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Academic literature on the topic 'Naturally fractured reservoirs'

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Published: 4 June 2021
Last updated: 19 February 2022

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Journal articles on the topic "Naturally fractured reservoirs"

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Kuchuk, Fikri, and Denis Biryukov. "Pressure-Transient Tests and Flow Regimes in Fractured Reservoirs." SPE Reservoir Evaluation & Engineering 18, no. 02 (March 31, 2015): 187–204. http://dx.doi.org/10.2118/166296-pa.

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Summary Fractures are common features in many well-known reservoirs. Naturally fractured reservoirs include fractured igneous, metamorphic, and sedimentary rocks (matrix). Faults in many naturally fractured carbonate reservoirs often have high-permeability zones, and are connected to numerous fractures that have varying conductivities. Furthermore, in many naturally fractured reservoirs, faults and fractures can be discrete (rather than connected-network dual-porosity systems). In this paper, we investigate the pressure-transient behavior of continuously and discretely naturally fractured reservoirs with semianalytical solutions. These fractured reservoirs can contain periodically or arbitrarily distributed finite- and/or infinite-conductivity fractures with different lengths and orientations. Unlike the single-derivative shape of the Warren and Root (1963) model, fractured reservoirs exhibit diverse pressure behaviors as well as more than 10 flow regimes. There are seven important factors that dominate the pressure-transient test as well as flow-regime behaviors of fractured reservoirs: (1) fractures intersect the wellbore parallel to its axis, with a dipping angle of 90° (vertical fractures), including hydraulic fractures; (2) fractures intersect the wellbore with dipping angles from 0° to less than 90°; (3) fractures are in the vicinity of the wellbore; (4) fractures have extremely high or low fracture and fault conductivities; (5) fractures have various sizes and distributions; (6) fractures have high and low matrix block permeabilities; and (7) fractures are damaged (skin zone) as a result of drilling and completion operations and fluids. All flow regimes associated with these factors are shown for a number of continuously and discretely fractured reservoirs with different well and fracture configurations. For a few cases, these flow regimes were compared with those from the field data. We performed history matching of the pressure-transient data generated from our discretely and continuously fractured reservoir models with the Warren and Root (1963) dual-porosity-type models, and it is shown that they yield incorrect reservoir parameters.
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Kuchuk, Fikri, and Denis Biryukov. "Pressure-Transient Behavior of Continuously and Discretely Fractured Reservoirs." SPE Reservoir Evaluation & Engineering 17, no. 01 (January 30, 2014): 82–97. http://dx.doi.org/10.2118/158096-pa.

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Summary Fractures are common features of many well-known reservoirs. Naturally fractured reservoirs contain fractures in igneous, metamorphic, and sedimentary formations. Faults in many naturally fractured carbonate reservoirs often have high-permeability zones, and are connected to many fractures with varying conductivities. Furthermore, in many naturally fractured reservoirs, faults and fractures can be discrete (i.e., not a connected-network fracture system). New semianalytical solutions are used to understand the pressure behavior of naturally fractured reservoirs containing a network of discrete and/or connected (continuous) finite- and infinite-conductivity fractures. We present an extensive literature review of the pressure-transient behavior of fractured reservoirs. First, we show that the Warren and Root (1963) dual-porosity model is a fictitious homogeneous porous medium because it does not contain any fractures. Second, by use of the new solutions, we show that for most naturally fractured reservoirs, the Warren and Root (1963) dual-porosity model is inappropriate and fundamentally incomplete for the interpretation of pressure-transient well tests because it does not capture the behavior of these reservoirs. We examined many field well tests published in the literature. With few exceptions, none of them shows the behavior of the Warren and Root (1963) dual-porosity model. These examples exhibit very diverse pressure behaviors of discretely and continuously fractured reservoirs. Unlike the single derivative shape of the Warren and Root (1963) model, the derivatives of these examples exhibit many different flow regimes depending on fracture distribution and on their intensity and conductivity. We show these flow regimes with our new model for discretely and continuously fractured reservoirs. Most well tests published in the literature do not exhibit the Warren and Root (1963) dual-porosity reservoir-model behavior. If we interpret them by use of this dual-porosity model, then the estimated permeability, skin factor, interporosity flow coefficient (λ), and storativity ratio (ω) will not represent the actual reservoir parameters.
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Evans, R. D., and S. D. L. Lekia. "A Reservoir Simulation Study of Naturally Fractured Lenticular Tight Gas Sand Reservoirs." Journal of Energy Resources Technology 112, no. 4 (December 1, 1990): 231–38. http://dx.doi.org/10.1115/1.2905763.

