Natural Fracture Network Research Articles

Foam Flow and Mobility Control in Natural Fracture Networks

We study the generation and flow of foam through rough-walled, fractured marble rocks that mimic natural fracture systems in carbonate reservoirs. Flow was isolated to the fracture network because of the very low rock permeability of the marble samples and foam generated in situ during co-injection of surfactant solution and gas. The foam apparent viscosities were calculated at steady pressure gradients for a range of gas fractions, and similar to foam flow in porous media, we identified two flow regimes for foam flow in fractures: a high-quality flow regime only dependent on liquid velocity and a low-quality flow regime determined by the gas and liquid velocities. Variations in local fluid saturation during co-injection were visualized and quantified using positron emission tomography combined with computed tomography.

Modeling natural fracture networks using improved geostatistical inferences

Estimation of a reservoir’s production potential depends on accurate physical and mathematical modeling of natural fracture networks. However, prediction of spatial locations and connectivity of these fracture networks is uncertain due to lack of sufficient data to model them. A stochastic simulation technique has been developed based on Multiple Point Statistics (MPS) using non-gridded training images and flexible spatial templates. The local angle of propagation of fractures are simulated based on the pattern of fractures in the vicinity of the simulation mode. The fracture is propagated in the simulated direction and a new set of simulation nodes are generated. The process is continued until the target fracture lengths are attained. A synthetic case was successfully used for demonstrating the working of the algorithm.

Method for Generating a Discrete Fracture Network from Microseismic Data and its Application in Analyzing the Permeability of Rock Masses: a Case Study

The deformation and failure process of rock masses is accompanied by the initiation, propagation and connection of fractures. The behaviors of fractures under engineering disturbance can be effectively determined by microseismic (MS) monitoring, and such information is essential for the stability analysis of rock masses. Based on moment tensor theory, the geometric properties of focal planes and the failure mechanisms of the seismic source can be determined, and this study proposes criteria for extracting the reasonable fracture from focal planes associated with different failure mechanisms and provides a detailed example. The fracture identified by the proposed criteria is called MS-derived fracture, and a formula describing the aperture is derived from the moment tensor theory and the motion characteristics of the MS-derived fractures associated with different failure mechanisms. This work chose the Shirengou Iron Mine as a case and selected an area exhibiting seepage and rock mass failure as the study area. Based on a three-dimensional noncontact discontinuity scan, a natural discrete fracture network (DFN) was generated. With the help of the proposed fracture generation method, a new DFN based on MS data was generated and is referred to as the MS-derived DFN. With the aid of Oda’s theory, the changes in the permeability value, principal direction and anisotropy degree in the study area were analyzed based on the MS-derived DFN, and the seepage channels in the study area were also determined. Therefore, the research methods in this paper could be used to better understand the changes in the permeability of rock masses based on MS data.

An integrated approach to determining 4D stress development at Castle Cove

Models for basin evolution and natural fracture development often contain many uncertainties. Multiscale approaches to structural analysis assist in reducing these by providing checkpoints for structural evolution to better constrain the development of paleostress phases through time. In this study, we integrate the analysis of calcite twins, magnetic fabrics, stylolites and natural fractures at Castle Cove in the eastern Otway Basin, producing a five-phase model for stress evolution consisting of: phase 1 ~NW–SE Mid-Cretaceous strike-slip or compression; phases 2 and 3 Late Cretaceous extension, coinciding with the development of ~NW–SE and ~NE–SW striking extensional fracture sets; phase 4 ~NE–SW strike-slip and compression, representing an enigmatic period of stress evolution with respect to the current understanding of the Otway Basin; and phase 5, present day ~NW–SE strike-slip stress. The results contribute to a 4D structural history construction for the eastern Otway Basin and suggest that the evolution of the region may require reassessing in order to determine the timing and nature of the detected ~NE–SW oriented compressional event. This study also demonstrates how the use of a calcite stress inversion technique can assist in providing mechanical checkpoints for the evolution of complex natural fracture networks, which can easily be expanded within the sub-surface.

A two‐dimensional extended finite element method model of discrete fracture networks

SummaryThis article presents the first effort to develop a two‐dimensional model using the extended finite element method (XFEM) for the simulation of discrete fracture networks, in which the mesh does not conform to the natural fracture network. The model incorporates contact, cohesion, and friction between blocks of rock. Shear dilation is an important mechanism impacting the overall nonlinear response of naturally fractured rock masses and is also included in the model; physics previously not simulated within an XFEM context. Here, shear dilation is modeled by means of a linear dilation model, capped by a dilation limiting displacement. Highly nonlinear problems involving multiple joint sets are investigated within a quasi‐static context. An explicit scheme is used in conjunction with the dynamic relaxation technique to obtain equilibrium solutions in the face of the nonlinear constitutive models from contact, cohesion, friction, and dilation. The numerical implementation is verified and its convergence is illustrated using a shear test and a biaxial test. The model is then applied to the practical problem of the stability of a slope of fractured rock.

Study on the 3D fluid-solid coupling model with multi-pressure system of shale

The study of fluid solid coupling process in fractured shale reservoir, with massive hydraulic and natural fracture networks, during production is a key scientific issue for accurately understanding the production performance of multi-stage fractured wells. In view of the complicated flow mechanism of shale gas flow, multi-scale media and multiple pressure systems of organic matter/matrix pore/natural fractures and discrete artificial fractures are established to accurately describe the gas flow in shale reservoir. The mathematic model considers mechanisms of non-equilibrium desorption and surface diffusion of the adsorbed gas, the viscous flow and Knudsen diffusion of the free gas, and the influence of matrix pore, natural fracture and artificial fracture pressure system on shale deformation. A fully coupled dual effective stress fluid-solid coupling is established, which considers different pressure system respectively. The influence of rock deformation on shale gas flow in the fractured well production is analyzed. It is found that the natural fracture pressure system is the main influence factor that causes stress sensitivity during the shale gas production. The impact of solid deformation on the permeability of matrix pores continuum is smaller than that of Knudsen diffusion. The apparent permeability of matrix pores continuum is still larger than its original permeability, thus there is no stress sensitivity of matrix pore permeability. With the increase of natural fracture density, the effective stress coefficient of natural fracture pressure system increases rapidly, and the stress sensitivity effect during shale gas production process is stronger.

An optimised Hydraulic Fracturing Treatment on Challenging Rizq Field

Hydrocarbon production from unconventional reservoirs is often associated with hydraulic fracturing operations. In many cases however, the high in-situ stresses and complex natural fracture network hinder an effective stimulation process. Therefore, different strategies are adopted to increase the success chance of stimulation. These strategies are in many cases field dependent and thus cannot be extended to other fields. In this study, we demonstrate a new work flow to ensure a successful stimulation process in an unconventional gas field in Pakistan. Well Rizq-01 was drilled as an exploration into challenging PAB formation which is tight sandstone with 0.3mD permeability but highly fractured. Exploration wells in offset fields were drilled and stimulated in the same formation and resulted in screening-out and inability to place enough proppant due to fracture complexity and high in-situ-stresses. To overcome these challenges, extensive petrophysical and geomechanical analysis were performed to introduce a new workflow for stimulation of the formations with similar characteristics. The workflow includes a) Extract extensivewell log information for better understanding of stress barriers, stress magnitude and orientation, Young’s Modulus, formation fluid information, other essential petrophysical properties, b) Sensitivity analysis on the hydraulic fracturing treatment including the proppant size, type and volume, and fluid systeme.g. the design was based upon geomechanical and petrophysical interpretations of the openhole log data, and c) Redesign of fracturing treatment process utilizing a first-of-its-kind onsite pre-frac test results, showing its helpfulness in the absence of bottom-hole gauge. The study therefore summarizes the challenges, the work flow implemented, and the lesson learnt for successful stimulation job in Rizq Field.

The impact of the coal macrolithotype on reservoir productivity, hydraulic fracture initiation and propagation

