Fractured Reservoir Characterization Research Articles

Numerical modeling of temperature-reporting nanoparticle tracer for fractured geothermal reservoir characterization

Information on the temperature distribution of subsurface reservoirs is essential for geothermal energy development. One of the promising tools to detect the reservoir temperature distribution is temperature-reporting nanoparticle tracers whose functionality has been extensively investigated in both theoretical and experimental ways in the last decade. However, most related studies were limited to simplified geometries and ignored the dynamic interplays of fluid flow, heat transfer, transport and reaction of the temperature-reporting nanoparticle tracer. The response behavior and working mechanisms of such nanotracers in a realistic three-dimensional system still have not been fully revealed through a systematic study. In this work, we develop a numerical modeling approach to simulate field implementation of these nanotracers in a fractured geothermal reservoir. This study aims to evaluate whether the injection of multiple temperature-reporting nanoparticle tracers with different thresholds can be used to estimate the temperature distribution and provide information on the thermal and geological heterogeneities. Several scenarios have been investigated for the geothermal reservoir including homogeneous and non-homogeneous cases (e.g., thermal and geological heterogeneities). Our obtained results from the nanotracer breakthrough curves show that the deviation temperatures in peak concentration values provide an upper limit of the lowest temperature and precise highest temperature for the reservoir temperature range. The deviation temperature of the peak arrival time curve accurately estimates the highest temperature along the main streamlines between the wells. The proposed analysis curves based on the nanotracer breakthrough data were visibly affected by geological heterogeneities including their conductivities and orientations as well as thermal heterogeneities in the geothermal reservoir.

Mechanical characterization of fractured granite reservoirs

In this paper, on the basis of laboratory triaxial mechanical experiments, a granite model including different numbers and angles of fractures was established by the discrete element method. Combined with the laboratory triaxial mechanical experiments and PCF simulation results, the effects of the number and angle of fractures on the rock mechanical properties of fractured granite reservoirs were analyzed. The results show that the existence of fractures significantly reduces the strength of the reservoir, but the increase of the fracture angle and the confining pressure will weaken the degree of this reduction, and the fractures are easy to expand and connect during the loading process.

Pore structure characterization and deliverability prediction of fractured tight glutenite reservoir based on geophysical well logging

Pore structure characterization and deliverability prediction of fractured tight glutenite reservoir based on geophysical well logging

“Detection and characterization of fractures in the Eocene Thebes formation using conventional well logs in October field, Gulf of Suez, Egypt”

Fractures are one of the most prevalent and important geological features in petroleum exploration and production, as they have a substantial impact as conduits for hydrocarbon flow and improve the overall permeability of the formation. Despite their necessity, detecting and characterizing natural fractures still represents a difficult challenge. This study provides a technique for detecting and characterizing naturally fractured reservoirs using conventional well logs in the Eocene Thebes Formation, October Field, Gulf of Suez. Especially as this technique is not applied widely in October Field or even in the Gulf of Suez. Most carbonate reservoirs are complex and heterogeneous; one of the reasons is their naturally fractured characteristics. These fractures can significantly affect reservoir behavior, performance, and production. Despite being the most commonly available data source, logs are rarely employed in a systematic way to have a complete quantitative analysis of naturally fractured reservoirs. Since the presence of fractures affects all well logs in one way or another. This study presents an integrated workflow for determining fracture presence potentiality by combining conventional well logs, thin sections, and other available data in absence of directly advanced logging technologies such as Formation MicroImager (FMI), Dipole Shear Image (DSI), and Borehole Televiewer (BHTV). This integrated workflow was very effective and useful in the evaluation of potential fractures' existence, reservoir characterization, and development. Finally, the results of this integrated workflow suggest a high probability of fracture existence and identification in Thebes Formation, confirming that integration between conventional logging and other available data is very precious, and has a good potential to be used in absence of direct advanced methods for fractured reservoir characterization. For further studies, core data and advanced logs would be beneficial for correlation, since they would provide a more accurate picture of the fracture parameters.