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The results of parametric studies of two naturally fractured lenticular tight gas reservoirs, Fluvial E-1 and Puludal Zones 3 and 4, of the U.S. Department of Energy Multi-Well Experiment (MWX) site of Northwestern Colorado are presented and discussed. The three-dimensional, two-phase, black oil reservoir simulator that was developed in a previous phase of this research program is also discussed and the capabilities further explored by applying it to several example problems. The simulation studies lead to the conclusion that 1) at early times the reservoir performance does not depend on lenticularity; 2) the initial reservoir performance does not depend on natural fracture concentration, although at later times the performance predictions of systems with lower natural fracture concentrations begin to fall below the ones with higher concentrations; 3) porosity change with time and pressure leads to double performance prediction reversals when comparing gas flow rates and cumulative gas production from naturally fractured and non-naturally fractured tight gas reservoirs; 4) the assumption of zero capillary pressure in the fractures can lead to erroneous predictions in the simulation of naturally fractured tight gas reservoir performance; and 5) the simulator developed in a prior phase of this project is capable of handling a reservoir block that is blanket sand, lenticular, completely fractured, partially fractured or completely unfractured and is amenable to an anisotropic heterogeneous reservoir whether the reservoir is fractured or not.
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Ali, Mahmoud T., Ahmed A. Ezzat, and Hisham A. Nasr-El-Din. "A Model To Simulate Matrix-Acid Stimulation for Wells in Dolomite Reservoirs with Vugs and Natural Fractures." SPE Journal 25, no. 02 (October 23, 2019): 609–31. http://dx.doi.org/10.2118/199341-pa.

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Summary Designing matrix-acid stimulation treatments in vuggy and naturally fractured carbonate reservoirs is a challenging problem in the petroleum industry. It is often difficult to physically model this process, and current mathematical models do not consider vugs or fractures. There is a significant gap in the literature for models that design and evaluate matrix-acid stimulation in vuggy and naturally fractured carbonate reservoirs. The objective of this work is to develop a new model to simulate matrix acidizing under field conditions in vuggy and naturally fractured carbonates. To obtain accurate and reliable simulation parameters, acidizing coreflood experiments were modeled using a reactive-flow simulator. A 3D radial field-scale model was used to study the flow of acid in the presence of vugs (pore spaces that are significantly larger than grains) and natural fractures (breaks in the reservoir that were formed naturally by tectonic events). The vugs’ size and distribution effects on acid propagation were studied under field conditions. The fracture length, conductivity, and orientation, and the number of fractures in the formation, were studied by the radial model. The results of the numerical simulation were used to construct Gaussian-process (GP)-based surrogate models for predicting acid propagation in vuggy and naturally fractured carbonates. Finally, the acid propagation in vuggy/naturally fractured carbonates was evaluated, as well.The simulation results of vuggy carbonates show that the presence of vugs in carbonates results in faster and deeper acid propagation in the formation when compared with homogeneous reservoirs at injection velocities lower than 8×10–4 m/s. Results also revealed that the size and density of the vugs have a significant impact on acid consumption and the overall performance of the acid treatment. The output of the fracture model illustrates that under field conditions, fracture orientations do not affect the acid-propagation velocity. The acid does not touch all of the fractures around the well. The GP model predictions have an accuracy of approximately 90% for both vuggy and naturally fractured cases. The vuggy/naturally fractured model simulations reveal that fractures are the main reason behind the fast acid propagation in these highly heterogeneous reservoirs.
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Xu, Lin Jing, Shi Cheng Zhang, and Jian Ye Mou. "Acid Leakoff Mechanism in Acid Fracturing of Naturally Fractured Carbonate Gas Reservoirs." Advanced Materials Research 868 (December 2013): 682–85. http://dx.doi.org/10.4028/www.scientific.net/amr.868.682.

