Fractured Horizontal Wells Research Articles

Simulation of Proppant Placement in Multiple Simultaneously Propagating Hydraulic Fractures in Horizontal Wells

Simulation of Proppant Placement in Multiple Simultaneously Propagating Hydraulic Fractures in Horizontal Wells

Optimization of Fine-Fracture Distribution Patterns for Multi-Stage and Multi-Cluster Fractured Horizontal Wells in Tight Gas Reservoirs

Optimization of Fine-Fracture Distribution Patterns for Multi-Stage and Multi-Cluster Fractured Horizontal Wells in Tight Gas Reservoirs

Shale Oil Shut-In and Flowback Mechanism and Optimization Strategy

Abstract Shut-in and flowback are critical stages following hydraulic fracturing in shale oil wells. Researching the distribution of reservoir pressure and fluid flow mechanism during shut-in and flowback is important for optimizing these procedures, thereby enhancing well productivity. Therefore, based on the flow mechanism of shale oil, this article establishes a flow equation considering imbibition and seepage, using linear source superposition equivalent to the pressure distribution generated by hydraulic fracturing as the initial condition. The PEBI (Perpendicular BIsection) grid is used to divide the grid for multistage fractured horizontal wells. The simulation results reveal that large-volume fracturing leads to the formation of a high-pressure zone around the wellbore, significantly surpassing the original reservoir pressure, termed as the high-energy band. This high-energy band is demarcated from the original reservoir pressure by the pressure boundary line (PBL). During production, a double-pressure funnel (DPF) manifests within the reservoir, generating a region with the utmost pressure at a specific position within the high-energy band, known as the pressure peak line. Oil located beyond the pressure peak line is unable to flow toward the wellbore. According to the DPF theory of shale oil, fracturing technology should be adopted to form long straight fractures as far as possible whenever feasible to cross the high-energy band. The shale oil optimal duration for shut-in is contingent upon the movement rate of the pressure boundary and the shale imbibition curve.

Utilizing well-reservoir pseudo-connections for multi-stage hydraulic fracturing modeling in tight gas saturated formations

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.

Optimizing the preparation of multi-colored dye-tracer proppants: A potential approach for quantitative localization and volume assessment of proppant flowback in multistage fractured horizontal wells

Proppant flowback is a common phenomenon after hydraulic fracturing of oil and gas wells. Especially in the large-scale sanding mode of horizontal wells, sand production after fracturing is usually serious. Proppant flowback can not only clog wellbore and wear out equipment, add additional hauling and disposal costs, but also reduce conductivity of the propped fractures, severely affecting oil and gas production. However, there is still a lack of effective means for locating sand production in horizontal wells. Traditional tracer proppants mainly use radioactive elements to monitor the shape of fractures, but they cannot tell the location and amount of sand production. In this work, dye tracer proppant of eight different colors was prepared by dyeing quartz sand proppant. The results show that all the eight kinds of dyes can dye the quartz sand proppant effectively and evenly. The optimal ratio of proppant mass to MB solution volume was determined to be 1:0.015, and the ratio of proppant mass to fixing agent volume was 1:0.0125. The dyed tracer proppant showed good dyeing stability at pH values of 6–13 and surfactant concentrations of 0–200 mg/L. The salinity and fracturing fluid did not affect its stability, and temperature had a negative effect on the stain stability. However, even in the most severe case of decolorization in the experiment, that is, after the dyed proppant was soaked for 24 h at a high temperature of 120 °C, the color of the dried dyed proppant was still clearly distinguished from that of ordinary quartz sand. In theory, using these dyed proppants can potentially tell quantitively the location and volume of sand production during horizontal large-scale fracturing flowback. Since this method has not been used in hydraulic fracturing, it only provides a new way to monitor the sand production of horizontal wells after fracturing. It can provide valuable data for adjusting subsequent fracturing process and has important implications for improving efficiency of fracturing operation of unconventional oil and gas reservoirs.

Effect Evaluation of Staged Fracturing and Productivity Prediction of Horizontal Wells in Tight Reservoirs

In this paper, the effect evaluation and production prediction of staged fracturing for horizontal wells in tight reservoirs are studied. Firstly, the basic characteristics and value of horizontal wells in tight reservoirs are introduced, their geological characteristics, flow mechanism and permeability model are analyzed and the application of grey theory in effect analysis is discussed. Considering the problems of staged fracturing effect evaluation and the production prediction of horizontal wells in tight reservoirs, a BP neural network model based on deep learning is proposed. Due to the interference of multiple physical parameters and the complex functional relationship in the development of tight reservoir fracturing, the traditional prediction method has low accuracy and it is difficult to establish an accurate mapping relationship. In this paper, a BP neural network is used to simulate multivariable nonlinear mapping by modifying the model, and its advantages in solving the coupling relationship of complex functions are brought into play. A neural network model with fracturing parameters as input and oil and gas production as output is designed. Through the training and testing of data sets, the accuracy and applicability of the proposed model for effect evaluation and yield prediction are verified. The research results show that the model can fit the complex mapping relationship between fracturing information and production and provide an effective evaluation and prediction tool for the development of the staged fracturing of horizontal wells in tight reservoirs.

A semi-analytical model for fractured horizontal wells production considering imbibition during shut-in periods

After hydraulic fracturing in tight oil reservoirs, part of the fracturing fluid is retained in the formation. Therefore, it’s essential to investigate the pressure and saturation distributions during and after fracturing to further understand the impact of fluid loss on productivity. Concerning the capillary pressure, fracture propagation, and fracture volume changes, a semi-analytical model was established innovatively. Comparisons between the model’s calculations and actual measurements demonstrate a high level of agreement, validating the model’s accuracy. Furthermore, the impacts of capillary pressure, shut-in time, injection rate, initial reservoir pressure, and initial water saturation on actual production performance were investigated. The results show that the effect of capillary pressure on production in the tight reservoir cannot be ignored. A reasonable shut-in operation should be carried out according to the actual situation. A smaller injection rate should be selected to achieve a larger fracture length and imbibition area. The proportion of oil produced by capillary pressure decreases with the increase of initial pressure. The initial water saturation is positively correlated with oil production and negatively correlated with water production. The imbibition effect of shut-in operation is more obvious in tight reservoirs with low initial pressure and low water saturation.

Discrete element-based multi-cluster hydraulic fracture extension study with temporary plugging and fracturing in horizontal wells

In this paper, a two dimensional-discrete element method complex fracture extension model was developed to simulate the fracture extension behavior in reservoirs during multi-cluster perforation fracturing of horizontal wells by particulate flow and considering temporary plugging conditions. The effect of particle inhomogeneity on the extension of multi-cluster fractures, the change of fracture extending characteristics before and after temporary plugging, and the effect of geological and construction parameters on the extension of multi-cluster fractures under the consideration of temporary plugging conditions are investigated in this model. The results show that: (1) the middle cluster is more difficult to extend than the outermost cluster due to interstitial stress interference; the increased nonuniformity of particles aggravates interstitial stress interference and favors shear fracture extension. (2) Fractures expand substantially when the fracturing fluid reaches 3/4 of the total fluid volume; after temporary plugging, it can promote the uniform extension of fractures and increase the total length of fractures, but the fractures formed in the middle are easy to be captured by the fractures at the two ends and expand along it, and it is not easy to form complex fractures; the timing of plugging is based on the percentage of perforation clusters with fractures already formed, with fracture extension being preferred. (3) The horizontal principal stress difference mainly affects the direction of fracture extension; the number of clusters mainly affects the uniformity of fracture extension; and the fluid flow mainly affects the length of fracture extension.

Transportation and sealing pattern of the temporary plugging ball at the spiral perforation in the horizontal well section

Multistage fracturing of horizontal wells is a critical technology for unconventional oil and gas reservoir stimulation. Ball-throwing temporary plugging fracturing is a new method for realizing uniform fracturing along horizontal wells and plays an important role in increasing oil and gas production. However, the transportation and sealing law of temporary plugging balls (TPBs) in the perforation section of horizontal wells is still unclear. Using COMSOL computational fluid dynamics and a particle tracking module, we simulate the transportation process of TPBs in a horizontal wellbore and analyse the effects of the ball density, ball diameter, ball number, fracturing fluid injection rate, and viscosity on the plugging efficiency of TPB transportation. This study reveals that when the density of TPBs is close to that of the fracturing fluid and a moderate diameter of the TPB is used, the plugging efficiency can be substantially enhanced. The plugging efficiency is greater when the TPB number is close to twice the number of perforations and is lower when the number of TPBs is three times the number of perforations. Adjusting the fracturing fluid injection rate from low to high can control the position of the TPBs, improving plugging efficiency. As the viscosity of the fracturing fluid increases, the plugging efficiency of the perforations decreases near the borehole heel and increases near the borehole toe. In contrast, the plugging efficiency of the central perforation is almost unaffected by the fracturing fluid viscosity. This study can serve as a valuable reference for establishing the parameters for temporary plugging and fracturing.

Division of Main Geological and Engineering Controlling Types of Low-Production Coalbed Methane Well-Blocks and their Stimulation Measures.

At present, the identification of the main factors controlling low-production coalbed methane (CBM) wells and production enhancement measures does not consider geological and reservoir differences between individual wells and the CBM production effect of well groups simultaneously. In view of this, an evaluation index system suitable for use on inefficient well-blocks was established, which involves their geological resource potential, ground stress, coal structure, and comprehensive permeability under engineering influences from a systemic perspective. The main geological engineering types were determined by zoning superposition, and the corresponding stimulation measures were proposed. The evaluation results of the Shizhuang South Block in the Qinshui Basin show that the area of interest can be divided into Class I, II, and III potential areas, of which the Class II potential areas are subdivided into six blocks. In Zone I, the horizontal well infill method is preferred to increase the CBM production from well groups. At the current level of technology, it is difficult to gain economic benefits from Zone III. In Zone II, these stimulation measures such as the infilling method of staged fracturing horizontal wells, refracturing under supplementary injection holes, roof fracturing, the combined method of acidification and secondary fracturing or nitrogen injection and secondary fracturing, the combined method of acidification and controlled displacement secondary fracturing, and controlled displacement repetitive roof fracturing, among others, can be adopted.

Multiple hydraulic fracture propagation simulation in deep shale gas reservoir considering thermal effects

Deep and ultra-deep shale gas will gradually become the focus of unconventional oil and gas resources in the petroleum industry. In the development of shallow shale reservoirs, the multi-cluster hydraulic fracturing of horizontal wells is the commonly applied technique to create a network of fractures and achieve reservoir stimulation. However, for deep shale reservoirs, the behavior of multiple hydraulic fracture propagation is affected by stress interference between fractures. On the other hand, it is also influenced by the temperature disturbances caused by the injection of low-temperature fracturing fluids into high-temperature formations and the resulting thermal effects. Currently, most research on multiple hydraulic fracture propagation in shale only considers the interaction between fluids and solids while neglecting thermal effects. Therefore, based on the displacement discontinuity method, finite volume method, and finite difference method, this study established a numerical model for the non-planar propagation of multi-cluster hydraulic fractures in deep shale, considering the thermal effects. And the model was validated through numerical solutions of the temperature field and double-fracture propagation. Moreover, the number of fracture clusters, pumping rate, and formation temperature were selected as influencing factors, and the differences in multiple hydraulic fracture propagation with and without considering thermal effects were analyzed. The results show that as the formation temperature increases, the thermal effects become more significant, leading to greater differences in the morphology of multi-cluster fractures. Moreover, the thermal effects are more significant when the formation temperature exceeds 90 °C. Additionally, appropriately reducing the number of fracture clusters or increasing the pumping rate can to some extent mitigate stress interference between fractures and promote uniform fracture propagation. The findings of this study contribute to understanding the influence of thermal effects on multiple hydraulic fracture propagation and provide theoretical basis for the efficient development of deep shale gas.

Production Prediction Model of Tight Gas Well Based on Neural Network Driven by Decline Curve and Data

The accurate prediction of gas well production is one of the key factors affecting the economical and efficient development of tight gas wells. The traditional oil and gas well production prediction method assumes strict conditions and has a low prediction accuracy in actual field applications. At present, intelligent algorithms based on big data have been applied in oil and gas well production prediction, but there are still some limitations. Only learning from data leads to the poor generalization ability and anti-interference ability of prediction models. To solve this problem, a production prediction method of tight gas wells based on the decline curve and data-driven neural network is established in this paper. Based on the actual production data of fractured horizontal wells in three tight gas reservoirs in the Ordos Basin, the prediction effect of the Arps decline curve model, the SPED decline curve model, the MFF decline curve model, and the combination of the decline curve and data-driven neural network model is compared and analyzed. The results of the case analysis show that the MFF model and the combined data-driven model have the highest accuracy, the average absolute percentage error is 14.11%, and the root-mean-square error is 1.491, which provides a new method for the production prediction of tight gas wells in the Ordos Basin.

Pressure- and Rate-Transient Model for an Array of Interfering Fractured Horizontal Wells in Unconventional Reservoirs

Summary An analytical solution is presented for pressure- and rate-transient behavior of an array of n parallel and fractured horizontal wells in an unconventional reservoir. Wells are of equal length but otherwise of unidentical properties. Each well has an arbitrary number of uniformly spaced identical, finite-conductivity fractures and is surrounded by a stimulated reservoir volume (SRV). The properties of hydraulic fractures (HFs) and SRVs may vary from well to well. Different properties may also be assigned to the unstimulated reservoir sections between wells. Natural fractures in stimulated and unstimulated reservoir volumes are accounted for by transient dual-porosity idealization. The flow domain is divided into blocks of 1D flow under the trilinear-flow assumption. Solution for each block is obtained analytically and coupled with the solutions for the neighboring blocks by the continuity of pressure and flux at the block interfaces. Drainage volumes of wells are adjusted based on the variation of well production rates because of moving no-flow boundaries between wells. The superposition principle is applied to consider variable-production conditions as well as nonsynchronous production and shut-in schedules of wells. The final solution is in the form of a matrix-vector equation in the Laplace transform domain and inverted into the time domain numerically. The model is robust and reasonably accurate for most practical applications of single-phase oil and gas production from multiple wells in an unconventional reservoir. It is an efficient tool to assess well interference effects for different well completion designs and varying reservoir characteristics. The speed of the model makes it useful for pressure-transient and production-data analysis, as well as for the initial calibration and verification of more complex numerical models.

FOUNDATION AND ASSESSMENT OF OPTIMAL FRACTURE GEOMETRY IN MULTI-STAGE HYDRAULIC FRACTURING OF HORIZONTAL WELLS

The article is dedicated to the calculation and assessment of the optimal geometry of fractures in the context of conducting hydraulic fracturing in horizontal wells. The significance of correctly determining the geometry of fractures to maximize well productivity and the efficiency of the hydraulic fracturing process is considered. The paper analyzes various methods for calculating and evaluating the optimal geometry of fractures, including numerical modeling, experimental research, and practical observations.Additionally, the article covers the results of experimental studies aimed at analyzing the behavior of fractures in different geological conditions. These studies include the analysis of physical and mechanical properties of rock formations, as well as the influence of well parameters on fracture formation. The obtained results can be useful for engineers and specialists in the oil and gas industry in designing and conducting hydraulic fracturing operations to increase hydrocarbon recovery from reservoirs.

Simulation and optimization of unstable dynamic propagation of multiple fractures in the shale formation

Multi-cluster hydraulic fracturing of horizontal wells is a well-adopted technique with high efficiency to increase the production of tight and shale formations. However, the stress shadows among clusters pose challenges to the synchronous propagation of hydraulic fractures during multi-cluster fracturing. In order to explore the fracture propagation mechanism and characteristics under the influence of stress shadow in low-spacing staged multi-cluster fracturing, a three-dimensional hydraulic fracturing model was generated using a lattice-based method. This model considered the impact of geological and engineering parameters on the propagation behavior of multiple fractures in shale formation. A variable pumping approach is adopted, where the fracturing fluid is initially injected at a high rate and then transitioned to a lower rate. Afterward, a method was proposed to quantitatively assess the extent of fracturing in a specific area (i.e., the stimulated area), considering the impact of stress shadow within a single stage. The simulation results demonstrated significant differences in the fracture stimulation area due to the influence of each parameter in the case of uncontrollable geological factors and controllable engineering factors. An increase in both Young’s modulus and stress anisotropy of the reservoir results led to a corresponding increase in the total fracture stimulation area. As the principal stress orientation increased, the fracture stimulation area gradually decreased. In terms of operational parameters, the stimulated area of hydraulic fractures gradually decreased as the fracture spacing increased. With increasing injection rate, the stimulated area initially expanded and then decreased, peaking at an injection rate of 0.04 m3/s. These findings can provide valuable insights into the propagation behavior of multi-cluster hydraulic fractures under uncertain parameters, with significant implications for future engineering applications.

A three-dimensional numerical well-test model for pressure transient analysis in fractured horizontal wells with secondary fractures

During oil and gas reservoir development, multi-stage horizontal wells (MFHWs) and hydraulic fracturing techniques can effectively increase estimated ultimate recovery. However, there still lacks an understanding of the three-dimensional (3D) pressure transient behaviors of multi-stage fractured horizontal wells with secondary fractures. To narrow this gap, a three-dimensional numerical well-test model based on a discrete fracture model and unstructured tetrahedral grids is developed to study the pressure transient behaviors of MFHWs with secondary fractures. The pressure transient solutions of MFHWs with secondary fractures have been demonstrated by model verifications. The results show that the proposed model can accurately capture the complex transient flow around fractures, including early radial flow that is not easily captured by two-dimensional numerical well test models. The proposed model classifies the flow regimes of a MFHW as: wellbore storage and skin effects, early radial flow, bilinear flow, linear flow, elliptical flow, pseudo radial flow, and pseudo-boundary dominated flow. It is found that the fracture geometry has a relatively large effect on the shape of the pressure derivative curve in this work. The hydraulic fracture half-length has the greatest impact on the pressure transient behaviors of the MFHW, followed by fracture height and secondary fracture half-length, as found in this study. Additionally, fracture parameters are evaluated, and actual well testing data are interpreted, taking into account the fracture height. This work is meaningful to understand the three-dimensional pressure transient behaviors of MFHWs with secondary fractures.

Numerical simulation of the simultaneous propagation of multiple hydraulic fractures based on expanded finite element method

Hydraulic fracturing technology with horizontal wells is a highly efficient approach to stimulate the unconventional reservoir by creating lots of fractures to increase the oil and gas recovery rate. However, some field monitoring data indicate that multiple fractures could not propagate uniformly due to stress interference, which leads to a lower stimulation volume and production capacity. Therefore, investigating the stress interference mechanism between multiple fractures is important to obtain a higher production capacity for unconventional reservoirs. In this study, a two-dimensional XFEM (expanded finite element method) model was established to investigate the influence of stress interference on the fracture propagation of multiple fractures in horizontal wells. The different injection parameters, completion parameters, and fracturing patterns were investigated by sixteen simulation cases. The results show that first the influencing degree of stress interference from different parameters is fracture spacing, injection flow rate, number of fractures, and fluid viscosity, respectively. Second, compared to the simultaneous fracturing and sequential fracturing, the zip fracturing pattern (sides fractures created first and then mid-fracture) could create more uniform fractures in the reservoir. Third, a small fracture spacing and a higher injection flow rate could lead to a faster stress interference, but the fluid viscosity and the number of fractures have little effect on the occur timing of stress interference. This study could provide some meaningful perspective on the field fracturing design in horizontal wells.

Extreme massive hydraulic fracturing in deep coalbed methane horizontal wells: A case study of the Linxing Block, eastern Ordos Basin, NW China

Deep coal seams show low permeability, low elastic modulus, high Poisson’s ratio, strong plasticity, high fracture initiation pressure, difficulty in fracture extension, and difficulty in proppants addition. We proposed the concept of large-scale stimulation by fracture network, balanced propagation and effective support of fracture network in fracturing design and developed the extreme massive hydraulic fracturing technique for deep coalbed methane (CBM) horizontal wells. This technique involves massive injection with high pumping rate + high-intensity proppant injection + perforation with equal apertures and limited flow + temporary plugging and diverting fractures + slick water with integrated variable viscosity + graded proppants with multiple sizes. The technique was applied in the pioneering test of a multi-stage fracturing horizontal well in deep CBM of Linxing Block, eastern margin of the Ordos Basin. The injection flow rate is 18 m3/min, proppant intensity is 2.1 m3/m, and fracturing fluid intensity is 16.5 m3/m. After fracturing, a complex fracture network was formed, with an average fracture length of 205 m. The stimulated reservoir volume was 1 987×104 m3, and the peak gas production rate reached 6.0×104 m3/d, which achieved efficient development of deep CBM.

Machine learning-based fracturing parameter optimization for horizontal wells in Panke field shale oil

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.

A semi-analytical rate-transient analysis model for fractured horizontal well in tight reservoirs under multiphase flow conditions

Abstract Rate-transient analysis (RTA) has been widely applied to extract reservoir/fracture properties using analytical and semi-analytical methods with simplifying assumptions. However, current RTA models may lead to misdiagnosis of flow regimes and incorrect estimates of reservoir/fracture information when complex fracture network, multiphase flow, and pressure-dependent properties occur in tight reservoirs simultaneously. A semi-analytical model is developed to account for multiphase flow, complex fracture network, and pressure-dependent properties. The technique uses the black oil formulation and butterfly model to determine three nonlinear partial differential equations (PDEs) that describe the flow of oil, gas, and water in the reservoir with complex fracture network. A modified Boltzmann variable considering the heterogeneity of complex fracture network is proposed to convert the fluid flow PDEs to a set of ordinary differential equations (ODEs) that can be solved through the Runge-Kutta method. A new rate-transient analysis workflow is also developed to improve flow regime identification (ID) and the accuracy for tight oil reservoirs with complex fracture network. It is applied to a synthetic case with equivalently modeled complex fracture network and multiphase flow. The estimated fracture properties are in excellent agreement with model inputs.