomes the limitations of conventional methods, which are unable to capture the temporal variations inherent in shale reservoir production. The proposed methodology offers a theoretical foundation for improved production forecasting, optimization of choke size, and analysis of wellbore tubing characteristics, thereby supporting more effective operational decision-making across different stages of shale reservoir development.

In the process of the large-scale hydraulic fracturing of a shale gas field in the Weiyuan area of Sichuan province, the quantitative description and evaluation of hydraulic fracture expansion morphology and the three-dimensional distribution law are the key points of evaluation of block fracturing transformation effect. Many scholars have used the finite element method, discrete element method, grid-free method and other numerical simulation methods to quantitatively characterize hydraulic fractures, but there are often the problems that the indoor physical simulation results are much different from the actual results and the accuracy of most quantitative studies is poor. Considering rock mechanics parameters and based on the displacement discontinuity method (DDM), a single-stage multi-cluster fracture propagation model of horizontal well was established. The effects of Young’s modulus, Poisson’s ratio, the in situ stress difference, the approximation angle, the perforation cluster number and the perforation spacing on the formation of complex fracture networks and on the geometrical parameters of hydraulic fractures were simulated. The research results can provide theoretical reference and practical guidance for the optimization of large-scale fracturing parameters and the quantitative post-fracturing evaluation of horizontal wells in unconventional reservoirs such as shale gas reservoirs.

Horizontal well hydraulic fracturing technology has significantly enhanced the productivity of shale reservoirs. However, our understanding of the expansion patterns within the complex fracture network and fluid seepage mechanisms under field conditions remains inadequate. Here, this work develops a dynamic geomechanical (DG) model to simulate the complete sequence of operations in hydraulic fracturing. This study utilizes a construction procedure that closely mirrors field practices to establish the DG model. Furthermore, the numerical simulation results of the DG model are calibrated with field data. This work adopts a numerical simulation method that integrates unsteady seepage model for multi-stage fractured horizontal wells with the dilation-recompaction model to develop the DG model. It systematically constructs the geological model of the shale reservoir by utilizing segmented logging data and by segmenting production data. The time series evolution system is developed through an iterative process involving discrete time steps. Results show that the DG model can perform history matching on a multi-stage basis, enabling comprehensive and detailed analysis of the entire reservoir. This process effectively replicates the distribution relationship between each reconstruction zone and the overall productivity. Furthermore, the DG model is capable of accurately simulating the dynamic process of injected high-pressure fluids into the reservoir to fracture the rock and the dynamic evolution law of reservoir properties. Hydraulic fracturing creates a fracture zone that centers on the well’s border and spreads outward radially. The injection volume and failure pressure are significantly correlated with the scale of shale reservoir reconstruction. Following the injection of 790.5 m³ of fracturing fluid in the first stage, the fracture half-length can reach around 148 m, essentially fulfilling the design specifications. Permeability can reach up to 86 mD at this moment, and it can even be maintained at the level of 46 mD during production. In conclusion, the DG model broadens the focus of study on the development of shale reservoirs and lays the groundwork for improving productivity and optimizing hydraulic fracturing design.

With the application of multi-stage hydraulic fracturing technology in horizontal wells of shale gas, the number of perforating clusters in each section has gradually increased. How to use temporary plugging and diverting technology to improve the opening efficiency of each perforation cluster is crucial to fracturing effect. This paper analyzes the temporary plugging and diverting effect in multi-cluster fracturing by combination of geological characteristics of shallow shale gas in Taiyang structure and perforation hole size inversion from ultrasonic imaging logging data. The analysis result shows that low formation stress is conducive to opening efficiency of perforation cluster. If the density of the temporary plugging balls is large, it is easy to appear unstable plug and sometime fall off the perforation holes. And it is more inclined to plug the holes at the lower perforating section. This aggravates the appearance of non-uniform fracturing and "super hole". The four-parameter method of treating pressure increase, overlaying positive pressure difference, fracture indication (or pressure drop from abrasion) and stop pump pressure increase is proposed. It can provide a more comprehensive and accurate basis for the analysis and evaluation of temporary plugging effect. It is suggested that "variable density temporary plugging balls + temporary plugging agent" or line-connected temporary plugging balls could further improve the temporary plugging effect. This paper have guiding significance for optimization of multi-cluster temporary plugging fracturing scheme in horizontal wells.

Jimsar shale oil represents a significant unconventional oil and gas resource within China's ultra-deep tight reservoirs. Multistage hydraulic fracturing with multi-cluster perforation in horizontal wells is one of the key technologies for developing Jimsar shale oil. However, due to the characteristics of Jimsar's reservoir, such as ultra-deep, low permeability, strong heterogeneity, and dispersed sweet spots, there are challenges including non-activation of some fracturing clusters and low production contribution. Therefore, it is crucial to comprehensively consider both geological and engineering sweet spots when optimizing the positioning of fracturing stages and clusters. In this paper, reservoir petrophysical properties were classified to characterize the geological sweet spots in horizontal wells, and a K-means clustering algorithm was applied to establish an intelligent optimization model for selecting fracturing stages. Additionally, the downhole mechanical specific energy was used to characterize the rock's mechanical strength, which served as the basis for selecting the optimal engineering sweet spot for fracturing cluster positioning. Finally, practical factors such as field operations, casing collar locations, and bridge plug positions were integrated to achieve balanced fracture initiation. The research results provide a new method for intelligent design of fracturing stage and cluster positioning in hydraulic fracturing, aiming to achieve uniform initiation of multi-cluster fractures and enhance production. The Jimsar Sag is an important demonstration area for shale oil development in China (Hu et al. 2022), with horizontal wells combined with multistage hydraulic fracturing being the key technology for developing this reservoir. The Lucaogou Formation oil reservoir in the Jimsar Sag, a primary lacustrine mixed-type shale oil reservoir currently under exploration and development, represents a major oil and gas exploration area in the Junggar Basin (Chen et al. 2024). This reservoir is characterized by deep burial, low porosity, low permeability, strong heterogeneity, and dispersed sweet spots, leading to uneven stimulation effects during multistage hydraulic fracturing (Wu et al. 2024).

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

No abstract available

In unconventional oil and gas resources, especially shale oil and gas resources with extremely low permeability and porosity, in order to develop effectively, it is necessary to establish perforation and multi-stage fracturing. The machine learning algorithm k-means clustering was used to cluster the five features selected to describe reservoir properties: shale content, porosity, total organic carbon content and those reflecting rock mechanical properties: Young’s modulus and Poisson’s ratio. The data were classified in a high-dimensional space to determine different perforation fracture stages. The classification algorithm XGboost was then used to predict different perforation stages using four conventional logging curves GR, NPRL, VP and DEN. The K-means clustering algorithm based on Euclidean distance can well classify the selected features in the high-dimensional space. The Hopkins statistics of clustering trend is 0.94, showing a good clustering trend. When the classification algorithm is used for prediction, the average accuracy is 0.92, the average recall rate is 0.90, and the average F1 score is 0.90, which can predict different perforated fracture stages well and optimize the design of the perforated fracture stage.

Wellbore integrity is significant to maintain and improve the production performances of shale wells. In Duvernay Canada, casing deformation near the top of Ireton with a few natural faults and cracks is severe during multi-fracturing. It is urgent to reveal the mechanism to reduce the risk of wellbore failure. In this paper, casing deformation and micro-seismic signal at casing shoe is analysed. The maximum deformation of the casing can reach to be 44.4mm. Based on the focal mechanism, it is easy to get the formation slip displacement. Under the condition of geology and wellbore geometry, a three-dimensional stage finite element method considering the whole drilling process is established to simulate the influence of fault on casing deformation. The results indicate that cement sheath at casing shoes intend to be failure during fracturing, where the fracturing fluid will immerse into the formation of Ireton thorough the micro-annulus of cement sheath. When the pore pressure is large enough to activate the natural fault, the micro-seismic signal at the casing shoe is frequent with the magnitude up to 3. Under this condition, the faults slippage can be 55 mm, and the casing deformation will be 34.9 mm. This is consistent with the actual deformation of casing. Along easy-slip formation position, cement property and wellbore structure should be optimized to prevent fracturing fluid entering the formation. Fracturing operation should be optimized to avoid generating high-magnitude seismic signals during the fracturing process, thereby reducing the possibility of casing shear deformation.

Sichuan Basin in China is rich in shale gas resources and has great exploration and development capacity. It is the main area of shale gas exploration and production in China. The proved shale gas reserves discovered by Sinopec in Weirong area exceed 100 billion m3, and they play an important role in the development of shale gas in China. In Sichuan Basin, the use of traditional shale gas production methods such as multi-stage hydraulic fracturing is hampered by serious casing deformation. By December 2019, Sinopec performed hydraulic fracturing operations in 20 wells in this area, where casing deformation was encountered in 10 wells, resulting in an increase of up to 5.69% in the proportion of invalid fracture sections. In order to explain the mechanism of casing deformation during hydraulic fracturing, the geological structures of a shale gas production site in Sichuan Basin with frequent casing deformation were examined, and the geological reasons for this deformation were revealed. In addition, a geological model was established to calculate the influence of formation activation induced by fracturing fluid on the casing load, and formation activation during hydraulic fracturing was studied. The results reported in this paper are of great significance for optimizing hydraulic fracturing parameters and reducing the influence of formation activities on the casing of horizontal wells.