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In acid fracturing, excessive acid leakoff is thought to be the main reason that limits fracture propagation and live acid penetration distance, so its very important to do research about acid leak-off on naturally fractured carbonates. we developed a new model in this paper to simulate acid leakoff into a naturally fractured carbonates gas reservoir during acid fracturing. Our model incorporates the acid-rock reaction on the fractured surfaces. Given the information of the Puguang gas reservoir, the model predicts acid filtration and leakoff rate over time. In this study, we found that acid leak-off mechanism in naturally fractured carbonates is much different from that in reservoirs without natural fractures. The leakoff volume is several times of nonreactive acid. Since the acid widened natural fractures, leakoff velocity increase with time firstly , then decrease. While the leakoff velocity of the nonreactive fluid decrease sustained. We also analyze other sensitivity parameters of the acid leakoff. In this model, we explain the acid leakoff mechanism in naturally fractured carbonates, and provide a more accurate calculating of fluid loss.
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Rezk, Mohamed Gamal, and A. A. Abdelwaly. "Estimation of characteristics of naturally fractured reservoirs by pressure transient analysis." World Journal of Engineering 14, no. 5 (October 2, 2017): 368–80. http://dx.doi.org/10.1108/wje-10-2016-0110.

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Purpose This paper aims to analyze the pressure behavior in dual porosity reservoirs using different techniques in an attempt to correctly characterize reservoir properties. Pressure transient tests in naturally fractured reservoirs often exhibit non-uniform responses. Design/methodology/approach The pressure transient tests in naturally fractured reservoirs were analyzed using conventional semi-log analysis, type curve matching (using commercial software) and Tiab’s direct synthesis (TDS) technique. In addition, the TDS method was applied in case of a naturally fractured formation with a vertical hydraulic fracture. These techniques were applied to a single-layer, naturally fractured reservoir under pseudosteady state matrix flow. By studying the unique characteristics of the different flow regimes appear on the pressure and pressure derivative curves, various reservoir characteristics can be obtained such as permeability, skin factor and fracture properties. Findings For naturally fractured reservoirs, a comparison between the results semi-log analysis, software matching and TDS method is presented. In case of wellbore storage, early time flow regime can be obscured that lead to incomplete semi-log analysis. Furthermore, the type curve matching usually gives a non-uniqueness solution, as it needs all the flow regimes to be observed. However, the direct synthesis method used analytical equation to calculate reservoir and well parameters without type curve matching. For naturally fractured reservoirs with a vertical fracture, the pressure behavior of wells crossed by a uniform flux and infinite conductivity fracture is analyzed using TDS technique. The different flow regimes on the pressure derivative curve were used to calculate the fracture half-length in addition to other reservoir properties. Originality/value The results of different field cases showed that TDS technique offers several advantages compared to semi-log analysis and type curve matching. It can be used even if some flow regimes are not observed. Direct synthesis results are accurate compared to the available core data and the software matching results. It can be used to confirm the software matching results and to give reliable reservoir characteristics when there is lack of data.
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Moinfar, Ali, Abdoljalil Varavei, Kamy Sepehrnoori, and Russell T. Johns. "Development of an Efficient Embedded Discrete Fracture Model for 3D Compositional Reservoir Simulation in Fractured Reservoirs." SPE Journal 19, no. 02 (July 24, 2013): 289–303. http://dx.doi.org/10.2118/154246-pa.

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Summary Many naturally fractured reservoirs around the world have depleted significantly, and improved-oil-recovery (IOR) processes are necessary for further development. Hence, the modeling of fractured reservoirs has received increased attention recently. Accurate modeling and simulation of naturally fractured reservoirs (NFRs) is still challenging because of permeability anisotropies and contrasts. Nonphysical abstractions inherent in conventional dual-porosity and dual-permeability models make them inadequate for solving different fluid-flow problems in fractured reservoirs. Also, recent technologies for discrete fracture modeling may suffer from large simulation run times, and the industry has not used such approaches widely, even though they give more-accurate representations of fractured reservoirs than dual-continuum models. We developed an embedded discrete fracture model (DFM) for an in-house compositional reservoir simulator that borrows the dual-medium concept from conventional dual-continuum models and also incorporates the effect of each fracture explicitly. The model is compatible with existing finite-difference reservoir simulators. In contrast to dual-continuum models, fractures have arbitrary orientations and can be oblique or vertical, honoring the complexity of a typical NFR. The accuracy of the embedded DFM is confirmed by comparing the results with the fine-grid, explicit-fracture simulations for a case study including orthogonal fractures and a case with a nonaligned fracture. We also perform a grid-sensitivity study to show the convergence of the method as the grid is refined. Our simulations indicate that to achieve accurate results, the embedded discrete fracture model may only require moderate mesh refinement around the fractures and hence offers a computationally efficient approach. Furthermore, examples of waterflooding, gas injection, and primary depletion are presented to demonstrate the performance and applicability of the developed method for simulating fluid flow in NFRs.
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Al-Rubaie, Ali, and Hisham Khaled Ben Mahmud. "A numerical investigation on the performance of hydraulic fracturing in naturally fractured gas reservoirs based on stimulated rock volume." Journal of Petroleum Exploration and Production Technology 10, no. 8 (August 17, 2020): 3333–45. http://dx.doi.org/10.1007/s13202-020-00980-8.

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Abstract All reservoirs are fractured to some degree. Depending on the density, dimension, orientation and the cementation of natural fractures and the location where the hydraulic fracturing is done, preexisting natural fractures can impact hydraulic fracture propagation and the associated flow capacity. Understanding the interactions between hydraulic fracture and natural fractures is crucial in estimating fracture complexity, stimulated reservoir volume, drained reservoir volume and completion efficiency. However, because of the presence of natural fractures with diffuse penetration and different orientations, the operation is complicated in naturally fractured gas reservoirs. For this purpose, two numerical methods are proposed for simulating the hydraulic fracture in a naturally fractured gas reservoir. However, what hydraulic fracture looks like in the subsurface, especially in unconventional reservoirs, remain elusive, and many times, field observations contradict our common beliefs. In this study, the hydraulic fracture model is considered in terms of the state of tensions, on the interaction between the hydraulic fracture and the natural fracture (45°), and the effect of length and height of hydraulic fracture developed and how to distribute induced stress around the well. In order to determine the direction in which the hydraulic fracture is formed strikethrough, the finite difference method and the individual element for numerical solution are used and simulated. The results indicate that the optimum hydraulic fracture time was when the hydraulic fracture is able to connect natural fractures with large streams and connected to the well, and there is a fundamental difference between the tensile and shear opening. The analysis indicates that the growing hydraulic fracture, the tensile and shear stresses applied to the natural fracture.
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Costa, Luís Augusto Nagasaki, Célio Maschio, and Denis José Schiozer. "A new methodology to reduce uncertainty of global attributes in naturally fractured reservoirs." Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles 73 (2018): 41. http://dx.doi.org/10.2516/ogst/2018038.

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Accurately characterizing fractures is complex. Several studies have proposed reducing uncertainty by incorporating fracture characterization into simulations, using a probabilistic approach, to maintain the geological consistency, of a range of models instead of a single matched model. We propose a new methodology, based on one of the steps of a general history-matching workflow, to reduce uncertainty of reservoir attributes in naturally fractured reservoirs. This methodology maintains geological consistency and can treat many reservoir attributes. To guarantee geological consistency, the geostatistical attributes (e.g., fracture aperture, length, and orientation) are used as parameters in the history matching. This allows us to control Discrete Fracture Network attributes, and systematically modify fractures. The iterative sensitivity analysis allows the inclusion of many (30 or more) uncertain attributes that might occur in a practical case. At each uncertainty reduction step, we use a sensitivity analysis to identify the most influential attributes to treat in each step. Working from the general history-matching workflow of Avansi et al. (2016), we adapted steps for use with our methodology, integrating the history matching with geostatistical modeling of fractures and other properties in a big loop approach. We applied our methodology to a synthetic case study of a naturally fractured reservoir, based on a real semi-synthetic carbonate field, offshore Brazil, to demonstrate the applicability in practical and complex cases. From the initial 18 uncertain attributes, we worked with only 5 and reduced the overall variability of the Objective Functions. Although the focus is on naturally fractured reservoirs, the proposed methodology can be applied to any type of reservoir.
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Naimi-Tajdar, Reza, Choongyong Han, Kamy Sepehrnoori, Todd James Arbogast, and Mark A. Miller. "A Fully Implicit, Compositional, Parallel Simulator for IOR Processes in Fractured Reservoirs." SPE Journal 12, no. 03 (September 1, 2007): 367–81. http://dx.doi.org/10.2118/100079-pa.

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Summary Naturally fractured reservoirs contain a significant amount of the world oil reserves. A number of these reservoirs contain several billion barrels of oil. Accurate and efficient reservoir simulation of naturally fractured reservoirs is one of the most important, challenging, and computationally intensive problems in reservoir engineering. Parallel reservoir simulators developed for naturally fractured reservoirs can effectively address the computational problem. A new accurate parallel simulator for large-scale naturally fractured reservoirs, capable of modeling fluid flow in both rock matrix and fractures, has been developed. The simulator is a parallel, 3D, fully implicit, equation-of-state compositional model that solves very large, sparse linear systems arising from discretization of the governing partial differential equations. A generalized dual-porosity model, the multiple-interacting-continua (MINC), has been implemented in this simulator. The matrix blocks are discretized into subgrids in both horizontal and vertical directions to offer a more accurate transient flow description in matrix blocks. We believe this implementation has led to a unique and powerful reservoir simulator that can be used by small and large oil producers to help them in the design and prediction of complex gas and waterflooding processes on their desktops or a cluster of computers. Some features of this simulator, such as modeling both gas and water processes and the ability of 2D matrix subgridding are not available in any commercial simulator to the best of our knowledge. The code was developed on a cluster of processors, which has proven to be a very efficient and convenient resource for developing parallel programs. The results were successfully verified against analytical solutions and commercial simulators (ECLIPSE and GEM). Excellent results were achieved for a variety of reservoir case studies. Applications of this model for several IOR processes (including gas and water injection) are demonstrated. Results from using the simulator on a cluster of processors are also presented. Excellent speedup ratios were obtained. Introduction The dual-porosity model is one of the most widely used conceptual models for simulating naturally fractured reservoirs. In the dual-porosity model, two types of porosity are present in a rock volume: fracture and matrix. Matrix blocks are surrounded by fractures and the system is visualized as a set of stacked volumes, representing matrix blocks separated by fractures (Fig. 1). There is no communication between matrix blocks in this model, and the fracture network is continuous. Matrix blocks do communicate with the fractures that surround them. A mass balance for each of the media yields two continuity equations that are connected by matrix-fracture transfer functions which characterize fluid flow between matrix blocks and fractures. The performance of dual-porosity simulators is largely determined by the accuracy of this transfer function. The dual-porosity continuum approach was first proposed by Barenblatt et al. (1960) for a single-phase system. Later, Warren and Root (1963) used this approach to develop a pressure-transient analysis method for naturally fractured reservoirs. Kazemi et al. (1976) extended the Warren and Root method to multiphase flow using a 2D, two-phase, black-oil formulation. The two equations were then linked by means of a matrix-fracture transfer function. Since the publication of Kazemi et al. (1976), the dual-porosity approach has been widely used in the industry to develop field-scale reservoir simulation models for naturally fractured reservoir performance (Thomas et al. 1983; Gilman and Kazemi 1983; Dean and Lo 1988; Beckner et al. 1988; Rossen and Shen 1989). In simulating a fractured reservoir, we are faced with the fact that matrix blocks may contain well over 90% of the total oil reserve. The primary problem of oil recovery from a fractured reservoir is essentially that of extracting oil from these matrix blocks. Therefore it is crucial to understand the mechanisms that take place in matrix blocks and to simulate these processes within their container as accurately as possible. Discretizing the matrix blocks into subgrids or subdomains is a very good solution to accurately take into account transient and spatially nonlinear flow behavior in the matrix blocks. The resulting finite-difference equations are solved along with the fracture equations to calculate matrix-fracture transfer flow. The way that matrix blocks are discretized varies in the proposed models, but the objective is to accurately model pressure and saturation gradients in the matrix blocks (Saidi 1975; Gilman and Kazemi 1983; Gilman 1986; Pruess and Narasimhan 1985; Wu and Pruess 1988; Chen et al. 1987; Douglas et al. 1989; Beckner et al. 1991; Aldejain 1999).
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Dissertations / Theses on the topic "Naturally fractured reservoirs"

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LIMA, BIANCA FERNANDES. "NATURALLY FRACTURED RESERVOIRS SIMULATION." PONTIFÍCIA UNIVERSIDADE CATÓLICA DO RIO DE JANEIRO, 2013. http://www.maxwell.vrac.puc-rio.br/Busca_etds.php?strSecao=resultado&nrSeq=34826@1.

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PONTIFÍCIA UNIVERSIDADE CATÓLICA DO RIO DE JANEIRO
CONSELHO NACIONAL DE DESENVOLVIMENTO CIENTÍFICO E TECNOLÓGICO
A presença de fraturas naturais em reservatórios de petróleo pode gerar grandes impactos no deslocamento de fluidos em seu interior. Os maiores problemas estão na irregularidade da área varrida pelo fluido injetado, por exemplo, a água, e a antecipação dos breakthroughs, ou seja, a chegada precoce da água aos poços produtores. De modo a analisar o efeito promovido pela presença de fraturas no meio, foram simulados os dois modelos de simulação de fluxo em reservatórios fraturados: o modelo de dupla-porosidade (DP) e o modelo de dupla-porosidade e dupla-permeabilidade (DPDK), bem como outros dois modelos derivados do modelo DP, o modelo de Subdomínios (SD) e o modelo MINC (Multiple Interacting Continua). Também foram realizadas análises paramétricas para compreender o impacto de propriedades, como as permeabilidades tanto da matriz quanto da fratura e o espaçamento das fraturas, no comportamento do fluxo em reservatórios fraturados. A presença de corredores de fraturas (fracture swarms) foi, igualmente, avaliada, assim como seu efeito associado à presença de camadas de altíssima permeabilidade (super-K). Por fim, foi simulado um modelo mais complexo, denominado GTEP, o qual foi construído a partir de uma seção aplicada à simulação de um reservatório carbonático gigante do Oriente Médio, com o intuito de exemplificar a irregularidade da área varrida em reservatórios naturalmente fraturados.
The presence of natural fractures in oil reservoirs can generate major impacts on the fluid displacement inside them. The greatest problems are irregularity in the area swept by the injected fluid, e.g. water, and breakthroughs anticipation, or early arrival of water to the producing wells. In order to analyze the effect of the presence of fractures in the medium, two flow models of fractured reservoirs were constructed: the dual-porosity model (DP) and the dual-porosity and dual permeability model (DPDK), as well as two other models derived from the DP model, Subdomains model (SD) and MINC model (Multiple Interacting Continua). Parametric analyzes were also conducted to comprehend the impact of properties, such as the matrix permeability, the fracture permeability and the fracture spacing, on the flow behavior in fractured reservoirs. The presence of fracture corridors (fracture swarms) was also evaluated in three models, as well as its effect associated with the presence of layers of high permeability, denoted super-K. Finally, a more complex model, called GTEP Field, was simulated, which was constructed from a section applied to the simulation of a giant carbonate reservoir in the Middle East, in order to illustrate the irregularity of the swept area in natural fractured reservoirs.
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Tran, Nam Hong Petroleum Engineering Faculty of Engineering UNSW. "Characterisation and modelling of naturally fractured reservoirs." Awarded by:University of New South Wales. Petroleum Engineering, 2004. http://handle.unsw.edu.au/1959.4/20559.

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Naturally fractured reservoirs are generally extremely complex. The aim of characterisation and modelling of such reservoirs is to construct numerical models of rock and fractures, preparing input data for reliable stimulation and fluid flow simulation analyses. This requires the knowledge of different fracture heterogeneities and their correlations at well locations and inter-well regions. This study addresses the issues of how to integrate different information from various field data sources and construct comprehensive discrete fracture networks for naturally fractured reservoir. The methodology combines several mathematical and artificial intelligent techniques, which include statistics, geostatistics, fuzzy neural network, stochastic simulation and simulated annealing global optimisation. The study has contributed to knowledge in characterisation and modelling of naturally fractured reservoirs in several ways. It has developed: .An effective and data-dependant fracture characterisation procedure. It examines all the conventional reservoir data sources and their roles towards characterisation of different fracture properties. The procedure has the advantage of being both comprehensive and flexible. It is able to integrate all multi-scaled and diverse fracture information from the different data sources. .An improved hybrid stochastic generation algorithm for modelling discrete fracture networks. The stochastic simulation is able to utilise both discrete and continuum fracture information. It could simulate not only complicated distributions for fracture properties (e.g. multimodal circular statistics and non-parametric distributions) but also their correlations. In addition, with the incorporation of artificial fuzzy neural simulation, discrete multifractal geometry of fracture size and fracture density distribution map could be evaluated and modelled. Compared to most of the previous fracture modelling approach, this model is more flexible and comprehensive. .An improved conditional global optimisation model for modelling discrete fracture networks. The hybrid model takes full advantages of the advanced fracture characterisation using geostatistical and fuzzy neural analyses. Discrete fractures are treated individually and yet continuum information could be modelled. Compared to the stochastic simulation approach, this model produces more representative fracture networks. Compared to the conventional optimisation programs, this model is more versatile and contains superior objective function.
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Sobbi, Farhad Aschar. "Well testing of naturally fractured reservoirs." Thesis, