Fractured Horizontal Wells Research Articles

This article discusses methods for modeling hydraulic fracturing (HF) in the context of horizontal and vertical wells. One of the modern technologies used to enhance reservoir productivity is acid fracturing, which is widely applied in the oil production industry. The article describes effective methods for integrating fracturing processes into geological and hydrodynamic models, particularly analytical and numerical approaches for accounting for fractures. The influence of the spatial relationship between the fracture and the wellbore axis on fluid flow profiles and oil recovery efficiency is analyzed. During the study, specific formulas were used to characterize the flow in the near-wellbore zone, along with fracture conductivity parameters. When conducting multistage hydraulic fracturing in horizontal wells, the complexity of the spatial geometry of fractures was taken into account, and a model-based approach adapted to real engineering conditions was proposed. The unique value of this work lies in the development of a technically and economically optimized scheme for interval-based acid treatment, considering the distribution of flow rates and filtration properties (both natural and induced) along the horizontal wellbore. This scheme allows for precise identification of low-productivity zones along the well and enables accurate control of stimulation methods. Based on the proposed approach, opportunities are explored for improving well performance, increasing oil recovery, and optimizing operational costs. The proposed modeling method and schematic solutions have significant practical importance for restoring damaged reservoir zones and reactivating idle wells.

Summary In recent years, multistage fractured horizontal well (MFHW) technology has been widely used in the development of unconventional oil and gas resources. Following the fracturing construction, complex fractures are generated around the wellbore. A proper understanding of the fracture characteristics can significantly influence fracturing evaluation and production estimation. To enhance this situation, we developed a semi-analytical model for the interpretation of fracture parameters and formation parameters in 3D space. First, we constructed the coupling between the three systems of reservoir, fracture, and well. Then, we proposed a methodology based on the connectivity matrix for identifying the longitudinal intersection of fractures and the corresponding grid division method. After that, we conducted model verification and sensitivity analysis. Finally, we classified the fracture networks into different types and carried out evaluations. The results indicate that the pressure derivative curve for 3D flow exhibits greater complexity compared with that of 2D flow. Fracture networks have the capacity to supply hydraulic fractures, and different types of fracture networks possess distinct characteristics on the pressure derivative curve. Furthermore, the disparity between vertical and horizontal permeability exerts a notable influence on vertical flow behavior. The pseudoradial flow in the vertical direction appears as a horizontal straightline segment on the pressure derivative curve, serving as an indicator that the fracture does not penetrate the entire formation. This work provides a theoretical basis for fracture evaluation and production prediction.

ABSTRACTAlthough the conversion of end‐of‐lifetime fractured hydrocarbon wells to geothermal wells has gained a strong momentum in research, it is necessary to perform thorough technical assessments of well conversion before pilot testing. The objective of the study was to perform such an assessment on converting fractured horizontal hydrocarbon wells to geothermal wells based on heat transfer efficiency analysis. A mathematical model was developed in this study to simulate the transient heat transfer from shale formations to hydraulic fractures. Sensitivity analysis was performed with the model to identify key factors affecting the heat transfer processes. In all cases studied, the temperature at the exit of the fracture is significantly higher than that at the entrance of the fracture in the first month, indicating high efficiency of heat transfer. Result of this study suggests that converting fractured‐horizontal hydrocarbon wells to geothermal wells is a viable process to extend the lifetime of old wells in oil and gas fields with high‐geothermal gradients. However, well rotation is needed to maintain the energy productivity of reservoir.

Ball-throwing temporary plugging technology addresses non-uniform fracture propagation in multi-cluster fracturing, though controlling ball movement for effective sealing remains challenging. This study investigates the migration of temporary plugging balls in horizontal wells using experimental and numerical simulation approaches. The two-phase flow dynamics of the fracturing fluid and the ball are simulated using a coupled computational fluid dynamics-discrete element method, and the accuracy of this method is validated through experimental testing. The results demonstrate that a reduction in the ball velocity before entering the perforation cluster, combined with an increase in the radial displacement of the ball, is conducive to achieving effective temporary sealing of the perforation. Furthermore, the influence of ball and fracturing fluid parameters on the migration is systematically examined. The results indicate that the critical value for effective perforation plugging falls within a ball-to-perforation diameter ratio range of 1.08–1.15. The injection rate of the fracturing fluid primarily affects the ball's velocity, while the fluid viscosity predominantly influences the ball's radial displacement. Optimal conditions for migrating the ball to the perforation and achieving successful sealing are observed at an injection rate of 4 m3/min and a viscosity of 18 mPa s. By analyzing the two-phase flow dynamics of the fracturing fluid and the plugging ball, this study provides optimized parameters for ball size and fracturing fluid injection, offering valuable insights for enhancing the development efficiency of unconventional oil and gas resources.