Deep shale gas reservoirs in the southern Sichuan Basin feature well-developed geological discontinuities, including bedding planes and natural fractures. The interaction between Hydraulic fractures (HFs) and these weak planes can cause complex pressure responses and microseismic event patterns during multi-fracture propagation. This study introduces a novel experimental method for multi-stage and multi-cluster hydraulic fracturing in a horizontal well. The simultaneous and sequential HF propagation are analyzed by integrating real-time injection pressure monitoring and acoustic emission (AE) event localization. Characteristic pressure and AE response patterns are identified for different HF propagation behaviors. Results show that multi-cluster HFs within a stage may not initiate simultaneously, with multiple pressure peaks and each associated with high-energy AE events. The initiation pressure and AE energy of previously initiated clusters are higher than those of subsequently initiated clusters. For multi-fracture sequential propagation, subsequent HFs may initiate at an angle to the wellbore due to the stress shadow from previous fractures, eventually coalescing with them. Moreover, under poor cementing quality, longitudinal HFs may initiate and the injection pressure decreases slightly after peak pressure, followed by a gradual increase with weak fluctuations. The pressure drops when the HF crosses a natural weak plane, with high-energy AE events generated at the intersection and low-energy events distributing along the weak plane. When the fracturing fluid seeps along natural discontinuities, the pressure curve fluctuates intensely and periodically, with low-energy AE events along the weak plane. The conclusions provide a guidance for evaluating fracture geometries through interpreting operation pressures and microseismic monitoring results.

As the global demand for clean energy increases, shale gas has emerged as a vital component of natural gas resources and a focal point for research and development. Precise evaluation of the permeability of low-permeability shale rocks is essential for optimizing extraction strategies, such as horizontal drilling and multi-stage fracturing. However, current permeability testing methods face significant challenges, particularly in differentiating between the permeability characteristics of the shale matrix and bedding laminae, which is crucial for understanding gas flow behavior in shale formations. In this paper, we introduce a novel pulse decay method for assessing the permeability of shale bedding laminae, with a focus on the early-stage pressure transmission process. The method develops a nonlinear governing equation that describes the gas flow behavior through bedding laminae and provides an analytical solution for bedding laminae permeability based on early-stage pressure transients. Experimental validation using shale samples from the Longmaxi Formation in the Sichuan Basin, China (with helium as the test gas), shows that the calculated apparent permeability of the samples is in good agreement with the experimental results. Further numerical simulations confirmed the validity of the method. The results indicate that the calculated permeability of the bedding laminae closely matches the model input values and demonstrates improved accuracy compared to conventional pulse decay methods. This new method provides a more accurate means of measuring the permeability of bedding laminae in shale, particularly for shale with well-developed bedding structures. As a valuable complement to traditional pulse decay methods, this approach enhances our ability to characterize the permeability properties of low-permeability rocks by focusing on the early flow stage, thereby contributing to more efficient shale gas resource development.

No abstract available

Based upon published reports, tight-sand and shale gas are one of the largest sources of natural gas under development globally, with annual production increasing dramatically from 2008 to 2023. This was particularly so in China, driven by advancements in drilling and completion technology such as multi-stage hydraulic fracturing in long horizontal wells. Given Australia’s geological setting and industrial environment, which have some similarities with USA and Canada, the country has potential to become a major player in commercially viable tight sand/shale gas production. An estimated 12.93 TCF of 2C contingent gas resources have been identified in Australia, primarily located in the Beetaloo Sub-basin within the greater McArthur Basin, as well as in the Cooper Basin, Canning Basin and Bowen-Surat Basins. However, developing tight-sand and shale gas resources in Australia presents numerous challenges, including their remote location, lack of existing gas export infrastructure, and well productivity constraints due to restrictions on the use of hydraulic fracturing. Additionally, a high-cost environment further hinders the path to commercial production. In China, a small-scale modularised LNG production approach has been successfully applied to tight sand/shale gas developments in the Sichuan Basin, demonstrating how early cash flow and extended production information can provide key support for an operator’s financial position in the market, increasing the chance of development. Lessons from these case studies could be instrumental in overcoming the challenges faced by Australia’s operators for development of this resource type, potentially paving the way to successful commercialisation.

Horizontal well multi-stage fracturing is the primary technology for deep shale gas development, but dense multi-cluster fractures are prone to non-uniform initiation and propagation, requiring real-time monitoring and interpretation techniques to adjust fracturing parameters. Although high-frequency water hammer pressure-monitoring technology shows diagnostic potential, the correlation mechanism between pressure response characteristics and multi-cluster fracture morphology remains unclear. This study utilized outcrop rock samples from the Longmaxi Formation shale to construct a long-injection-tube pipeline system and a 1 kHz high-frequency pressure acquisition system. Through a true triaxial fracturing simulation test system, it systematically investigated the effects of flow rate (50–180 mL/min) and fracturing fluid viscosity (3–15 mPa·s) on water hammer signal characteristics and fracture morphology. The results reveal that when the flow rate rose from 50 mL/min to 180 mL/min, the initiation efficiency of transverse fractures significantly improved, artificial fractures more easily broke through bedding plane limitations, and fracture height propagation became more complete. When the fracturing fluid viscosity increased from 3–5 mPa·s to 12–15 mPa·s, fracture height propagation and initiation efficiency significantly improved, but fewer bedding plane fractures were activated. The geometric complexity of fractures positively correlated with the water hammer decay rate. This research demonstrates a link between water hammer signal features and downhole fracture morphology, giving a theoretical basis for field fracturing diagnostics.

Heterogeneity is an intrinsic property of shale reservoirs, which exhibits long-standing puzzles that it is difficult to optimize the hydraulic fracturing design and may render suboptimal good performance. At present, the selection of single influencing factor is not appropriate due to the one-sidedness and blindness. In this study, the multiple influencing factors were firstly selected from geophysical logging data to establish the structural hierarchy model. And then, the heterogeneity index of single parameters was respectively obtained from the relationship between the Intrinsic Mode Function (IMF) number decomposed by the Empirical Mode Decomposition Technique (EMDT) and its average wavenumber. Meanwhile, the weighting coefficient of multiple influencing factors was determined based on the Analytic Hierarchy Process (AHP). At last, the composite heterogeneity index of multi-stage was calculated combined with the weighting coefficient of multiple influencing factors. A shale gas well was analyzed by using the new quantification method. The results indicate that composite heterogeneity index of multi-stage is good agreement with the fracture pressure derived from hydraulic fracturing data and better than the Coefficient of Variation and the Lorentz coefficient method. Therefore, the quantification method of multiple influencing factors is significantly important to comprehensive evaluate heterogeneity degree within shale reservoirs.

Presented on 27 May 2025: Session 7 Based upon published reports, tight-sand and shale gas are one of the largest sources of natural gas under development globally, with annual production increasing dramatically from 2008 to 2023. This was particularly so in China, driven by advancements in drilling and completion technology such as multi-stage hydraulic fracturing in long horizontal wells. Given Australia’s geological setting and industrial environment, which have some similarities with USA and Canada, the country has potential to become a major player in commercially viable tight sand/shale gas production. An estimated 12.93 TCF of 2C contingent gas resources have been identified in Australia, primarily located in the Beetaloo Sub-basin within the greater McArthur Basin, as well as in the Cooper Basin, Canning Basin and Bowen-Surat Basins. However, developing tight-sand and shale gas resources in Australia presents numerous challenges, including their remote location, lack of existing gas export infrastructure, and well productivity constraints due to restrictions on the use of hydraulic fracturing. Additionally, a high-cost environment further hinders the path to commercial production. In China, a small-scale modularised LNG production approach has been successfully applied to tight sand/shale gas developments in the Sichuan Basin, demonstrating how early cash flow and extended production information can provide key support for an operator’s financial position in the market, increasing the chance of development. Lessons from these case studies could be instrumental in overcoming the challenges faced by Australia’s operators for development of this resource type, potentially paving the way to successful commercialisation. To access the Oral Presentation click the link on the right. To read the full paper click here

At present, large-scale volume fracturing has become the primary technique for reservoir reconstruction. The conductivity associated with multi-scale fractures requires the application of a significant quantity of proppant. Nevertheless, the flowback of the proppant after the fracturing operation may reduce its efficacy. Furthermore, the proppant that ascends to the surface has the potential to erode and compromise surface pipelines, disrupting normal oil and gas production. In addressing the sand production challenges encountered after fracturing operations on the Jimsar platform, two sand control methodologies were proposed: fiber sand control and coated sand control. A comparative evaluation of the efficacy of these two sand control techniques resulted in the development of a multi-stage fiber sand control approach. This approach is specifically designed for horizontal wells following fracturing, with a focus on determining the optimal timing for fiber addition during the different phases of sand addition, aimed at reducing the flowback of proppant. The experimental findings demonstrate that incorporating fibers during the final quarter of the pumping process for 30/50 mesh quartz sand leads to a reduction in the amount of proppant flowback by 59.03%. This approach not only contributes to the stability of the proppant structure at the fracture roots but also minimizes the amount of proppant flowback, reduces material costs, and improves the effectiveness of sand control.

Multi-stage fractured horizontal well technology is an effective development method for unconventional reservoirs; however, shale oil reservoirs with ultra-low permeability and micro/nanopore sizes are still not ideal for production and development. Injecting CO2 into the reservoir, after hydraulic fracturing, gas injection flooding often produces a gas channeling phenomenon, which affects the production of shale oil. In comparison, CO2 huff-n-puff development has become a superior method in the development of multi-stage fractured horizontal wells in shale reservoirs. CO2 huff and injection can not only improve shale oil recovery but also store the CO2 generated in industrial production in shale reservoirs, which can reduce greenhouse gas emissions to a certain extent and achieve carbon capture, utilization, and storage (CCUS). In this paper, the critical temperature and critical parameters of fluid in shale reservoirs are corrected by the critical point correction method in this paper, and the influence of reservoir pore radius on fluid phase behavior and shale oil production is analyzed. According to the shale reservoir applied in isolation to the actual state of the reservoir and under the condition of a complex network structure, we described the seepage characteristics of shale oil and gas and CO2 in the reservoir by embedding a discrete fracture technology structure and fracture network, and we established the numerical model of the CO2 huff-n-huff development of multi-stage fractured horizontal wells for shale oil. We used the actual production data of the field for historical fitting to verify the validity of the model. On this basis, CO2 huff-n-puff development under different gas injection rates, huff-n-puff cycles, soaking times, and other factors was simulated; cumulative oil production and CO2 storage were compared; and the influence of each factor on development and storage was analyzed, which provided theoretical basis and specific ideas for the optimization of oilfield development modes and the study of CO2 storage.

Horizontal well drilling and multi-stage hydraulic fracturing technologies are at the root of commercial shale gas development and exploitation. During these processes, typically, a large amount of working fl uid enters the formation, resulting in widespread water-rock interaction. Deeply understanding such effects is required to optimize the production system. In this study, the mechanisms of water-rock interaction and the associated responses of shale fabric are systematically reviewed for working fl uids such as neutral fl uids, acid fl uids, alkali fl uids and oxidative fl uids. It is shown that shale is generally rich in water-sensitive components such as clay minerals, acid-sensitive components (like carbonate minerals), alkali-sensitive components (like quartz), oxidative-sensitive components (like organic matter and pyrite), which easily lead to change of rock fabric and mechanical properties owing to water-rock interaction. According to the results, oxidizing acid fl uids and oxidizing fracturing fl uids should be used to enhance shale gas recovery. This study also indicates that an aspect playing an important role in increasing cumulative gas production is the optimization of the maximum shut-in time based on the change point of the wellhead pressure drop rate. Another important in fl uential factor to be considered is the control of the wellhead pressure considering the stress sensitivity and creep characteristics of the fracture network.

Economic gas recovery from shale reservoirs is inherently difficult because of the extremely low permeability of these formations. To overcome this challenge, horizontal wells are drilled and subjected to multi-stage hydraulic fracturing treatments, which generate high-conductivity flow pathways. The adoption of these technologies has significantly boosted the economic recovery of gas from shale formations, particularly the Marcellus Shale, which stands as the most productive shale gas play in the United States. The effectiveness of a fracturing treatment in enabling economic gas production from shale reservoirs is governed by the characteristics of the fractures it creates. The propagation of initial fracture, during multi-stage hydraulic fracturing, modifies the initial stress conditions in the surrounding area, commonly referred to as a “stress shadow.” The stress shadow restricts the initiation and subsequent propagation of later fracture stages, leading to the development of less favorable fracture properties. As a result, the uneven contribution of individual fracture stages to gas flow ultimately diminishes overall gas recovery from the horizontal well. For efficient gas drainage from the shale, the fracture stages are often closely spaced. When fracture stages are placed in close proximity, the stress shadow effect can be intensified. Thus, accounting for the stress shadow is essential in the design of hydraulic fracture treatments. This study investigates how fracture spacing, injected fluid volume, and fluid type influence the magnitude of the stress shadow effect, its impact on fracture properties, and the resulting gas recovery from the Marcellus Shale. The goal is to facilitate the optimization of the hydraulic fracture design to mitigate the stress shadow impact and enhance gas production. Data from several Marcellus Shale horizontal wells, along with published findings, were compiled and analyzed to determine the petrophysical and geomechanical characteristics of the formation. These results were then used to construct a reservoir model representative of a Marcellus Shale horizontal well. Fracture properties, altered by the stress shadow, were assessed through hydraulic fracturing simulations and incorporated into the model. Ultimately, the reservoir model was employed to predict the production performance. The results of the investigation confirmed that close stage spacing intensifies the impact of the stress shadow. The stress shadow was found to impair fracture conductivity which negatively impacted gas recovery. The negative impact of the stress shadow on gas recovery was observed to gradually diminish as the production rate declined over time. The volume and type of the fluid injected during fracturing treatment can amplify the stress shadow’s impact.

No abstract available

The injection amount of CO2 is a key parameter for the CO2 fracturing effect of shale oil. In this paper, taking CO2 fracturing in shale oil reservoirs as the research object, first, combining field tests and three‐dimensional well groups, the practical effects of CO2 fracturing in shale oil reservoirs are analyzed. Second, a numerical model for CO2 fracturing in shale oil reservoirs is established, and the effects of CO2 consumption, soaking time on displacement efficiency, are analyzed. Third, the relationship between CO2 intensity and cumulative oil production is compared and analyzed. Results show that: (a) Under different gas‐oil ratios, as CO2 consumption increases, the replacement ratio also increases. (b) As the dissolved gas–oil ratio in the reservoir increases, the replacement ratio decreases under the same consumption, and the CO2‐enhanced oil and reduced viscosity effect are covered by dissolved gas. (c) Under the conditions of a CO2 consumption of 2 t/fracture and an oil–gas ratio of 0.2, after 30 days of soaking, the pressure enters the straight line segment, which is the reasonable time for soaking and the pressure to decrease in the straight line segment.

CO2 fracturing shows promise in unconventional gas reservoirs. However, differences in fluid properties and fracture evolution between CO2 fracturing and traditional water fracturing remain inadequately studied. This paper established a fluid–solid–damage coupling model that accounts for variations in compressibility and viscosity during water and CO2 fracturing. The differences in damage and flow properties were studied between water and CO2 fracturing under the same conditions. Furthermore, the effects of stress ratios and pressurization rates on damage and flow properties were systematically investigated for different bedding structures during CO2 fracturing. The results indicated that permeability, pore pressure, and viscosity increase significantly with damage accumulation but decrease along the fracture propagation direction, while the compressibility shows the opposite trend. The breakdown pressure for water fracturing is higher than that for CO2 fracturing by 19.2%, 10.9%, and 19% in non-bedding shale, parallel bedding shale, and orthogonal bedded shale, respectively. Comparisons of fracture network and cumulative failure number indicate that CO2 can be used to replace water as an effective fracturing fluid. During CO2 fracturing, the parallel bedding shale exhibits the lowest damage initiation pressure and breakdown pressure. Additionally, the fracturing failure number was the highest when the stress ratio was 0.5 for parallel bedding shale and 1 for orthogonal bedding shale. Under the stress ratio of 0.5, the damage initiation pressure and breakdown pressure are the lowest in both cases. Furthermore, an increase in the pressurization rate leads to a higher fracture-tip pressure, which reduces the fracture complexity and the time required for fracturing.

The rapid expansion of reservoir fractures and the enlargement of the area affected by working fluids can be accomplished solely through fracturing operations of oilfield working fluids in geological reservoirs. Supercritical CO2 is regarded as an ideal medium for shale reservoir fracturing owing to the inherent advantages of environmental friendliness, excellent capacity, and high stability. However, CO2 gas channeling and complex propagation of fractures in shale reservoirs hindered the commercialization of Supercritical CO2 fracturing technology. Herein, a simulation method for Supercritical CO2 fracturing based on cohesive force units is proposed to investigate the crack propagation behavior of CO2 fracturing technology under different construction parameters. Furthermore, the shale fracture propagation mechanism of Supercritical CO2 fracturing fluid is elucidated. The results indicated that the propagation ability of reservoir fractures and Mises stress are influenced by the fracturing fluid viscosity, fracturing azimuth angle, and reservoir conditions (temperature and pressure). An azimuth angle of 30° can achieve a maximum Mises stress of 3.213 × 107 Pa and a crack width of 1.669 × 10−2 m. However, an apparent viscosity of 14 × 10−6 Pa·s results in a crack width of only 2.227 × 10−2 m and a maximum Mises stress of 4.459 × 107 Pa. Additionally, a weaker fracture propagation ability and reduced Mises stress are exhibited at the fracturing fluid injection rate. As a straightforward model to synergistically investigate the fracture propagation behavior of shale reservoirs, this work provides new insights and strategies for the efficient extraction of shale reservoirs.

The great success of CO2 fracturing in shale oil reservoirs has not only increased the production capacity of shale oil, but also effectively carried out CO2 geological storage. In this paper, focusing on the microscale displacement characteristics of CO2 fracturing in shale oil reservoirs, first, the impact of oil saturation and gas invasion pressure on gas invasion is discussed. Then, the coupling control mode of oil saturation/pressure for various mechanisms of gas invasion is revealed. Results show that: (a) at lower displacement, the rock core has a lower initiation pressure and is fractured in a shorter period of time; (b) at higher displacement, the required fracturing time is longer and the fracturing pressure increases, but the fracturing effect is good and it is easy to form complex fracture networks; and (c) under higher pressure conditions, more complex fractures can be formed, which is beneficial for reservoir transformation and production improvement.

BCG-CO2 fracturing fluid system is especially suitable for shale gas stimulation with advantage of minimizing the actual water consumption, reducing the damage to formation, recovering more rapidly and efficiently, etc. A major objective of this article is to ascertain the friction performance of BCG-CO2 fracturing fluid in a wide range of experimental conditions for guiding the selection of fracturing parameters. The experimental results showed that the frictional resistance coefficient levels off under the flow velocity greater than 1 m/s. For the impact of the foam quality on the friction resistance coefficient, the completely opposite change rule is showed under foamed and unfoamed conditions.

BCG-CO2 fracturing fluid system is especially suitable for shale gas stimulation with advantage of minimizing the actual water consumption, reducing the damage to formation, recovering more rapidly and efficiently, etc. A major objective of this article is to ascertain the rheological properties of BCG-CO2 fracturing fluid in a wide range of experimental conditions for guiding the selection of fracturing parameters. The experimental results showed that as the temperature reaches 35 °C, the effective viscosity of BCG-CO2 fracturing fluid has an obvious increase. Apparently the shear rate change below 1000 s−1 is sharper than that above 1000 s−1. The effective viscosity presents an increase trend with increasing foam quality under foamed conditions. It has been concluded that the key factors influencing rheological characteristics of BCG-CO2 fracturing fluid are both temperature and foam quality, and the exponential function form can be used to describe the change rule approximately.

No abstract available

No abstract available

CO2 fracturing technology shows innovation and strategic value in both economy and environment. This study proposes a novel CO2 utilization strategy to restore production-induced stress fields and enhance infill well fracturing. A fully coupled fluid–solid model was developed, incorporating complex transport mechanisms and dynamic fracture propagation in shale. The model was solved using a discontinuous discrete fracture approach, enabling continuous simulation of production and fracturing. Two oilfield scenarios were simulated: (1) direct CO2 fracturing of the infill well, and (2) CO2 injection into the parent well to restore the stress field prior to infill fracturing. The simulation results revealed that CO2 injection effectively reestablished the stress field without reservoir damage, increased effective fracture length, and enhanced CH4 production from both infill and parent wells. One-year cumulative gas production improved by up to 23.2%. Additionally, the method offers significant potential for reducing carbon emissions in shale gas development.