Analytical Fractured Reservoir Characterization by using Geological and Petrophysical Logs

Due to structural complexities in some wells, higher than the expected thickness of the Asmari formation is found. Fracture intensity and deep-rooted fractures broadly increase the risk of unpredictable water production. The well-test analysis is not sufficient in describing fracture properties. Unfortunately, the core condition is poor in the fractured zones and cannot be used to provide reliable information. So, the objectives of this study are developing an accurate structural model for the Asmari reservoir, and fracture characterization in the borehole by interpreting image logs and comparing the log's image results with core data. Dip classification based on a geological log has the value of providing a direct demonstration of structural origin and detecting Asmari fault and fracture systems and their impact on production and answering structural issues. So, in this study, the borehole imaging tools were interpreted to find solutions for fracture systems and fracture attributes. Interpreting accurate structural dip determined the structural problem, thus bringing the precise location of the well within the Asmari reservoir. Fracture properties (open or closed), occurrence, orientation, spacing, and porosity were interpreted using an Image log. The high density of fractures seen on FMS image logs in the study well has been confirmed by inspection of the cores and the distinction between major and minor fracture types from the FMS image logs has been established following core review. As a result, this exercise has been confirmed to be very valuable, not only for indicating the value of the log data, but it has also emphasized some significant limitations of the core data. The amount of information extracted from the FMS image logs goes beyond that achieved from the core. This exercise has validated why image logs are the main source of fracture information in the oil fields of Iran.

Numerical study on the heat transfer behavior in naturally fractured reservoirs and applications for reservoir characterization and geothermal energy development

Naturally fractured reservoir characterization has always been a challenging problem worldwide due to highly heterogeneous. Pressure transient analysis (PTA) is the most used technique for reservoir characterization. However, the pressure inversion inevitably produces non-uniqueness. Additionally, naturally fractured reservoirs are also some of the most promising geothermal systems. A novel concept is to harness heat by producing water from abandoned hydrocarbon reservoirs. However, few literatures have discussed the geothermal development issues in such way by far. To narrow the gap, we present a numerical model to study heat transfer behaviors when fluids are produced from naturally fractured reservoirs. The J-T coefficient, adiabatic expansion, viscous dissipation, conduction, convection and reservoir damage are all considered in proposed model. Two advices for geothermal development are presented according to heat-transfer behavior study. Furthermore, an integrated workflow of combining temperature transient analysis (TTA) and PTA is proposed to determine the reservoir properties for the first time, which help overcome the shortcomings of conventional PTA. Results indicate that: (a) Two parameters proposed in this work (reservoir heat storage ratio and heat inter-porosity coefficient) can evaluate the feasibility of geothermal development, which are characterized by ‘V-shape’ feature on temperature derivative curve. (b) The reservoir temperature will drop when heat transfers to closed boundary, so the geothermal development should choose the reservoir with larger size. (c) TTA can characterize the radius and permeability of reservoir damage zone, which are not readily accessible from PTA. Meanwhile, TTA can distinguish the composite reservoirs and closed reservoirs, which helps address the non-uniqueness problem of PTA. Therefore, TTA can serve as a companion way with PTA to more clearly characterize reservoir with reasonable workflow.

Azimuthal Fourier coefficient inversion for horizontal and vertical fracture characterization in weakly orthorhombic media

Horizontally and vertically aligned fractures (joints) permeated in an isotropic background can give rise to a long-wavelength equivalent orthorhombic medium, which is common for naturally fractured reservoirs. We have developed a feasible approach to characterize the horizontal and vertical fractures using observed azimuthal seismic reflection data. For weak anisotropy, we assume that the horizontal and vertical fractures are decoupled. Using a linear-slip orthorhombic model, we first obtain analytic expressions for the effective elastic stiffness matrix and the corresponding perturbed matrix of an effective orthorhombic anisotropic elastic medium. Combining the scattering function and the perturbed matrix of the orthorhombic medium, we then derive a linearized PP-wave reflection coefficient of effective orthorhombic medium in terms of compressional-wave (P-wave) and shear-wave (S-wave) moduli, density, and horizontal- and vertical-fracture-induced normal and tangential weaknesses. To handle the inverse problem for multiple model parameters in an orthorhombic medium, we reexpress the linearized PP-wave reflection coefficient as a Fourier series. According to the sensitivity analysis of Fourier coefficients (FCs) to isotropic background elastic parameters and four fracture weaknesses, we finally establish a three-step inversion approach to describe the orthorhombic model, which involves (1) estimation of the FCs at different incidence angles from observed azimuthal seismic data and determination of the symmetry axis azimuth, (2) an iterative Bayesian inversion for isotropic background elastic parameters and fracture weaknesses of horizontal fractures from the zeroth-order FC, and (3) an iterative Bayesian inversion for fracture weaknesses of vertical fractures from the second-order FC. The proposed approach is validated by tests on synthetic and field data sets, which demonstrates that the inversion results of P- and S-wave moduli, density, and four fracture weaknesses are robust and reasonable for gas-bearing fractured reservoir characterization with orthorhombic symmetry.

Interference test interpretation in naturally fractured reservoirs

The naturally fractured reservoir characterization is crucial because it can help to predict the flow pattern of fluids, and the storativity ratio of the fractures and to understand whether two or more wells have communication, among others. This paper presents a practical methodology for interpreting interference tests in naturally fractured reservoirs using characteristic points found on the pressure derivative curve. These kinds of tests describe a system that consists of a producing well and an observation well separated by a distance (r). Using characteristic points and features found on the pressure and pressure derivative log-log plot, Analytical expressions were developed from the characteristic points of the pressure and pressure derivative log-log plot to determine the interporosity flow parameter (λ) and the storativity ratio of the fractures (ω). Finally, examples are used to successfully verify the expressions developed so that the naturally-fractured parameters were reproduced with good accuracy.

Foam processes in naturally fractured carbonate oil-wet reservoirs: Technical and economic analysis and optimization

In the recent years, foam process has shown a growing potential in producing naturally fractured reservoirs. While much effort was devoted to fractured reservoir characterization and laboratory design of foaming chemicals, decision-making for field development goes through reservoir simulation. This work assesses foam flooding performance through dual-media reservoir simulations, to optimize injection strategy and foam key features such as stability, mobility reduction, adsorption and interfacial tension (IFT) reduction.Foam flooding may improve significantly oil recovery in fractured oil-wet reservoirs through a better fluid mobility control and an increase in viscous forces in fractures, improving the sweep efficiency. Additionally, foaming chemicals can lead to low to ultra-low interfacial tension between oil and water, and thus enhance oil mobilization. This study evaluates the sensitivity of foam flooding performances to foam properties and injection strategy at pilot-scale.This sensitivity analysis is based on the variance decomposition (Sobol indexes) of the response model (such as oil production), while a surrogate model is built to limit the number of simulations required to evaluate the objective function. Optimizations are performed to constrain the process to be more efficient than gas and/or water injection.The foam process optimum is a trade-off between oil recovery maximization and costs minimization, which corresponds to a rise in viscous forces that force out the oil from the matrix while respecting the fracture pressure and limiting the amount of injected chemicals.This sensitivity assessment brings new insights for pre-feasibility studies, in particular for the foaming formulation design. Specifically, as foam flooding recovery mechanisms interplay, impacts of chemicals adsorption, injection strategy and optimization parameters will strongly differ whether foaming chemicals achieve or not low interfacial tension. The foam process efficiency mainly depends on viscous forces developed in the fracture network whereas the ”low-IFT” effect mainly relies on the penetration of aqueous chemicals in the matrix. The proposed optimization workflow demonstrates its ability to evaluate and to guide the selection of the most appropriate process at pilot scale, according to the reservoir specificities.

Discrete Fracture Network and Fractured Reservoir Characterization in Khabaz Field-Tertiary Formation

Discrete Fracture Network and Fractured Reservoir Characterization in Khabaz Field-Tertiary Formation

Stochastic inverse modeling and global sensitivity analysis to assist interpretation of drilling mud losses in fractured formations

This study is keyed to enhancing our ability to characterize naturally fractured reservoirs through quantification of uncertainties associated with fracture permeability estimation. These uncertainties underpin the accurate design of well drilling completion in heterogeneous fractured systems. We rely on monitored temporal evolution of drilling mud losses to propose a non-invasive and quite inexpensive method to provide estimates of fracture aperture and fracture mud invasion together with the associated uncertainty. Drilling mud is modeled as a yield power law fluid, open fractures being treated as horizontal planes intersecting perpendicularly the wellbore. Quantities such as drilling fluid rheological properties, flow rates, pore and dynamic drilling fluid pressure, or wellbore geometry, are often measured and available for modeling purposes. Due to uncertainty associated with measurement accuracy and the marked space–time variability of the investigated phenomena, we ground our study within a stochastic framework. We discuss (a) advantages and drawbacks of diverse stochastic calibration strategies and (b) the way the posterior probability densities (conditional on data) of model parameters are affected by the choice of the inverse modeling approach employed. We propose to assist stochastic model calibration through results of a moment-based global sensitivity analysis (GSA). The latter enables us to investigate the way parameter uncertainty influences key statistical moments of model outputs and can contribute to alleviate computational costs. Our results suggest that combining moment-based GSA with stochastic model calibration can lead to significant improvements of fractured reservoir characterization and uncertainty quantification.

The successful experience of IGCP636 project “Unifying international research forces to unlock and strengthen geothermal exploitation of the Americas and Europe”

Geothermal fluids are extracted through deep wells drilled in a geological reservoir, which can be represented by highly heterogeneous volcanic complex, sedimentary basins or deep basement rocks. The main objective of this project was to propose suitable methodologies and techniques for the characterization and modeling of fractured geothermal reservoirs, to ensure their sustainable exploitation and, therefore, ensure acceptation of this kind of energy by local communities. This goal was achieved with experiences from the volcanic complex of the Nevado del Ruiz (Colombia), the St. Lawrence Lowlands sedimentary basin (Quebec, Canada), the Carboniferous limestone reservoir in the area of Mons (Belgium), the Soultz-Sous-Forets power plant and the Ploemeur fractured rock hydrogeological experimental site (France), and various areas of interest for geothermal exploration in Chile. The work conducted provided new insights into the construction of conceptual and numerical models for geothermal reservoirs and allowed the creation of a solid research network between Europe and Americas, fostering participation in geosciences of young researchers, students, and women.

Fault-related fracture modeling in the complex tectonic environment of the Malay Basin, offshore Malaysia: An integrated 4D geomechanical approach

In the South-East prong of Eurasia prevails a positive tectonic inversion, where the Malay Basin and its complex oil and gas reservoirs were formed. Therefore, the characterization of the natural fracture network originated from the complex multi-tectonic events of this area remains challenging. This contribution presents a 4D innovative approach for improving the geomechanics-based assessment of fault-related fractures in such exigent environment. The workflow consists of several steps to reduce uncertainties in the fractured reservoir modeling, both in estimating (i) the paleo-geometry of the main structures using 3D reconstruction techniques and (ii), the paleo-tectonic stresses using fracture-based stress inversion technology, both steps being essential to comprehensive geomechanical simulations through geological time. This acute fractured reservoir characterization workflow was therefore applied in a field development plan in the Malay Basin, offshore Malaysia. Well data analysis, refined seismic interpretations, 2D/3D structural restorations and paleo-stress inversions were integrated to manage uncertainties in the discrete fracture simulation. The model reveals evidences of two successive tectonic events: a Paleogene extension with a normal-slip fault regime (σH => N66°) and a Neogene contraction with a strike-slip fault regime (σH => N174°). This tectonic inversion is associated with a redirection of the far field stress, as well asthe location and orientation of the natural fracture network during its growth. The proposed workflow improves the understanding of the fractured reservoir characterization greatly and is of help to appraise future development plans better.

A new DFIT procedure and analysis method: An integrated field and simulation study

Diagnostic Fracture Injection Tests (DFITs) have become commonplace in low-permeability (unconventional) reservoirs to obtain parameters used in hydraulic fracture stimulation design and reservoir characterization. However, the time taken to acquire reliable estimates of these parameters may be excessive. As a result, pump-in/flowback tests, as opposed to the more conventional pump-in/shut-in tests, have been applied in the industry to accelerate the closure process and to estimate closure pressure, which is used in hydraulic fracture design. However, this comes at the expense of losing after-closure data, which is required to estimate reservoir pressure and flow properties. The goal of this paper is to accelerate the closure process during a DFIT, without sacrificing the after-closure data and derived parameters.The proposed DFIT procedure includes flowing back the fracturing fluid, after opening and propagation of the fracture, at a very low and constant rate. The flowback process is continued for a few hours after fracture closure. The well is then shut-in and the pressure falloff is monitored. The main purpose of the ultra-low rate flowback is to remove or reduce the afterflow caused by wellbore storage.The new DFIT procedure is applied to two field examples performed in a low-permeability reservoir in western Canada. The data are analyzed using well-established pressure-transient analysis methods. An estimate of closure pressure was obtained in less than two hours for both field examples, despite the low-permeability of the reservoir (several hundred nanodarcies). For one of the field examples, estimates of reservoir pressure and transmissibility were obtained after just 4 days of shut-in following the flowback process.Finally, a conceptual model is presented to analyze the conventional pump-in/flowback tests for determination of reservoir pressure. The conceptual model is validated against synthetic simulation results. Using this method, reservoir pressure is obtainable with just a few hours of flowback data.

Face-Detection Algorithm Handles Big Data To Help Identify Candidates for Restimulation

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 187328, “From Face Detection to Fractured-Reservoir Characterization: Big Data Analytics for Restimulation-Candidate Selection,” by Egbadon Udegbe, SPE, Eugene Morgan, SPE, and Sanjay Srinivasan, SPE, The Pennsylvania State University, prepared for the 2017 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 9–11 October. The paper has not been peer reviewed. The recent proliferation of subsurface data from instrumented wells has created significant challenges for traditional production-data-analysis methods to extract useful information for reservoir management. This paper demonstrates the viability of a production-data-classification approach adapted from real-time face detection for identifying restimulation candidates. The approach has the potential to be used as a big-data analytic tool for long-duration production-data analysis to serve as a screening tool for selection of restimulation candidates. Introduction Restimulation treatments in producing shale wells have the potential to improve economic performance by increasing the conductivity of existing fractures or enhancing their contact with the formation. The influence of matrix and fracture characteristics on the success of restimulation, however, is not completely understood, which has led to uncertainty in determining favorable candidate wells. Several methods to select restimulation candidates have been proposed. These methods, however, are time-consuming and tend to require detailed input data or exhibit a lack of generality for other reservoir settings. This paper aims to address these challenges with a new methodology for fast and robust analysis of production data from hydraulically fractured wells. A dual-permeability forward-flow modeling approach is used to generate multiple realizations of production-rate profiles by modifying fracture and other parameters. Using this data, pattern-recognition tools are applied to help uncover trends associated with favorable and unfavorable restimulation candidates. This is achieved using a binary classification framework adapted from real-time face detection, which uses simple numerical criteria computed directly from raw flow-rate data, thus eliminating the need for detailed information and promoting computational efficiency. The algorithm also provides probabilistic predictions, which serve as a means to rank candidate wells. While the process of training the classifier has the potential to be computationally intensive, the application of the trained classifier on the observed data is extremely fast, making the method useful for real-time classification of well performance. Face-Detection Overview The Viola-Jones face-detection algorithm is a binary classification scheme that takes labeled examples of images containing faces and nonfaces and develops a set of numerical criteria for distinguishing between both categories. Using these rules, an arbitrary test image can be analyzed and classified as a face or a nonface.

Fractured reservoir characterization using VSP and surface data: a case study from the Paris basin

Anisotropic characteristics are mainly attributed to fractures in fractured reservoirs. The Dogger formation in the Paris basin is a kind of fractured carbonate reservoir, and the nine-component surface seismic and vertical seismic profiling (VSP) data were acquisited in this area. To characterize the fracture attributes, we analyzed the differential variation of each attribute of the vector wavefield, such as velocity ratio, polarizations, amplitudes and differential travel times. The results described using these parameters had a good match with the overall shear wave anisotropy in the Dogger formation. Two VSP data verified our results. There was about four percent anisotropy in the horizontal direction, which could be interpreted as the porosity and permeability changing along the Dogger layer. The differential shear-wave amplitude from the top of the Dogger shows an overall dimming. There were about six intervals in the shear wave section, which showed that shear wave processes and interpretation provided more information than the P-wave section. The interpretation with shear wave anisotropy showed advantages in revealing detailed lateral variations in fractured reservoirs.

Basin structuring and hydro-geophysical characterization of Upper Cretaceous and Eocene fractured deep carbonate reservoirs in the Hajeb Layoun-Jelma-Ouled Asker area (Central Tunisia)

In the Hajeb Layoun-Jelma-Ouled Asker-Oued El Hajal folded pull a part basin, situated in Central Tunisia, the shallow and deep Miocene groundwaters are often over exploited. The sedimentary basins, in this area, contain important carbonate deep reservoirs not yet exploited. Turonian (Bireno-Douleb Formations), Maastrichtian (Abiod Formation), and Ypresian (El Gueria Formation) limestones constitute the most important fractured reservoirs in this region. The present study combine geological, hydrogeological, and geophysical data, using 2D seismic reflection, to determine the spatial distribution and the deep structuring of these carbonate reservoirs. Isochron and isopach maps, generated for the study area, highlight the effect of tectonics in structuring these carbonate reservoir horizons. This effect is well presented along the folded structures and the major fault directions: NE-SW, NW-SE, N-S, and E-W responsible of the reservoir compartmentation. Indeed, subsurface faults as well as thickness and facies variations of these carbonate reservoirs should play a key role in the hydraulic flows and the distribution of principal aquifers. Knowledge and highlights of this structuring represent a subsurface modeling for future deep hydrogeologic exploration with proposed fictitious wells in the study area.

Geomechanical restoration as a tool for fractured reservoir characterization: Application to the Permian Basin, west Texas

We present a three-dimensional (3-D) geomechanical-restoration method as a reservoir characterization tool in the Permian Basin, west Texas. The Oates SW field produces gas from the Lower Devonian Thirtyone Formation within structural traps. The Thirtyone is a brittle chert with characteristics of a fractured reservoir: field development has experienced variable production trends for decades. To assess the impact of deformation on reservoir properties, we employ 3-D geomechanical restorations to model strain patterns associated with fault displacement and fold growth. We correlate these model strains with independent measures of natural rock strain to assess the viability of the restoration results. A semblance volume generated from 3-D seismic reflection data illuminates secondary faults and fracture zones that are not incorporated in the geomechanical restorations. Our analysis yields strong correlations between low semblance and elevated strain throughout the Thirtyone reservoir. These correlations indicate that restoration strains may be used to describe the distribution of secondary faults and fractures that are not represented in our models, providing predictive capabilities for defining fractured reservoir properties. We integrate strain and semblance with production data to evaluate these correlations at the borehole scale in the study area. We describe how tectonic strain likely enhanced permeability, directly impacting observed production trends. Our characterization of the Thirtyone reservoir demonstrates the ability to accurately predict strain distributions with geomechanical restorations where structure has been a significant factor in the development of reservoir permeability. We suggest that these methods show promise as a reservoir characterization tool for conventional and unconventional development operations.

Elastic impedance parameterization and inversion for fluid modulus and dry fracture quasi-weaknesses in a gas-saturated reservoir

A single set of aligned vertical fractures embedded in a purely isotropic background can be considered as an effective long-wavelength transversely isotropic (HTI) medium with a horizontal axis of symmetry. Understanding the separated effect of fluid and fracture properties on seismic characteristics is important for the characterization of a gas-saturated fractured reservoir. Our goal is to demonstrate a direct approach to separate the effects of fluid and fracture properties on PP-wave reflection coefficient, and utilize the azimuthal seismic reflection data to estimate the fluid modulus and dry fracture quasi-weaknesses simultaneously in a gas-saturated fractured reservoir. Starting from Gassmann's poroelasticity theory and linear-slip model, we first derive expressions for the effective elastic stiffness matrix of a gas-saturated fracture-induced porous HTI medium. Using the assumption of small perturbations in rock moduli and small weaknesses, we then derive an expression for linearized PP-wave reflection coefficient for the case of a weak-contrast interface separating two weakly HTI media in terms of fluid modulus and dry (gas-filled) fracture weaknesses based on the perturbation matrix and scattering function, separating the effects of fluid and fracture properties on PP-wave seismic response. With a novel parameterization for dry fracture weaknesses, we propose a method of elastic impedance variation with offset and azimuth (EIVOA) inversion for fluid modulus and dry fracture quasi-weaknesses to reduce the uncertainty of the characterization of fluid and dry fracture properties. Combing Bayesian seismic inversion and regularization constraints, the fluid modulus and dry fracture quasi-weakness parameters are reasonably estimated in the case of synthetic and real seismic data containing a moderate noise in a gas-saturated fractured reservoir.

Seismic structure and texture analyses for fractured reservoir characterization: An integrated workflow

Fractured reservoir prediction is risky and challenging because of the variability in fracture characteristics and the lack of direct observational data in the subsurface. To reduce the risk and challenge, we have developed an integrated workflow to predict fractured reservoirs based on 3D seismic data. The workflow begins with reservoir structure analysis from seismic reflection geometry, which is referred to as seismic structure analysis, to define fracture intensity and fracture orientation using maximum curvature and maximum flexure algorithms. Next, the workflow proceeds with reservoir texture analysis from seismic amplitude signal, which is referred to as seismic texture analysis, to evaluate fracture scale and reservoir facies using waveform regression and calibration algorithms. The results from seismic structure and texture analyses are then used for modeling reservoir properties and fracture networks. Each algorithmic method in the workflow is tested in a siliciclastic tight-sand reservoir in the Teapot Dome oil field (Powder River Basin) and in a carbonate reservoir in the South Pars gas field (Persian Gulf Basin). The test results reveal the previously unknown reservoir heterogeneity and anisotropy that are interpreted to be attributable to the variability in fracture characteristics. It is concluded that the integrated workflow based on seismic structure and texture analyses could potentially contribute to reducing the risk and challenge in characterizing fractured reservoirs in the subsurface.