Macrolithotypes control the pore-fracture distribution heterogeneity in coal, which impacts stimulation via hydrofracturing and coalbed methane production in the reservoir. Here, the aspects of coalbed methane production that are impacted by macrolithotype were determined from production data from 56 wells in the Hancheng Block, China. The macrolithotype contribution had a significant influence on the well productivity, with dull lithotype-rich (dull and semi-dull coal) coal having significantly lower productivity than wells with bright lithotype-rich (bright and semi-bright coal) coal. The main reason for this difference is that macrolithotypes impart a fracture distribution, which further impacts the hydrofracture stimulation and subsequent coalbed methane production. Here, the hydraulic fracture was evaluated using the appropriate mechanical behavior for each macrolithotype with PFC2D software, and the impact of the macrolithotype on hydraulic fracture initiation and propagation, which are controlled by stress and mechanical properties, was investigated systematically. The result showed that the hydraulic fracture propagation types are controlled by the pre-existing natural fractures. Furthermore, due to the well-developed natural fracture network, the hydraulic fractures in bright coal were mainly composed of the opening, steering propagation, and compound types, forming a lattice-like fracture network. Dull coal is denser, and its hydraulic fractures are characterized as an isolated fracture distribution. The conclusions were verified through monitoring of hydraulic fracture by the microseism wells which show that the fracture in the bright coal is more likely to match the “complex fracture network” description, and the “simple” case when the dull coal is fractured. Meanwhile, the hydraulic fractures mainly open at a shallow depth, but with the increase in depth, the hydraulic fractures are dominated by the crossing type. If the hydraulic fractures are the opening type, only at a higher liquid pressure can the natural fractures in dull coal be initiated. Thus, the difference between hydraulic fractures in bright and dull coal lead to different flow paths and ultimately result in a variation of coalbed methane production. Therefore, during coalbed methane output, a bright coal reservoir will have more potential than a dull coal reservoir, which provides a scientific base for coalbed methane exploration and development.

Modeling acoustic attenuation of discrete stochastic fractured media

The acoustic response has many important roles in seismic exploration and nondestructive testing. It enables the development of fracture classification and sizing. In this paper, we combined Hudson’s effective medium scheme and finite-difference time-domain modeling method to simulate acoustic wave propagation in fractured media. Fractures are represented by discrete fracture networks, allowing for a state-of-the-art representation of natural fracture networks by a negative Exponential Law length distribution. The propagation of acoustic waves that are emitted by a point source and reflected from a fractured area in a 2D digital rock model are examined numerically with the purpose of developing an acoustic inference of fracture properties. In these fractured models, we vary the number and mean length of fractures to explore the relation between internal structure of rock and acoustic wave field characters. The modeling results indicate that acoustic wave field is more sensitive to the fracture number than to the mean of the fracture length. Moreover, a fracture-dependent attenuation analysis of the reflection records of discrete stochastic fractured models is obtained. The frequency- and time- dependent attenuation profiles feature two parts in frequency, (1) fracture-to-background at lower frequencies and (2) fracture-to-fracture at higher frequencies. Our results indicate that accounting for attenuation effects may not only allow for improving estimation of fracture number, but also provide information about geometrical characteristics of length distribution. Such an approach can be used to estimate nature fracture network properties with given acoustic records.

Evaluation of a workflow to derive terrestrial light detection and ranging fracture statistics of a tight gas sandstone reservoir analog

Understanding natural fracture networks in the subsurface is highly challenging, as direct one-dimensional borehole data are unable to reflect their spatial complexity, and three-dimensional seismic data are limited in spatial resolution to resolve individual meter-scale fractures. Here, we present a prototype workflow for automated fracture detection along horizontal scan lines using terrestrial light detection and ranging (t-LIDAR). Data are derived from a kilometer-scale Pennsylvanian (locally upper Carboniferous) reservoir outcrop analog in the Lower Saxony Basin, northwestern Germany. The workflow allows the t-LIDAR data to be integrated into conventional reservoir-modeling software for characterizing natural fracture networks with regard to orientation and spatial distribution. The analysis outlines the lateral reorientation of fractures from a west–southwest/east–northeast strike, near a normal fault with approximately 600 m (∼1970 ft) displacement, toward an east–west strike away from the fault. Fracture corridors, 10–20 m (33–66 ft) wide, are present in unfaulted rocks with an average fracture density of 3.4–3.9 m−1 (11.2–12.8 ft−1). A reservoir-scale digital outcrop model was constructed as a basis for data integration. The fracture detection and analysis serve as input for a stochastically modeled discrete fracture network, demonstrating the transferability of the derived data into standard hydrocarbon exploration-and-production-industry approaches. The presented t-LIDAR workflow provides a powerful tool for quantitative spatial analysis of outcrop analogs, in terms of natural fracture network characterization, and enriches classical outcrop investigation techniques. This study may contribute to a better application of outcrop analog data to naturally fractured reservoirs in the subsurface, reducing uncertainties in the characterization of this reservoir type at depth.