With the increasing global demand for energy, the development of unconventional resources has become a focal point of research. Among these, shale gas has drawn considerable attention due to its abundant reserves. However, its low permeability and complex fracture networks present substantial challenges. This study investigates the composite fracturing technology combining supercritical CO2 and slickwater for shale gas extraction, elucidating the mechanisms by which it influences shale fracture roughness and conductivity through an integrated approach of theory, experiments, and numerical modeling. Experimental results demonstrate that the surface roughness of shale fractures increases markedly after supercritical CO2–slickwater treatment. Moreover, the dynamic evolution of permeability and porosity is governed by roughness strain, adsorption expansion, and corrosion compression strain. Based on fluid–solid coupling theory, a mathematical model was developed and validated via numerical simulations. Sensitivity analysis reveals that fracture density and permeability have a pronounced impact on shale gas field productivity, whereas fracture dip angle exerts a comparatively minor effect. The findings provide a theoretical basis for optimizing composite fracturing technology, thereby enhancing shale gas extraction efficiency and promoting effective resource utilization.

No abstract available

No abstract available

Supercritical CO2 (SC-CO2) fracturing represents an emerging waterless stimulation technology with significant advantages for shale gas development. This study initially established stress field models for oriented and spiral perforations using the finite difference method, investigating how perforation configurations influence fracture initiation efficiency. Subsequently, a three-dimensional near-wellbore SC-CO2 fracturing model under spiral perforation conditions was developed using the discrete lattice method coupled with the Span–Wagner equation of state, examining the impacts of geoengineering parameters on competitive fracture initiation and propagation while revealing inter-perforation competition and fracture interaction mechanisms. Finally, fracture morphology differences between conventional hydraulic and SC-CO2 fracturing were analyzed. The results demonstrate that oriented perforations exhibit more pronounced stress concentration conducive to initiation, yet generate greater stress field perturbation than spiral configurations, hindering simultaneous multi-perforation initiation. Consequently, spiral perforations demonstrate superior initiation performance. Increasing perforation density and injection rate intensifies stress shadowing, significantly suppressing initiation efficiency at central perforations while promoting dominant fractures at terminal perforations. This exacerbates imbalanced propagation, thereby impeding primary fracture development and directional extension. Conversely, longer perforations and higher horizontal stress differentials substantially reduce competitive initiation and stress shadowing, thereby diminishing fracture complexity and enhancing primary fracture propagation. Furthermore, hydraulic fracturing exhibits greater near-wellbore propagation imbalance than SC-CO2 fracturing, hindering multi-directional primary fracture growth.

Against the backdrop of global energy transition and strict environmental regulations, supercritical carbon dioxide (scCO2) fracturing and oil displacement technologies have emerged as pivotal green approaches in shale gas exploitation, offering the dual advantages of zero water consumption and carbon sequestration. However, the inherent low viscosity of scCO2 severely restricts its sand-carrying capacity, fracture propagation efficiency, and oil recovery rate, necessitating the urgent development of high-performance thickeners. The current research on scCO2 thickeners faces a critical trade-off: traditional fluorinated polymers exhibit excellent philicity CO2, but suffer from high costs and environmental hazards, while non-fluorinated systems often struggle to balance solubility and thickening performance. The development of new thickeners primarily involves two directions. On one hand, efforts focus on modifying non-fluorinated polymers, driven by environmental protection needs—traditional fluorinated thickeners may cause environmental pollution, and improving non-fluorinated polymers can maintain good thickening performance while reducing environmental impacts. On the other hand, there is a commitment to developing non-noble metal-catalyzed siloxane modification and synthesis processes, aiming to enhance the technical and economic feasibility of scCO2 thickeners. Compared with noble metal catalysts like platinum, non-noble metal catalysts can reduce production costs, making the synthesis process more economically viable for large-scale industrial applications. These studies are crucial for promoting the practical application of scCO2 technology in unconventional oil and gas development, including improving fracturing efficiency and oil displacement efficiency, and providing new technical support for the sustainable development of the energy industry. This study innovatively designed an amphiphilic modified amino silicone oil polymer (MA-co-MPEGA-AS) by combining maleic anhydride (MA), methoxy polyethylene glycol acrylate (MPEGA), and amino silicone oil (AS) through a molecular bridge strategy. The synthesis process involved three key steps: radical polymerization of MA and MPEGA, amidation with AS, and in situ network formation. Fourier transform infrared spectroscopy (FT-IR) confirmed the successful introduction of ether-based CO2-philic groups. Rheological tests conducted under scCO2 conditions demonstrated a 114-fold increase in viscosity for MA-co-MPEGA-AS. Mechanistic studies revealed that the ether oxygen atoms (Lewis base) in MPEGA formed dipole–quadrupole interactions with CO2 (Lewis acid), enhancing solubility by 47%. Simultaneously, the self-assembly of siloxane chains into a three-dimensional network suppressed interlayer sliding in scCO2 and maintained over 90% viscosity retention at 80 °C. This fluorine-free design eliminates the need for platinum-based catalysts and reduces production costs compared to fluorinated polymers. The hierarchical interactions (coordination bonds and hydrogen bonds) within the system provide a novel synthetic paradigm for scCO2 thickeners. This research lays the foundation for green CO2-based energy extraction technologies.

To ensure the economic feasibility of shale oil and gas exploitation, large-scale hydraulic fracturing is essential for increasing recovery volumes by creating more efficient conductivity channels. However, China's continental shale reservoirs present complex geological conditions, making optimization through traditional hydraulic fracturing challenging. Thus, substituting CO2 for water in fracturing fluids to enhance shale reservoirs has garnered significant interest. An orthogonal experimental design was implemented to identify the optimal parameters for CO2 composite fracturing. Analysis of single-factor experiments led to the selection of four key variables: slickwater volume, slickwater displacement, preflush liquid CO2 volume, and proppant addition volume, resulting in 16 experimental configurations. Using numerical simulation of tight oil shale reservoirs, the effective stimulated reservoir volume for each parameter combination was calculated. Variance analysis revealed that increased slickwater volume significantly enhances fracture initiation and propagation. While variations in slickwater displacement and preflush liquid CO2 volume influence fracture network morphology and complexity, they have a lesser effect on the stimulated volume compared to slickwater volume. Proppant quantity primarily affects fracture conductivity with minimal impact on stimulated volume. This research underpins the optimization of Constructional parameters for CO2 composite fracturing.

On a global scale, shale oil/gas has become an important alternative energy source for conventional oil and gas. The potential advantages of supercritical CO2 (ScCO2) make it an ideal alternative to hydraulic fracturing, used for shale reservoir transformation and production increase while also promoting the geological storage of CO2, which is in-line with today’s carbon capture, utilization, and storage technology and helps to address the challenges of global climate change. To further study the fracture propagation and optimization of a complex fracture network (CFN) in ScCO2 fracturing under complex geological conditions using the cohesive module of ABAQUS to establish a fluid structure coupling model and completing indoor and field experimental verification, we introduce the global embedded cohesion zone model (CZM) combined with Python to generate two natural-fracture (NF) distribution models, conjugate and power law, to establish a dispersed mesh model. Based on this model, we studied the fracture propagation problem of ScCO2 fracturing under different engineering and geological conditions. The simulation results will be used as data-driven data to establish an optimization model of the random forest-particle swarm optimization algorithm (RF-PSO) and optimize the CFN. Research has shown that (1) ScCO2 is more inclined to pass through NFs and propagate in the rock matrix, and hydraulic fractures (HFs) combine better with NFs. Compared with hydraulic fracturing, ScCO2 fracturing has significant advantages (only the fracture width is lower than hydraulic fracturing, its initiation pressure and fracture length are much better than hydraulic fracturing, and there are more small fractures, making it easier to form a CFN). (2) During the process of fracture propagation, once dominant fractures form, the trend of the “Matthew effect” is inevitable. The process of fracture propagation is influenced by multiple factors, especially the distribution of NFs; the larger the reservoir filtration coefficient is, the more ScCO2 fracturing fluid that is lost, which is more unfavorable for fracturing construction. While maintaining the same amount of fracturing fluid injection, as the displacement increases, the fracture complexity increases, and the fracturing control range expands. Compared with other parameters, the effect of fracturing fluid temperature (FFT) on the expansion of ScCO2 fracturing fractures is not significant. (3) The established RF-PSO optimization model has an error of 2.89%, which can well adapt to CFN optimization problems under complex NF conditions and reduce uncertainty. We propose in this article a research method for fracture network optimization from fracture modeling, dynamic simulation, and optimization modeling. By combining numerical simulation and machine learning, the CFN optimization design of ScCO2 fracturing under CFN conditions is achieved, providing a research approach for the optimization of fracturing in fractured reservoirs.

Hydraulic fracturing is a widely employed technique for stimulating unconventional shale gas reservoirs. Supercritical CO2 (SC-CO2) has emerged as a promising fracturing fluid due to its unique physicochemical properties. Existing theoretical models for calculating breakdown pressure often fail to accurately predict the outcomes of SC-CO2 fracturing due to the complex, nonlinear interactions among multiple influencing factors. In this study, we conducted fracturing experiments considering parameters such as fluid type, flow rate, temperature, and confining pressure. A fully connected neural network was then employed to predict breakdown pressure, integrating both our experimental data and published datasets. This approach facilitated the identification of key influencing factors and allowed us to quantify their relative importance. The results demonstrate that SC-CO2 significantly reduces breakdown pressure compared to traditional water-based fluids. Additionally, breakdown pressure increases with higher confining pressures and elevated flow rates, while it decreases with increasing temperatures. The multi-layer neural network achieved high predictive accuracy, with R, RMSE, and MAE values of 0.9482 (0.9123), 3.424 (4.421), and 2.283 (3.188) for training (testing) sets, respectively. Sensitivity analysis identified fracturing fluid type and tensile strength as the most influential factors, contributing 28.31% and 21.39%, respectively, followed by flow rate at 12.34%. Our findings provide valuable insights into the optimization of fracturing parameters, offering a promising approach to better predict breakdown pressure in SC-CO2 fracturing operations.

Although supercritical CO2 (SC-CO2) fracturing has shown promise in oil and gas development with demonstrated potential, its application in shale gas extraction remains in its infancy globally. In this study, fracturing experiments were conducted with water, liquid CO2 (L-CO2), and SC-CO2, as well as SC-CO2 at varying pump rates. The results reveal that SC-CO2 fracturing produces a highly complex fracture network characterized by fractures of varying numbers, deflection angles, and tortuosity. Analysis of CO2 temperature and pressure data showed a sharp drop in injection pressure and temperature at breakdown, followed by fluctuations until injection stopped. Acoustic emission (AE) monitoring demonstrated that energy released during main fracture initiation significantly exceeded that from CO2 phase transition-driven fracture extension, underscoring the dominant role of main fractures in energy dissipation. Compared to hydraulic fracturing, SC-CO2 fracturing created a seepage area 2.2 times larger while reducing the breakdown pressure by 37.2%, indicating superior stimulation performance. These findings emphasize the potential of SC-CO2 to form intricate fracture networks, offering a promising approach for efficient shale gas extraction.

Extracting gas from unconventional shale reservoirs with low permeability is challenging. To overcome this, hydraulic fracturing (HF) is employed. Despite enhancing shale gas production, HF has drawbacks like groundwater pollution and induced earthquakes. Such issues highlight the need for ongoing exploration of novel shale gas extraction methods such as in situ heating through combustion or pyrolysis to mitigate operational and environmental concerns. In this study, thermally immature shales of contrasting organic richness from Rajmahal Basin of India were heated to different temperatures (pyrolysis at 350, 500 and 650 °C) to assess the temperature protocols necessary for hydrocarbon liberation and investigate the evolution of pore structural facets with implications for CO2 sequestration in underground thermally treated shale horizons. Our results from low-pressure N2 adsorption reveal reduced adsorption capacity in the shale splits treated at 350 and 500 ºC, which can be attributed to structural reworking of the organic matter within the samples leading to formation of complex pore structures that limits the access of nitrogen at low experimental temperatures. Consequently, for both the studied samples BET SSA decreased by ∼58% and 72% at 350 °C, and ∼67% and 68% at 500 °C, whereas average pore diameter increased by ∼45% and 91% at 350 °C, and ∼100% and 94% at 500 °C compared to their untreated counterparts. CO2 adsorption results, unlike N2, revealed a pronounced rise in micropore properties (surface area and volume) at 500 and 650 ºC (∼30%–35% and ∼41%–63%, respectively for both samples), contradicting the N2 adsorption outcomes. Scanning electron microscope (SEM) images complemented the findings, showing pore structures evolving from microcracks to collapsed pores with increasing thermal treatment. Analysis of the SEM images of both samples revealed a notable increase in average pore width (short axis): by ∼4 and 10 times at 350 °C, ∼5 and 12 times at 500 °C, and ∼10 and 28 times at 650 °C compared to the untreated samples. Rock-Eval analysis demonstrated the liberation of almost all pyrolyzable kerogen components in the shales heated to 650 °C. Additionally, the maximum micropore capacity, identified from CO2 gas adsorption analysis, indicated 650 °C as the ideal temperature for in situ conversion and CO2 sequestration. Nevertheless, project viability hinges on assessing other relevant aspects of shale gas development such as geomechanical stability and supercritical CO2 interactions in addition to thermal treatment. Insitu thermal treatment of shales for liberation of hydrocarbons and CO2 sequestration. Significant changes in shale geochemistry and pore properties with increasing temperatures of treatment. Visualizing thermally induced pore evolution in shale: microcracks to collapsed pores. Limitations of N2 in accessing complex pore structures. Insitu thermal treatment of shales for liberation of hydrocarbons and CO2 sequestration. Significant changes in shale geochemistry and pore properties with increasing temperatures of treatment. Visualizing thermally induced pore evolution in shale: microcracks to collapsed pores. Limitations of N2 in accessing complex pore structures.

CO2 fracturing technology has been widely used to develop unconventional oil and gas reservoirs such as shale oil and gas and tight sandstone reservoirs. To mitigate the issues of low viscosity and high friction associated with traditional CO2 fracturing technology, this paper proposes CO2 quasi-dry fracturing technology. Taking the low permeability tight sandstone reservoir in Block X of T oilfield as the research object, indoor experiments were conducted to optimize the ratio of CO2 quasi-dry fracturing fluid. Numerical simulation was used to select the optimal construction displacement using FracproPT, and the temperature and pressure changes in the reservoir and the grid after CO2 injection were analyzed using CMG to lay a foundation for the production practice. The results show that the fracturing fluid formulation system is 70% liquid CO2 + 30% water with 1.2% water-based thickener APQD-6 and 1.2% CO2 thickener APFR-2; the optimal construction displacement is 3 m3/min, and the fracture half-length is 206.2 m; the reservoir temperature responds to the CO2 injection volume more rapidly than the pressure, which indicates that CO2 has a more significant effect on the temperature. The field application results show that the reservoir temperature responds more rapidly to the CO2 injection volume than the pressure, indicating that CO2 has a more significant effect on temperature. The field application results are remarkable. This operation successfully achieved the key parameter indicators of the highest sand ratio of 10% and the average sand ratio of 6%. The daily liquid production of the well was stable at 1.6 t, the daily gas production jumped by 820 m3, and the daily oil production also increased by 0.7 t. The effect of single-well stimulation is very prominent, which strongly verifies the feasibility and effectiveness of CO2 quasi-dry fracturing technology exploiting low-porosity and low-permeability reservoirs. This practical result provides valuable practical guidance for developing similar reservoirs. It is expected to promote the further development and application of low porosity and low permeability reservoir development technology.

No abstract available

Supercritical CO2 (ScCO2)-enhanced shale gas recovery technology offers dual advantages: improving shale gas recovery while reducing CO2 emissions. The permeability of shale reservoirs during CO2 displacement of CH4 is a crucial issue in evaluating the efficacy of shale gas production and CO2 sequestration. In this study, ScCO2 fracturing and displacement experiments were carried out for shale samples, and the fracturing and permeability characteristics of shale were analyzed. The findings indicate that ScCO2 significantly enhances fracturing and permeability, with an overall increase in permeability by three orders of magnitude. Higher injection pressures and lower stress lead to an earlier breakthrough of CO2. The CH4 production rate after CO2 displacement is higher than that under conventional recovery conditions. The cumulative flow of CH4 initially rises with increasing pressure of injection, but subsequently declines throughout the later phases of displacement, leading to a reduced CO2 storage rate and CH4 generation rate. High stress can inhibit CO2 injection and CH4 outflow, reduce CH4 production rate, and promote shale to preferentially adsorb CO2, resulting in higher CO2 storage rate.

No abstract available

No abstract available

CO2 injection composite fracturing is an effective method for shale oil and gas well development. The downhole casing is prone to uniform corrosion, pitting, perforation, and even corrosion fracture in the CO2 environment. Therefore, it is particularly important to reveal the physical characteristics of CO2 under actual geological conditions and the impact of CO2 corrosion on the performance of casing. A mathematical model for the temperature and pressure field of CO2 in the wellbore under fracturing conditions is established in this paper, and the temperature and pressure distribution along the depth of the well is calculated. By optimizing the CO2 state equation and using the S-W equation, Lee model, and RK model to calculate the CO2 density, viscosity and compression factor, respectively, the phase distribution pattern of CO2 along the actual wellbore is obtained. Through CO2 corrosion tests on the casing, the influence of temperature and CO2 concentration on the corrosion rate of the casing is clarified. The peak corrosion rate of Q125 steel corresponds to 80 °C, and the corrosion rate increases with the increase in CO2 concentration. Finally, a prediction model for the uniform corrosion rate of casing under different temperatures and CO2 concentration conditions is obtained, which can provide technical support for the design of CO2-enhanced fracturing technology.

Shale oil resources, noted for their broad distribution and significant reserves, are increasingly recognized as vital supplements to traditional oil resources. In response to the high fracturing costs and swift decline in productivity associated with shale oil horizontal wells, this research introduces a novel approach utilizing CO2 for enhanced shale oil recovery in radial boreholes. A compositional numerical simulation method is built accounted for component diffusion, adsorption, and non-Darcy flow, to explore the viability of this technique. The study examines how different factors—such as initial reservoir pressure, permeability, numbers of radial boreholes, and their branching patterns—influence oil production and CO2 storage. Our principal conclusions indicate that with a constant CO2 injection rate, lower initial reservoir pressures predominantly lead to immiscible oil displacement, hastening the occurrence of CO2 gas channeling. Therefore, maintaining higher initial or injection pressures is critical for effective miscible displacement in CO2-enhanced recovery using radial boreholes. Notably, the adsorption of CO2 in shale oil results in the displacement of lighter hydrocarbons, an effect amplified by competitive adsorption. While CO2 diffusion tends to prompt earlier gas channeling, its migration towards areas of lower concentration within the reservoir reduces the extent of channeling CO2. Nonetheless, when reservoir permeability falls below 0.01 mD, the yield from CO2-enhanced recovery using radial boreholes is markedly low. Hence, selecting high-permeability “sweet spot” regions within shale oil reservoirs for the deployment of this method is advisable. To boost oil production, utilizing longer and broader radial boreholes, increasing the number of boreholes, or setting the phase angle to 0° are effective strategies. Finally, by comparing the production of shale oil enhanced by CO2 with that of a dual horizontal well fracturing system enhanced by CO2, it was found that although the former’s oil production is only 50.6% of the latter, its cost is merely 11.1%, thereby proving its economic viability. These findings present a new perspective for the economically efficient extraction of shale oil, offering potential guidance for industrial practices.

CO2–slickwater hybrid fracturing technology is an essential part of shale gas recovery and CO2 geo-storage. However, the exposure to supercritical CO2 (ScCO2) and slickwater can result in potential changes of the pore structures and surface wetting behavior, which affect the gas transportation and CO2 sequestration security in shale reservoirs. Therefore, in this paper, X-ray diffraction (XRD), low-pressure nitrogen gas adsorption (N2GA), mercury intrusion porosimetry (MIP), and fractal analysis were used to describe the pore characteristics of shale before and after ScCO2–slickwater coupling treatments. Shale’s surface wettability was confirmed by contact angle measurements. After the ScCO2–slickwater treatments, the number of micropores (<3.5 nm) and mesopores (3.5–50 nm) increased, while that of macropores (>50 nm) declined based on the N2GA and MIP experiments. Combined with fractal analysis, we argue that the pore connectivity diminished and the pore structure became more complicated. By analyzing the results of XRD, shale pore changes occurring after the ScCO2–slickwater treatment can be explained by the adsorption of polyacrylamide (PAM). Contact angle measurement results showed that the shale’s surface treated by ScCO2 and slickwater was more hydrophilic than that treated by ScCO2 and water, and indirectly prove our argument above. Hence, the coupling using effect of ScCO2 and slickwater can impair the negative effect of CO2 on the shale capillary force to improve shale gas productivity, but it can negatively affect the security of CO2 sequestration in shale reservoirs.

Estimating the effectiveness of hydraulic fracturing in the context of the incrfease in the shale gas demand is of great significance for enhancing shale gas production, which aims to substantially reduce fossil energy consumption and CO2 emissions. The Zhaotong national shale gas demonstration zone has complex stress structures and well-developed fracture zones, and thus it is challenging to achieve targeted reservoir segment transformation. In this paper, we construct and optimize the geometry of hydraulic fractures at different pressures considering the upper and lower barriers in hydraulic fracturing simulation experiments and numerical modeling. The numerical simulation results show that the pore pressure exhibits a stepped pattern around the fracture and an elliptical pattern near the fracture tip. During the first time of injection, the pore pressure rapidly increases to 76 MPa, dropping sharply afterward, indicating that the fracture initiation pressure is 76 MPa. During the fracture propagation, the fracture length is much greater than the fracture height and width. The fracture width is larger in the middle than on the two sides, whereas the fracture height gradually decreases at the fracture tip in the longitudinal direction until it closes and is smaller near the wellbore than at the far end. The results revealed that the fracture width at the injection point reached the maximum value of 9.05 mm, and then it gradually decreased until the fracture width at the injection point dropped to 6.33 mm at the final simulation time. The fracture broke through the upper and lower barriers due to the dominance of the effect of the interlayer principal stress difference on the fracture propagation shape, causing the hydraulic fracture to break through the upper and lower barriers. The results of the physical simulation experiment revealed that after hydraulic fracturing, multiple primary fractures were generated on the side surface of the specimen. The primary fractures extended, inducing the generation of secondary fractures. After hydraulic fracturing, the width of the primary fractures on the surface of the specimen was 0.382–0.802 mm, with maximum fracture widths of 0.802 mm and 0.239 mm, representing a decrease of 70.19% in the maximum fracture width. This work yielded an important finding, i.e., the urgent need for hydraulic fracturing adaptation promotes the three-dimensional development of a gas shale play.

The depletion of conventional reservoirs has led to increased interest in deep shale gas. Hydraulic fracturing addresses the challenge of developing low-permeability shale, involving hydro-mechanical coupling fracture propagation mechanics. Supercritical CO2 (SC-CO2) has become a promising alternative to fracturing fluids due to its ability to be buried underground after use. The high temperature, pressure, and stress of deep shale lead to the flow of fracturing fluid to plastic deformation of rock, resulting in microfractures. In this paper, we simulate the fracture propagation process of deep shale fractured by SC-CO2 based on the coupling of the Darcy-Brinkman-Biot method, which adopts the Navier-Stokes-like equation to solve the free flow region, and the Darcy equation with Biot’s theory to solve flow in the matrix. To clearly probe the mechanism of deep fracturing from a microscopic perspective, the plastic rock property is taken into consideration. We investigate the effects of injection velocity, rock plastic yield stress, formation pressure, and gas slippage effect on fluid saturation and fracture morphology, and find that increasing the injection rate of fracturing fluid can form better extended fractures and complex fracture networks, improving the fracturing effect. Furthermore, we find that it is more appropriate to adopt SC-CO2 as a fracturing fluid alternative in deep shale with higher plastic yield stress due to higher CO2 saturation in the matrix, indicating greater carbon sequestration potential. High confining pressure promotes the growth of shear fractures, which are capable of more complex fracture profiles. The gas slip effect has a significant impact on the stress field while ignoring the flow field. This study sheds light on which deep shale gas reservoirs are appropriate for the use of SC-CO2 as a fracturing fluid and offers recommendations for how to enhance the fracturing effect at the pore scale.

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This study investigates the shale oil drainage characteristics from the Gulong Sag, The objective is to clarify the development method for effective recovery enhancement of terrestrial shale oil. The investigation employs elastic depletion, CO2 displacement, and CO2 huff and puff coupled with nuclear magnetic resonance (NMR) measurements and numerical simulation methods. The study found that the elastic depletion, CO2 displacement, and CO2 huff and puff utilization efficiencies were 17.4%, 18.87%, and 21%, respectively. The study evaluated the oil drainage efficiency of different pore sizes in elastic depletion and CO2 huff and puff modes. The results demonstrated a clear trend in the order of micropore, mesoporous and macropore, with micropores exhibiting the highest oil drainage efficiency due to gas channeling during CO2 displacement. The use of CO2 huff and puff has been shown to improve oil drainage efficiency by 6.02%∼9.2% for different pore sizes. The numerical simulation optimization results suggest an injection volume of 3,000 t per round per well, an injection rate of 100 t/d, and a soaking time of 20 d for optimal CO2 huff and puff injection. This will increase oil production by 65,000 m³, resulting in an overall improvement of 24%. The study results provide a strong theoretical foundation for improving the recovery rates of terrestrial shale oil and gas through injection.

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Both surfactant solution imbibition and CO2 flooding are widely applied oil recovery techniques in shale oil reservoirs. However, the synergistic oil recovery effect of water‐based medium imbibition and CO2 flooding for shale oil reservoirs is rarely explored, and the mechanisms of synergistic enhanced oil recovery by water‐based medium imbibition and CO2 flooding are still not clear. In this paper, core flooding experiments combined with NMR tests are conducted to explore the synergy between slick water imbibition and CO2 flooding in enhancing shale oil recovery and the governing mechanisms. The results show that (a) the average oil recovery rate of slick water imbibition is 38.86%, and after subsequent CO2 flooding, the oil recovery rate is further increased by 21.93%. (b) Compared with slick water imbibition combined with subsequent slick water flooding, slick water imbibition combined with subsequent CO2 flooding can improve the total oil recovery rate by about 10%. (c) During slick water imbibition combined with subsequent CO2 flooding, slick water primarily mobilizes oil from clay interlayer pores (r < 10 nm), whereas CO2 preferentially displaces oil trapped in pores with radii >10 nm, and the large pore (r > 150 nm) oil recovery rate can reach almost 100% when the miscibility is obtained. (d) During subsequent flooding, compared with slick water, CO2 can improve oil recovery rates in pores with radii >10 nm by more than 10%. Additionally, it enhances imbibition recovery of slick water by improving the hydrophilicity of shale core samples.

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The development of unconventional liquid-rich reservoirs, supercritical carbon dioxide (scCO2) considers a promising fluid to further improve oil recovery of shale oil reservoirs in and after hydraulic fracturing. However, the scCO2 has some disadvantages to limit its application in hydraulic fracturing, such as ultra-low viscosity, asphaltene deposition and high miscible pressure. Diluted microemulsion (DME) shows great potential as the additive of fracturing fluid to improve the well productivity through strengthening the spontaneous imbibition during the shut-in period after hydraulic fracturing. Therefore, it is essential to further understand the synergic effects between scCO2 and DME at the pore scale. In this study, three soaking sequences are designed and compared, which include only scCO2 soaking, water-scCO2-DME soaking sequence, and DME-scCO2-DME soaking sequence using shale cores from the Lucaogou Formation. Low-field nuclear-magnetic-resonance (NMR) technique are utilized to quantify the oil distribution among different pores in each soaking stage. Furthermore, component change of the produced oil is characterized by the gas chromatography (GC). Notably, T1-T2 spectra are introduced to verify the results of T2 spectra and GC. Results show that DME can replace the oil from small pores into large pores and thus improve the extraction effects of scCO2. The solid-liquid and oil-water/scCO2 interactions determine the adhesion work of heavy components. DME can enhance the heavy component (C17+) mobilization through interfacial tension (IFT) reduction and wettability alteration. Combing scCO2 and DME can effectively improve the mobilization of both light and heavy components of crude oil, and thus achieve a better ultimate oil recovery rate.