In tight oil reservoirs, water huff and puff serves as an effective recovery technique by replenishing formation energy and stabilizing production of volumetric fractured horizontal wells. However, fully coupled flow–geomechanics models currently available are limited in accounting for nonlinear flow characteristics and impose strict mesh constraints under complex geometry conditions. To address these challenges, a numerical model integrating fully coupled flow and geomechanics is established. The model incorporates nonlinear flow behavior and is constructed on the three-dimensional projection-based embedded discrete fracture model (3DpEDFM) to characterize four-dimensional in situ stress evolution during long-term waterflooding and water huff and puff processes in tight reservoirs. Notably, this study presents the first integration of 3DpEDFM with the virtual element method for coupled flow and geomechanics, enabling accurate simulation of complex fracture–matrix interactions without relying on conforming grids. The governing flow and mechanical equations are, respectively, discretized by the finite volume and virtual element methods, leading to a fully coupled nonlinear system that is solved using Newton–Raphson iterations. The model's reliability is demonstrated by benchmarking against the classical Mandel problem and numerical outputs from the commercial simulator tNavigator under idealized scenarios. A case study is further designed according to the geological features of a representative tight reservoir in China, involving long-term waterflooding and water huff and puff implemented via a volumetric fractured horizontal well injection–production system. The simulation results are used to investigate changes in flow behavior and in situ stress evolution. A reduction in horizontal principal stress differences within the stimulated reservoir volume is achieved through the application of water huff and puff, which in turn promotes the development of a complex fracture network and boosts horizontal well productivity.

Temporary plugging ball migration behavior of multi-cluster hydraulic fracturing in horizontal wells based on macroscopic particle model

Multistage fracturing technology for horizontal wells has become a core technology for the effective development of shale and other unconventional oil and gas resources. Following the fracturing and modification of horizontal wells, reliable monitoring of the fracturing effect of each interval, the return of drainage, and the fluid production profile during subsequent production is an important prerequisite for further optimization of the fracturing program and sustainable and effective development. The use of coated tracer sand allows the fracturing effect of horizontal good segments to be assessed and the fluid production profile of horizontal wells to be evaluated in real-time during production. This approach facilitates the improvement of the horizontal well development efficiency. This paper investigates a preparation method for slow-release-coated tracer sands and determines a reasonable preparation method by optimizing the proppant, coated components, and effective components of the tracer. The prepared samples are evaluated for performance parameters, including particle size, salinity, temperature, pH, and mud velocity. The results of this study indicate that the particle size and salinity of tracer particles with intact coated films have a minimal effect on slow-release performance. However, it was observed that the presence of acid enhances the release of slow-release particles, while alkalinity inhibits the release of coated particles. Higher temperature increases the release rate. If the conditions stay the same, then the slow release of coated particles follows a set speed law. But above a certain speed, the release rate and amount increase greatly. This study provides a theoretical basis for using coated slow-release tracer sands in monitoring horizontal well fracturing.

ABSTRACT Hydraulic fracturing is widely employed for the efficient development of tight sandstone reservoirs, which are typically characterized by natural fracture zones. However, the influence of these zones on fracture propagation during multi-cluster staged fracturing in horizontal wells remains poorly understood and warrants further investigation. This study addresses this issue through a combined approach of laboratory experiments and numerical simulations. Artificial rock samples containing natural fractures at varying approaching angles were fabricated from field outcrop materials, and true triaxial hydraulic fracturing experiments were performed. A three-dimensional hydraulic fracturing model incorporating natural fracture zones was developed based on the Discrete Element Method (DEM) and validated by experimental results. Experimental results indicate that larger approaching angles promote hydraulic fracture propagation through natural fractures. Increasing the horizontal stress difference facilitates the crossing of hydraulic fractures through natural fracture zones. A wider natural fracture zone, closer proximity to the horizontal wellbore, and a larger fracture zone angle result in more uneven hydraulic fracture propagation. A higher injection rate also facilitates the crossing of hydraulic fractures through natural fracture zones.

This study addresses the challenge of non-uniform fracture propagation in multi-cluster staged fracturing of horizontal wells by proposing a three-dimensional dynamic simulation method for temporary plugging fracturing, grounded in a fully coupled fluid–solid damage theory framework. A Tubing-CZM (cohesive zone model) coupling model was developed to enable real-time interaction computation of flow distribution and fracture propagation. Focusing on the Xinjiang X Block reservoir, this research systematically investigates the influence mechanisms of reservoir properties, engineering parameters (fracture spacing, number of perforation clusters, perforation friction), and temporary plugging parameters on fracture propagation morphology and fluid allocation. Our key findings include the following. (1) Increasing fracture spacing from 10 m to 20 m enhances intermediate fracture length by 38.2% and improves fracture width uniformity by 21.5%; (2) temporary plugging reduces the fluid intake heterogeneity coefficient by 76% and increases stimulated reservoir volume (SRV) by 32%; (3) high perforation friction (7.5 MPa) significantly optimizes fracture uniformity compared to low-friction (2.5 MPa) scenarios, balancing flow allocation ratios between edge and central fractures. The proposed dynamic flow diversion control criteria and quantified temporary plugging design standards provide critical theoretical foundations and operational guidelines for optimizing unconventional reservoir fracturing.

Multi-stage fractured horizontal wells (MSFHWs) represent a crucial development approach for low-permeability reservoirs, where accurate productivity prediction is essential for production operations. However, existing models suffer from limitations such as inadequate characterization of complex flow mechanisms within the reservoir or computational complexity. This study subdivides the flow process into three segments: matrix, fracture, and wellbore. By employing discretization concepts, potential distribution theory, and the principle of potential superposition, a productivity prediction model tailored for MSFHWs in low-permeability reservoirs is established. Moreover, this model provides a clearer characterization of fluid seepage processes during horizontal well production, which aligns more closely with the actual production process. Validated against actual production data from an offshore oilfield and benchmarked against classical models, the proposed model demonstrates satisfactory accuracy and reliability. Sensitivity analysis reveals that a lower Threshold Pressure Gradient (TPG) corresponds to higher productivity; a production pressure differential of 10 MPa yields an average increase of 22.41 m3/d in overall daily oil production compared to 5 MPa, concurrently reducing the overall production decline rate by 26.59% on average. Larger stress-sensitive coefficients lead to reduced production, with the fracture stress-sensitive coefficient exerting a more significant influence; for an equivalent increment, the matrix stress-sensitive coefficient causes a production decrease of 1.92 m3/d (a 4.32% decline), while the fracture stress-sensitive coefficient results in a decrease of 4.87 m3/d (a 20.93% decline). Increased fracture half-length and number enhance production, with an initial productivity increase of 21.61% (gradually diminishing to 7.1%) for longer fracture half-lengths and 24.63% (gradually diminishing to 5.22%) for more fractures; optimal critical values exist for both parameters.

Staged multi-cluster fracturing in horizontal wells is essential for developing shale oil reservoirs. The stress shadow caused by competitive fracture propagation and bedding interactions is highly complex. A three-dimensional flow-stress-damage coupled numerical model based on the finite element method was developed. It is used to simulate the non-planar propagation behavior and stimulated reservoir volume (SRV) of hydraulic fractures (HFs) when they encounter bedding planes. The HFs may experience arrest, deflection, penetration, and combined bifurcation under different conditions such as cluster spacing, number of clusters, in situ stress, bedding tensile strength, and construction factors in layered shale. The response surface methodology (RSM) was employed to analyze the sensitivity and coupling effects on SRV and identify optimal parameter combinations. The results indicate that the bedding structure and stress interference lead to transverse asymmetric propagation. Intermediate fractures tend to deflect or arrest due to stress superposition, while adjacent fractures commonly exhibit vertical reverse propagation patterns. Reduced cluster spacing and an excessive number of clusters increase fracture interference, thus limiting vertical propagation. A moderate vertical stress difference and bedding tensile strength promote the formation of complex fractures. RSM analysis reveals that injection rate and cluster spacing are the most sensitive factors affecting SRV, while the number of clusters has the least sensitivity, with each factor's influence being nonlinear. Optimizing the interrelationships between cluster spacing, injection rate, and viscosity is crucial for enhancing SRV and fracture network efficiency. These findings provide insights into fracture geometry control mechanisms and SRV optimization strategies in Jiyang Depression's layered shale reservoirs.