Integration of outcrop, subsurface, and microseismic interpretation for rock-mass characterization: An example from the Duvernay Formation, Western Canada

Identifying and characterizing geomechanical domains is important for understanding how a reservoir will respond to hydraulic fracturing, including interaction with natural fractures to create new permeable pathways. We have used a rock-mass characterization approach, which describes the mechanical reservoir package by combining parameters of the intact rock, such as brittleness, with inferred geometry and density of natural fractures. Insights from outcrop observations are important to complement the interpretation of fracture geometry and density derived from subsurface data, to give a more complete understanding of natural fracture networks. This integrated approach is applied to a data set from the Duvernay play in Western Canada. A synthetic model of the subsurface reservoir is constructed using data from well logs, cores, and outcrop analogs. Numerical simulation of the response of the artificial rock mass to hydraulic fracturing is performed using a distinct element code. Independent validation of the model is obtained by achieving an agreement between the simulated microseismic response and the observed distribution of microseismicity during hydraulic fracturing.

Hydraulic fracturing for improved nutrient delivery in microbially-enhanced coalbed-methane (MECBM) production

Microbially enhanced coalbed methane (MECBM) recovery is a novel method to increase gas production by injecting nutrients, either with/without microorganisms, in depleted CBM wells. However, to be effective, methanogens require that the nutrient must be delivered efficiently by aqueous solution to a maximally large reservoir volume for microbial colonization. This study seeks to improve understanding of solute transport and microbial gas generation in naturally fractured reservoirs that are both pristine and hydraulically fractured. We complete a field-scale numerical simulation using an equivalent multi-continuum method to define the effectiveness of nutrient delivery. The complex pre-existing fracture pattern in the coalbed is represented by an overprinted discrete fracture network (DFN) to capture the natural heterogeneity and anisotropy of fracture permeability. A simplified PKN model is adopted to simulate hydraulic fracture propagation based on linear elastic fracture mechanics (LEFM). The hydraulically stimulated case is compared to the untreated control case, both without and with a network of natural fractures. Saturated cleat area, cumulative injection volume and prediction of methane yields are systematically modeled and analyzed for all three cases. We show that hydraulically stimulated fracture pathways, especially when connecting with a natural fracture network, optimally deliver nutrient remotely from the injection well, thereby increasing nutrient delivery and improving methane production and potential recovery. However, large magnitudes of proppant embedment and related permeability loss in the hydraulic fractures may reduce MECBM recovery. In the optimal production scenario, the methane production rate may reach 31 ft3/ton, an approximately 5-fold increase over that from the pristine unstimulated case.

Numerical study of influence of hydraulic fracturing on fluid flow in natural fractures

Abstract The hydraulic fracturing operation is highly complex in fractured reservoirs. The fundamental key to a successful operation is processing and analysis of the propagation of hydraulic fracturing in a natural fracture network. In this paper, the hydraulic fracturing process is evaluated in a fractured reservoir in southwest Iran. The developing process of induced fracture in a natural fracture network is analysed by the Distinct Element Method (DEM). After determining the fluid flow regime in the natural fractures of the reservoir, hydraulic fracturing is applied along different lengths of the reservoir and in each range, the production rate is checked. Fluid flow in natural fractures after the hydraulic fracturing operation is shown and evaluated in order to evaluate the induced fracture effectiveness in enhancing fluid flow regimes in the reservoir. The reverse suction phenomenon which causes changes in the fluid flow pattern in fractures and will thus affect the production rate is also studied in this paper. Fracture coalescence will cause the induction of natural fractures to hydraulically fracture without their intersection; this is one of the significant parameters in hydraulic fracturing in naturally fractured reservoirs which is also discussed in detail. This paper can present valuable information on fluid flow analysis before and after applying hydraulic fracturing in a fractured reservoir and solve some essential ambiguities in this area.

Influence of data analysis when exploiting DFN model representation in the application of rock mass classification systems

Discrete fracture network (DFN) models have been proved to be effective tools for the characterisation of rock masses by using statistical distributions to generate realistic three-dimensional (3D) representations of a natural fracture network. The quality of DFN modelling relies on the quality of the field data and their interpretation. In this context, advancements in remote data acquisition have now made it possible to acquire high-quality data potentially not accessible by conventional scanline and window mapping. This paper presents a comparison between aggregate and disaggregate approaches to define fracture sets, and their role with respect to the definition of key input parameters required to generate DFN models. The focal point of the discussion is the characterisation of in situ block size distribution (IBSD) using DFN methods. An application of IBSD is the assessment of rock mass quality through rock mass classification systems such as geological strength index (GSI). As DFN models are becoming an almost integral part of many geotechnical and mining engineering problems, the authors present a method whereby realistic representation of 3D fracture networks and block size analysis are used to estimate GSI ratings, with emphasis on the limitations that exist in rock engineering design when assigning a unique GSI value to spatially variable rock masses.

Numerical Simulation of Hydraulic Fracture Propagation in Coal Seams with Discontinuous Natural Fracture Networks

To investigate the mechanism of hydraulic fracture propagation in coal seams with discontinuous natural fractures, an innovative finite element meshing scheme for modeling hydraulic fracturing was proposed. Hydraulic fracture propagation and interaction with discontinuous natural fracture networks in coal seams were modeled based on the cohesive element method. The hydraulic fracture network characteristics, the growth process of the secondary hydraulic fractures, the pore pressure distribution and the variation of bottomhole pressure were analyzed. The improved cohesive element method, which considers the leak-off and seepage behaviors of fracturing liquid, is capable of modeling hydraulic fracturing in naturally fractured formations. The results indicate that under high stress difference conditions, the hydraulic fracture network is spindle-shaped, and shows a multi-level branch structure. The ratio of secondary fracture total length to main fracture total length was 2.11~3.62, suggesting that the secondary fractures are an important part of the hydraulic fracture network in coal seams. In deep coal seams, the break pressure of discontinuous natural fractures mainly depends on the in-situ stress field and the direction of natural fractures. The mechanism of hydraulic fracture propagation in deep coal seams is significantly different from that in hard and tight rock layers.

Topology, connectivity and percolation in fracture networks

The connectivity of a fracture network depends on both its geometry and topology, which may be characterized in terms of the types of nodes and branches in the system. A number of dimensionless parameters (dimensionless intensity (P22, B22), connections per line (CL) and connections per branch (CB), are used to characterize and assess network connectivity based on well-established lattice and continuum percolation models. These models result in networks with only I- and X-nodes, whereas most natural fracture networks have many Y-nodes. A simple scheme to transform IX systems into IYX systems is developed that allows the expected value of dimensionless branch intensity (B22C) at the percolation threshold to be derived for any network topology. The method is used to assess if a network is likely to be connected or not, and demonstrated by analysing the development of a network of desiccation cracks.

The distinct element method (DEM) and the extended finite element method (XFEM) application for analysis of interaction between hydraulic and natural fractures

Hydraulic fracturing can be considered one of the most effective stimulation methods for fractured network formation. The interaction between induced and natural fractures greatly affects the success of the treatment. In this paper, the extended finite element method (XFEM) and distinct element method (DEM) have been combined to identify the propagation of hydraulic fractures in a porous medium with naturally fractured blocks. DEM is used to investigate hydraulic fractures in a natural-fracture network and evaluate the production flow rate under different apertures and lengths of hydraulic fracture. XFEM is used to simulate the deformation of the natural-fracture interface during the approaching phase of induced fractures as a no-remeshing tool. The results of DEM reveal that length of hydraulic fracturing has a significantly greater effect on production than aperture. Results from XFEM show that tensile and shear debonding of natural fractures change as a function of angle and distance from an induced fracture.

Multi-scale modeling of shale laminas and fracture networks in the Yanchang formation, Southern Ordos Basin, China

Outcrops and core observations show that sandy and tuffaceous laminas and natural fractures are well developed in the continental shale gas reservoir. This study reports the distribution of laminas and natural fracture networks at different scales, in cases of outcrops, wells and cores from Yanchang Formation, southern Ordos Basin. Firstly, based on two-dimensional fracture field investigations, a 3-D joint network model of the study area was built using the Monte Carlo simulation method. Then the laminations were identified from macroscopic scales to microscopic scales with multiple probe techniques. Statistical analysis of multi-scale layer thickness suggested that the average thickness of layers at multiple scales showed a fractal feature, and that the layer thickness at each scale followed with an exponential probability distribution, whose exponential coefficient was −3.38, −1.91, −1.65, −1.21, corresponding to meter scale, decimeter scale, centimeter scale and millimeter scale respectively. The fitting curves indicated that the majority of laminas at each scale were relatively thin, and the thicker the layer, the less the number of layers contained in shale. Finally, the lamination models were constructed and superposed over the joint network model to generate 3-D geological structure models at various scales. The models were validated by reproducing fracture and lamina parameters fairly close to those obtained from realistic geological bodies in the study area. The findings of this work could provide a more reliable geological model for the numerical simulation and physical model test of hydraulic fracturing in shale gas reservoir.

Characterizing the Stimulated Reservoir Volume During Hydraulic Fracturing-Connecting the Pressure Fall-Off Phase to the Geomechanics of Fracturing

Microseismic imaging of the hydraulic fracturing operation in the naturally fractured rocks confirms the existence of a stimulated volume (SV) of enhanced permeability. The simulation and characterization of the SV evolution is uniquely challenging given the uncertainty in the nature of the rock mass fabrics as well as the complex fracturing behavior of shear and tensile nature, irreversible plastic deformation and damage. In this paper, the simulation of the SV evolution is achieved using a nonlocal poromechanical plasticity model. Effects of the natural fracture network are incorporated via a nonlocal plasticity characteristic length, ℓ. A nonlocal Drucker–Prager failure model is implemented in the framework of Biot's theory using a new implicit C0 finite element method. First, the behavior of the SV for a two-dimensional (2D) geomechanical injection problem is simulated and the resulting SV is assessed. It is shown that breakdown pressure and stable fracturing pressure are the natural outcomes of the model and both depend upon ℓ. Next, the post-shut-in behavior of the SV is analyzed using the pressure and pressure derivative plots. A bilinear flow regime is observed and it is used to estimate the flow capacity of the SV. The results show that the flow capacity of the SV increases as ℓ decreases (i.e., as the SV behaves more like a single hydraulic fracture); however, for 0.1m≤ℓ≤1m, the calculated flow capacity indicates that the conductivity of the SV is finite. Finally, it is observed that as ℓ tends to zero, the flow capacity of the SV tends to infinity and the SV behaves like a single infinitely conducting fracture.

Integrated Study Aids Characterization and Modeling of Natural-Fracture Networks

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 186043, “An Integrated Study To Characterize and Model Natural-Fracture Networks of Gas-Condensate Carbonate Reservoirs, Onshore Abu Dhabi,” by Budour Ateeq, Mohamed El Gohary, Khalid Al Ammari, and Rashad Masoud, ADCO; Abdelwahab Noufal, ADNOC; Ghislain de Joussineau and Martin Weber, Beicip Franlab; and Dinesh Agrawal, IFP Middle East Consulting, prepared for the 2017 SPE Reservoir Characterization and Simulation Conference and Exhibition, Abu Dhabi, 8–10 May. The paper has not been peer reviewed. Natural fractures can have a significant effect on fluid flow by creating permeability anisotropy in hydrocarbon reservoirs. They can also play an undesirable role in reservoir subsidence and compaction during depletion, with important consequences for production strategy. The investigation of these effects motivated a comprehensive integrated fracture study of three reservoirs from a giant gas-condensate field in Abu Dhabi. The main objective was to build 3D fracture models and compute fracture properties of each reservoir, to be used in dynamic simulations. Introduction The studied reservoirs are gas-condensate-bearing in a carbonate field onshore Abu Dhabi. The field has an anticlinal structure and consists of a series of stacked reservoirs, among which three (Reservoirs A, B, and C) were part of this study. For each reservoir, the production comes mainly from the large gas-bearing area above the gas/oil contact, which is surrounded by a thin peripheric oil rim. The studied field has a long production history; Reservoir A has produced oil and gas for 30 years. Minor fracturing was observed during routine core analyses in the past, but a comprehensive fracture characterization at field scale was never conducted. Because fractures may have a major bearing on production and could play a significant role in rock compaction and collapse during reservoir depletion, an important objective was to ascertain the risk related to the geomechanical stability of these reservoirs because of the presence of natural-fracture networks. Work Flow An integrated work flow was applied in order to characterize fracture distribution and flow effect in the reservoirs properly. The work flow consisted of the following key steps: Fracture characterization from 3D seismic data and subsequent detection of fracture corridors Fracture characterization from core data Fracture characterization from borehole image data Fracture characterization from well dynamic data Conceptual fracture model Building of a 3D fracture model Dynamic calibration of the 3D model using flowmeter and well-test data Upscaling and computation of equivalent fracture properties for the simulation grid using the calibrated model Static Fracture Characterization Fracture characterization using the seismic data initiated the work flow and was followed by the interpretation of fractures from borehole images and core data. Fracture Characterization From 3D Seismic Data. This task was performed to detect the seismic and the subseismic faults and fracture corridors within the three reservoirs. Seismic fracture-facies maps and fracture-index maps were created on the basis of post-stack discontinuity attributes (e.g., curvature, polar dip, and similarity) computed from the inverted seismic cube.