There are abundant shale oil resources in Yingxiong Ling, Qaidam Basin, but the oil recovery rate is low due to complex lithofacies types, large physical property differences, diverse pore types and structures, and strong heterogeneity. In order to improve the oil recovery efficiency of Yingxiong Ling shale oil, based on the analysis of the factors affecting the micro-mobility of Yingxiong Ling shale oil, through spontaneous imbibition and nuclear magnetic test, the oil mobility evaluation of different lithology reservoirs and different pore structures and the feasibility of surfactant to improve oil recovery were carried out. The research results show that: (1) Yingxiong Ling shale oil has considerable mobile hydrocarbon base, effective seepage channels, high viscosity reduction conditions and elastic properties, and has the potential for efficient development. (2) In the spontaneous imbibition state, the utilization efficiency of laminar limestone and laminar limestone are 10% and 12.5%, respectively, and that of small pores, large pores and texture cracks are 6.7%, 5.2% and 1.8%, respectively. The overall utilization efficiency is low. (3) The solution containing surfactant components can effectively improve the crude oil production degree of Gan Chaigou shale oil reservoir. The variable-viscosity fracturing fluid can increase the oil production efficiency to 21.46%, and the nano-emulsion can increase the oil production efficiency to 33.43%. The surfactant has a significant effect on the EOR of Yingxiong Ling shale oil. Based on the analysis of micromobility, the characteristics of crude oil mobility and the experimental results of enhanced oil recovery by surfactants, it is concluded that the oil recovery of Yingxiong Ling shale oil can be greatly improved by combining high efficiency surfactants with large-scale volumetric fracturing.

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CO2 is highly effective at enhancing shale oil recovery while facilitating geological sequestration. The interaction between supercritical CO2 (ScCO2) and shale significantly alters the wettability, a key factor influencing both the oil recovery efficiency and the CO2 storage capacity. A novel investigation was carried out to explore the dynamic characteristics of the CO2–brine–oil–shale multiphase system and the mechanisms underlying wettability alteration using samples from the Yanchang shale formation in China. The wettability of shale samples was characterized by high-temperature and high-pressure contact angle tests, while quantitative analysis of the mineral composition was conducted through ScCO2-shale reaction experiments combined with XRD. FTIR and zeta potential tests determined the types and amounts of surface charged groups, and 3D surface morphology scanning reflected structural changes. Results showed that ScCO2 injection significantly weakened the water-wetness of shale. Temperature and pressure were key external factors: increasing temperature shifted the wettability from water-wet toward neutral-wet, while higher pressure drove it closer to oil-wet. After ScCO2 treatment, significant alterations in the physicochemical properties of shale were observed, which fundamentally influenced its wettability. The content of clay minerals, encompassing both hydrophilic and hydrophobic phases, was reduced, whereas the proportion of hydrophilic quartz increased. The decrease in hydrophilic hydroxyl groups (OH), increase in oleophilic oxygen-containing groups (C–O–C), and reduction in the zeta potential collectively altered the multiphase interfacial forces, thereby impacting the spreading behavior of liquids on shale surfaces. ScCO2 also increased shale surface roughness at the nanoscale, which can alter fluid distribution by providing additional adsorption sites and modifying the spreading behavior of fluids. These findings provide theoretical support for artificial wettability regulation, aiding shale oil recovery and CO2 storage.

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Shale oil is abundant in geological reserves, but its recovery rate is low due to its unique characteristics of ultra-low porosity, ultra-low permeability, and high clay content. This study investigated the effect of mixed-charge surfactants (PSG) on enhanced oil recovery (EOR) in high-temperature shale reservoirs, building on our previous research. The results indicate that PSG not only has outstanding interfacial activity, anti-adsorption, and high-temperature resistance but can also alter the wettability of shale. After aging at 150 °C for one month, a 0.2% PSG solution exhibited minimal influence on the viscosity reduction and oil-washing properties but significantly altered the oil/water interfacial tension (IFT). Compared to field water, the 0.2% PSG solution enhances the static oil-washing efficiency by over 25.85% at 80 °C. Moreover, its imbibition recovery rate stands at 29.03%, in contrast to the mere 9.84% of field water. Because of the small adhesion work factor of the PSG solution system, it has a strong ability to improve shale wettability and reduce oil/water IFT, thereby improving shale oil recovery. This study provides the results of a laboratory experiment evaluation for enhancing shale oil recovery with surfactants. Furthermore, it holds significant potential for application in the single-well surfactant huff-n-puff process within shale reservoirs.

Scholars are investigating the viability of enhancing shale oil recovery and geological CO2 storage. However, the multi-phase flow and stress sensitivity of fractures intensify the complexity of fractured shale. A semi-analytical model of three-phase flow considering stress-dependent permeability (SDP), desorption, and CO2 huff-n-puff is proposed. A three-region model, comprising a primary fracture region, an enhanced fractured region, and a non-stimulated region, is employed to characterize the zoning of fractured wells. The three-phase distance of investigation is derived to characterize the dynamic drainage of formation fluid. Different stress sensitivity indexes are employed to characterize the SDPs in each region, and Langmuir's theory is used to model the effect of desorption. Then, the inter-region flow rates are provided analytically. Finally, a successive iteration is used to update the dynamic parameters by coupling the material balance equations (MBEs). The production curves exhibit good agreement with the fully numerical result while requiring less computational time (15 min to 3 s). The saturation of PFR influences the gas production within 30 days, and the range of EFR will significantly influence gas production within 500 days. The SDP in fractures and matrix will reduce reservoir production significantly (about 50%). The desorption in matrix will improve the production of gas throughout production. The effects of CO2 huff-n-puff are evaluated by simplifying the effects of CO2 as the change of pressure and pressure–volume–temperature data of the fluid. The production increases significantly (about 22%) when the CO2 content exceeds 20%.

Shale oil, while globally abundant, poses significant development challenges due to its low porosity and ultra-low permeability, leading to difficulties in exploitation and inherently low recovery rates. CO2 huff and puff (H-n-P) technology stands out as a primary method to enhance the recovery efficiency of shale oil reservoirs. However, the extraction mechanisms of shale oil across varying pore throat scales remain poorly understood. Unraveling these mechanisms during the CO2 H-n-P process is crucial for optimizing the recovery rate of shale oil. In this study, we unveil the extraction mechanisms of shale oil across varying pore throat scales during the CO2 H-n-P process, leveraging both physical experiments and numerical simulation technology. Initially, Nuclear Magnetic Resonance (NMR) transverse relaxation was deployed to scrutinize the impact of diverse factors on oil displacement during CO2 H-n-P, examining the micro-pore scale. This analysis delineated the extent of crude oil recovery, the characteristics of micro-pore utilization, and the lower limits of pore accessibility within different pore structures. Subsequently, we constructed a CO2 H-n-P numerical simulation core model, informed by the experimental outcomes of the CO2 H-n-P physical experiment. Within this model, we integrated the pivotal mechanisms of CO2 adsorption/desorption, dissolution, diffusion, and conducted a sensitivity analysis to assess the influential factors on CO2 H-n-P. The results show that: (1) In the initial stage of shale reservoir depletion development, the medium-bore crude oil is first used, and then the large-bore and medium-bore crude oil become the main oil increase, while the small-bore crude oil continues to produce slowly. (2) CO2 H-n-P efficiency is significantly affected by factors such as CO2 injection timing, injection volume, injection speed, smothering time and H-n-P cycles. (3) The cumulative recovery degree increased with the increase of injection amount, and the final recovery degree reached 30.05%; The degree of recovery decreases with the increase of injection rate, increases first and then stabilizes with the increase of smothering time, and the optimal smothering time is 6 hours. (4) The recovery degree of a single round decreases with the increase of throughput rounds. The optimal throughput rounds of experiment and digital model optimization are 3 times. The first and second throughput rounds mainly use crude oil in large and medium pores, with a relative utilization degree of 60%~70%; the third round mainly uses crude oil in small pores, with a relative utilization degree of 55%. This study reveals the characteristics and rules of crude oil production during CO2 H-n-P and verifies the results through core numerical simulation, which provides theoretical support for further understanding of the shale oil production process, and has important guiding significance for enhancing oil recovery from CO2 H-n-P.

Injecting air or CO2 into shale reservoirs can significantly enhance oil recovery (EOR) following the initial depletion. However, effectively characterizing the complex pore structure of shale reservoirs poses a challenge, leading to an incomplete understanding of the seepage mechanism and microscopic production characteristics of air/CO2 flooding at different pore scales. In this study, we characterized the microscopic pore structure of shale reservoirs through the reconstruction of visual and quantitative digital cores in multiple dimensions. Subsequently, the online nuclear magnetic resonance (NMR) air/CO2 flooding experiments were conducted, and the production characteristics and influencing factors of microscopic pore crude oil were quantitatively studied. The results show that the pore structure characteristics and connectivity of shale reservoirs are highly intricate and the deterioration of reservoir physical properties correlates with a decreasing trend in pore‐throat coordination numbers and heterogeneity. Shale oil primarily occurs in three types of pores (< 0.1, 0.1–1, and 1–10 μm), and improving micronanopore recovery is urgent for EOR. Crude oil production is observed during the air and oil molecule generation low‐temperature oxidation (LTO) reaction. Additionally, CO2 accelerates mass transfer and oil and gas extraction through molecular diffusion effects, substantially improving shale oil recovery; however, significant differences exist in the microscopic production characteristics of air/CO2 flooding. High‐oxygen‐concentration air flooding or high‐pressure CO2 proves beneficial for EOR, especially for small pores and macropores, which contribute 45.75%–53.42% recovery. This study provides scientific and theoretical support for clarifying the microscopic production characteristics and efficient development of shale oil.

Given the limited improvement in shale oil recovery from microscopic pores through pure CO2 injection, this study explores the potential of gas-solvent-assisted CO2 to enhance recovery by improving miscibility and displacement efficiency in shale oil. Systematic experiments revealed the interaction effects between gas-solvent-assisted CO2 and shale oil. Molecular dynamics simulations were utilized to examine the enhanced oil displacement performance and underlying interaction mechanisms. Furthermore, the role of gas solvents in augmenting CO2's competitive adsorption capabilities was explored. The research results showed that the addition of gas solvents reduces the saturation pressure of shale oil, enhances the CO2 solubility, and increases the expansion coefficient while significantly decreasing the viscosity, density, and minimum miscibility pressure (MMP). In displacement models, gas-solvent-assisted CO2 systems exhibited stronger interactions with octane and SiO2, leading to markedly improved displacement efficiency compared to pure CO2 systems and enabling faster, more complete interactions between CO2 and octane. Furthermore, competitive adsorption experiments highlight the ability of gas solvents to enhance CO2 adsorption over CH4 in nanopores, increasing selectivity coefficients and optimizing adsorption profiles. These findings provide critical insights into the potential of gas-solvent-assisted CO2 injection as a viable strategy for enhancing shale oil recovery and advancing the understanding of gas-liquid interactions in unconventional reservoirs.

CO2 pre-injection fracturing is a promising technique for the recovery of continental shale oil. It has multiple advantages, such as oil recovery enhancement, CO2 geological storage and water consumption reduction. Compared with conventional CO2 huff and puff and flooding, CO2 pre-injection features higher injection rates and pressures, leading to EOR and improved CO2 storage performance. Combining physical experiments and numerical simulation, this research systematically investigated the EOR and storage performance of CO2 pre-injection in continental shale reservoirs. The results showed that CO2 pre-injection greatly improved the oil recovery; after seven cycles of soaking, the average oil recovery factor was 39.27%, representing a relative increase of 31.6% compared with that of the conventional CO2 huff and puff. With the increasing pressure, the CO2 solubility grew in both the oil and water, and so did the CO2 adsorption in shale. Numerical simulation indicated that the average CO2 storage ratio of the production stage was 76.46%, which validated the effectiveness of CO2 pre-injection in terms of CO2 geological storage.

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CO2 cyclic gas injection is an effective method for enhanced oil recovery in shale reservoirs, yet the stimulation effectiveness and CO2 utilization/storage efficiency of pure CO2 injection remain limited. In this study, systematic solubility tests were conducted under Jimsar shale reservoir conditions to screen and optimize three nonionic CO2‐soluble surfactants. The optimal surfactant with a concentration of 0.1 wt% was selected for CO2 cyclic gas injection experiments. By integrating nuclear magnetic resonance (NMR) T2 spectrum characterization, the pore‐scale mechanisms were elucidated. Experimental results demonstrate that although the surfactant only moderately reduced the CO2/Jimsar shale oil interfacial tension from 3.26 to 1.09 mN/m, LF‐NMR monitoring revealed its remarkable differential effects on oil recovery from pores of varying sizes: small‐pores (0.01 ms < T 2 < 10 ms) showed a maximum recovery increase of 8.19% per cycle, while meso‐pores (10 ms 

Recovering oil by fracturing fluid imbibition has demonstrated significant potential for enhanced oil recovery (EOR) in tight oil reservoirs. White mineral oil (WMO), kerosene, or saturated alkanes with matched apparent viscosity have been widely used as “crude oil” to investigate imbibition mechanisms in light shale oil or tight oil. However, the representativeness of these simulated oils for low-maturity crude oils with higher viscosity and greater content of resins and asphaltenes requires further research. In this study, imbibition experiments were conducted and T2 and T1–T2 nuclear magnetic resonance (NMR) spectra were adopted to investigate the oil recovery characteristics among resin–asphaltene-rich Jimusar shale oil and two WMOs. The overall imbibition recovery rates, pore scale recovery characteristics, mobility variations among oils with different occurrence states, as well as key factors influencing imbibition efficiency were analyzed. The results show the following: (1) WMO, kerosene, or alkanes with matched apparent viscosity may not comprehensively replicate the imbibition behavior of resin–asphaltene-rich crude oils. These simplified systems fail to capture the pore-scale occurrence characteristics of resins/asphaltenes, their influence on pore wettability alteration, and may consequently overestimate the intrinsic imbibition displacement efficiency in reservoir formations. (2) Surfactant optimization must holistically address the intrinsic coupling between interfacial tension reduction, wettability modification, and pore-scale crude oil mobilization mechanisms. The alteration of overall wettability exhibits higher priority over interfacial tension in governing displacement dynamics. (3) Imbibition displacement exhibits selective mobilization characteristics for oil phases in pores. Specifically, when the oil phase contains complex hydrocarbon components, lighter fractions in larger pores are preferentially mobilized; when the oil composition is homogeneous, oil in smaller pores is mobilized first.

High-pressure air injection (HPAI) is one of the effective methods to improve shale oil recovery after the primary depletion process. However, the seepage mechanisms and microscopic production characteristics between air and crude oil are complicated in porous media during the air flooding process. In this paper, an online nuclear magnetic resonance (NMR) dynamic physical simulation method for enhanced oil recovery (EOR) by air injection in shale oil was established by combining high-temperature and high-pressure physical simulation systems with NMR. The microscopic production characteristics of air flooding were investigated by quantifying fluid saturation, recovery, and residual oil distribution in different sizes of pores, and the air displacement mechanism of shale oil was discussed. On this basis, the effects of air oxygen concentration, permeability, injection pressure, and fracture on recovery were studied, and the migration mode of crude oil in fractures was explored. The results show that the shale oil is mainly found in <0.1 μm (small pores), followed by 0.1–1 μm (medium pores), and 1–10 μm (macropores); thus, it is critical to enhancing oil recovery in pores less than 0.1 and 0.1–1 μm. The low-temperature oxidation (LTO) reaction can occur by injecting air into depleted shale reservoirs, which has a certain effect on oil expansion, viscosity reduction, and thermal mixing phases, thereby greatly improving shale oil recovery. There is a positive relationship between air oxygen concentration and oil recovery; the recoveries of small pores and macropores can increase by 3.53 and 4.28%, respectively, and they contribute 45.87–53.68% of the produced oil. High permeability means good pore-throat connectivity and greater oil recovery, and the production degree of crude oil in three types of pores can be increased by 10.36–24.69%. Appropriate injection pressure is beneficial to increasing the oil–gas contact time and delaying gas breakthrough, but high injection pressure will result in early gas channeling, which causes the crude oil in small pores to be difficult to produce. Notably, the matrix can supply oil to fractures due to the mass exchange between matrix fractures and the increase of the oil drainage area, and the recoveries of medium pores and macropores in fractured cores increased by 9.01 and 18.39%, respectively; fractures can act as bridges for matrix crude oil migration, which means that proper fracturing before gas injection can make the EOR better. This study provides a new idea and a theoretical basis for improving shale oil recovery and clarifies the microscopic production characteristics of shale reservoirs.

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In the Sichuan Basin, over 65% of shale gas resources are stored in deep shale reservoirs (depth>3500m). The complex tectonic evolution in this area and the large burial depth generate extensively-developed and large-scale natural fractures/faults and large principal horizontal stress difference. This condition significantly influences fracture propagation and the resulting geometry. A good understanding of artificial fractures’ location, size, propped length, conductivity, and complexity is pivotal for further fracturing design optimization. However, due to the above geological factors, it is difficult to accurately predict fracture geometry and other properties while fracturing deep shale. To better evaluate the created fracture system and select appropriate fracturing monitoring approaches, four different fracturing monitoring techniques are applied to a single fractured horizontal well in this area, including acoustic-based monitoring (near-field and far-field measurements), high-frequency-pressure-based monitoring, microseismic monitoring, and pressure-fall-off-data-based interpretation. For acoustic-based monitoring, about 5 min to 10 min after the main fracturing is stopped (the water hammer effect ends), 6 sets of active sound waves are emitted to monitor the fracture system. The near-field connectivity index (NFCI), far-field conductivity index (FFCI), fracture length, height, and width can be obtained. As for the high-frequency-pressure-based monitoring, during the fracturing period, the high-frequency pressure fluctuation information is collected at the wellhead, and the fracture initiation is analyzed based on the high-frequency pressure wave cepstrum. For each stage, key information, such as the core stimulated reservoir volume (SRV), SRV region equivalent permeability, perforation cluster opening ratio, fracturing-fluid-reached length, propped fracture length, fracture height, fracture conductivity, and fracture geometry index, can be interpreted. Microseismic monitoring is a fracture geometry monitoring and analyzing method using weak seismic waves induced by subsurface stress changes and fractures. For each stage, it offers the number of seismic events, SRV azimuth, length, height, and width. For the pressure-fall-off-data-based interpretation, by using the pressure responses during the pressure-fall-off period after the main fracturing of a stage, effective fracture half-length, main fracture surface area, secondary fracture surface area, and fracture complexity index (FCI, the surface area ratio of secondary fractures to the main fracture) can be calculated. By comparing 15 stages’ fracture half-length of the analyzed well, we found that, for each stage, the half-length values provided by the four techniques are generally close to each other. Particularly, the data obtained from microseismic monitoring tend to be the largest, while the pressure-fall-off-data-based method's interpretation turns out to be the lowest. Other fracture properties are also documented and their controlling operation parameters are further analyzed. This study can serve as a practice reference for the selection of appropriate fracturing monitoring technique in this region. The pressure-fall-off-data-based interpretation with certain accuracy is a fast and economical fracture monitoring approach.

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Microseismic monitoring is a conventional technique used to evaluate the hydraulic fracturing effect according to the temporal and spatial distribution and evolution of located microseismic events (MEs) at the macroscale. It is generally thought that few or no located MEs reflects poor hydraulic fracturing results and that more located MEs indicate a better result, but the variability in rupture behavior at different rupture scales is ignored. This paper focuses on the characteristics of multiscale rupture of shale by combining laboratory acoustic emission and field microseismic monitoring. The results demonstrate that shear slippage along fractures mainly dominates the rupture behavior. If no pre-existing fracture is present at the microscale, in the laboratory experiment, a rupture mainly occurs along bedding planes, veins and cracks and predominantly slips, which can help develop a fracture network. Because seismic wave energy is related to the rupture scale and stronger MEs are generated by larger ruptures along pre-existing fractures, fault damage zones or isolated small faults, these slippages may cause casing deformation, and the connected fracture networks may result in fluid seepage. A large number of weak MEs are ignored during fracturing because too little energy is released from small ruptures to be effectively detected, but they usually indicate a fracture network and greatly contribute to gas production in the long term. Therefore, ruptures in shale generally occur from the microscale to macroscale and express similar rupture behavior at each scale but result in different seismic characteristics, located ME distributions, fracture evolutions and engineering effects.