This study addresses the coupled influence of the threshold pressure gradient and stress sensitivity during the seepage process in low-permeability reservoirs. By integrating Laplace transform, perturbation transform, the image principle, and the superposition principle, a non-steady-state seepage model for segmented-fractured horizontal wells considering both effects is established for the first time. The analytical solution of the point source function including the threshold pressure gradient (λ) and stress sensitivity effect (permeability modulus α) is innovatively derived and extended to closed-boundary reservoirs. The model accuracy is verified by CMG numerical simulation (with an error of only 1.02%). Based on this, the seepage process is divided into four stages: I linear flow (pressure derivative slope of 0.5), II fracture radial flow (slope of 0), III dual radial flow (slope of 0.36), and IV pseudo-radial flow (slope of 0). Sensitivity analysis indicates the following: (1) The threshold pressure gradient significantly increases the seepage resistance in the late stage (the pressure curve shows a significant upward curvature when λ = 0.1 MPa/m); (2) Stress sensitivity dominates the energy dissipation in the middle and late stages (a closed-boundary-like feature is presented when α > 0.1 MPa−1); (3) The half-length of fractures dominates the early flow (a 100 m fracture reduces the pressure drop by 40% compared to a 20 m fracture). This model resolves the accuracy deficiency of traditional single-effect models and provides theoretical support for the development effect evaluation and well test interpretation of fractured horizontal wells in low-permeability reservoirs.

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.

An optimal location of perforation clusters is critical to obtain a commercial production rate in unconventional tight reservoir reservoirs. At present, the perforation cluster position design method based on overlapping induced stress between fractures is only suitable for multi-stage single-cluster fracturing in horizontal well. Under real well conditions, multiple fractures extend at the same time during multi-stage and multi-cluster fracturing, which is easy to produce stress barrier effects and stress interference effects. These problems put forward higher requirements for selecting the best position of perforating cluster. In this paper, according to the characteristics of multiple fractures extending simultaneously in one stage in multi-stage multi-cluster fracturing, the influence range of induced stress in one stage considering stress barrier and disturbance effect was analyzed. The mathematical model for calculating the induced stress at different locations in one stage is established considering the variation of effective net pressure to the surrounding formation and the resulted resulting distribution of induced stress. Based on this model, a multi-stage and multi-cluster fracture optimization design method for horizontal wells is proposed, which can effectively avoid repeated fractured and non-fractured areas by optimizing the non-equidistant locations of the perforated clusters. Case studies show that this method can effectively avoid refracturing and non-refracturing zones, thus achieving better fracturing results with lower energy consumption.

Natural fractures are widely distributed in hydrate reservoirs, resulting in a fracture-filling type of gas hydrate. However, the complexity of fracture networks, including both hydraulic and natural fractures, complicates the evaluations of gas well productivity. This study investigates the heat and mass transfer dynamics in fracture-filling gas hydrate reservoirs developed using a multi-stage fractured horizontal well. A coupled thermal-hydraulic-mechanical model was developed based on the embedded discrete fracture method, and the model was validated against a commercial numerical simulator, demonstrating high accuracy in predicting gas–water production rates and reservoir pressure, temperature, and hydrate saturation field evolution. The simulation results revealed significant insights into gas and water production rates, flux distributions, and field map distributions. Furthermore, we analyzed the impact of various hydraulic fracture parameters, including fracture numbers, angles, lengths, and morphologies. The simulation results show that fractured wells perform better than non-fractured wells, and the initial daily gas production of a multi-stage fractured horizontal well is 4.05 times that of a fractured vertical well. Besides, fracture geometry critically influences the productivity of the multi-stage fractured horizontal well. The greater the number of hydraulic fractures and the longer the fracture length, the higher the daily and cumulative gas production of the gas well due to higher drainage areas. The cumulative gas production is increased by 131.98% as the number of hydraulic fractures is increased from 3 to 9, whereas the increase is 91.66% as the fracture length is increased from 50 to 200 m. A narrower intersection angle between hydraulic fractures and the wellbore corresponds to a diminished drainage area, thereby exacerbating fracture-driven interference effects and accelerating production decline rates. The intersection density between hydraulic fractures and natural fracture systems serves as the primary determinant of drainage efficiency in fracture-filling gas hydrate reservoirs. The findings have important implications for improving gas well productivity and enhancing the efficient exploitation of fracture-filling gas hydrates.

Numerical simulation study of segmented hydraulic fracturing in horizontal wells of fractured hot dry rocks, at the U.S. FORGE site

Hydraulic fracturing is a crucial technology for developing unconventional oil and gas resources, widely used to enhance low-permeability reservoirs. To clarify the complex fracture propagation behavior in the Shahejie Formation III of the Dagang Oilfield, Bohai Bay Basin, a typical low-permeability reservoir, we conducted laboratory experiments using physical models along with numerical simulations based on the cohesive element method. These approaches were used to study the impact of various formation and operational parameters on the fracture morphology of multi-cluster hydraulic fracturing, including formation properties (permeability, elastic modulus, Poisson’s ratio) and operational conditions (in situ stress, perforation cluster number, injection rate, and fracturing fluid viscosity). The results indicate that an increased horizontal stress difference coefficient can induce a transition from symmetric bi-wing fractures to asymmetric multi-branch fractures. Increasing the number of perforation clusters leads to stress interference between fractures, enhancing fracture complexity. Higher fracturing fluid injection rates promote the formation of long and wide main fractures but reduce the complexity of the fracture network, while fracturing fluid viscosity has a weaker influence on fracture morphology. Among the investigated factors, the number of perforation clusters and the injection rate exhibited a strong control on the fracture parameters. Notably, the variation trends of the fracture parameters with respect to the influencing factors in both experiments and numerical simulations were generally consistent. This study provides theoretical support for complex fracture network prediction and fracturing design optimization for low-permeability reservoirs.

ABSTRACT Carbon capture, utilization, and storage (CCUS) is a vital technology for reducing greenhouse gas emissions. While numerous studies investigate CO2 storage in conventional geological formations, such as depleted oil reservoirs and saline aquifers, this study provides a novel assessment of CO2 sequestration in a depleted oil and gas reservoir characterized by tight sandstone in British Columbia, Canada. Advanced numerical simulations evaluate the feasibility and challenges of CO2 storage in low-permeability formations, focusing on its behavior in a hydraulically fractured horizontal well with 17 fracture stages. Unlike in conventional reservoirs, CO2 exhibits limited migration, remaining concentrated in fractured zones and demonstrating enhanced storage stability. Over a 10-year injection period, more than 100,000 tons of CO2 were successfully injected at a rate of 15,000 m3/day. The study also quantifies the contributions of various trapping mechanisms: residual trapping (10%), solubility trapping (2.9–14.3%, with the highest solubility under ideal conditions), and structural trapping (0.6%). These findings provide new insights into the potential and limitations of CO2 storage in unconventional reservoirs, highlighting both the challenges and unique advantages associated with tight sand formations.

Mechanistic study on the effect of seepage force on fracture propagation behavior in multi-cluster fracturing of horizontal wells

Fracturing interference is a phenomenon that interferes with the production of neighboring wells during hydraulic fracturing. At present, the mechanism and preventive measures of inter-well fracturing interference are still unknown. To address this problem, a fracture extension model and a numerical reservoir model for the hydraulic fracturing of horizontal wells are established in this paper. By simulating the influence of different production times of horizontal wells on the fracture expansion of adjacent fractured wells after fracturing and verifying the feasibility of restoring formation energy to alleviate the inter-well fracturing interference. The results show the following: (1) After the horizontal wells are produced after fracturing, the range of formation depletion will expand. The adjacent fracturing wells are easy to form hydraulic fracture communication with production wells. (2) After production wells are shut-in, the formation energy around the well gradually recovers, and fracture extension in neighboring fractured wells will be limited. (3) Liquid injection in production wells can replenish formation energy in a short time, reducing the possibility of fracture communication in neighboring wells. The results of the study provide a basis for analyzing the mechanism of fracturing interference between horizontal wells and identifying the preventive measures of fracturing interference.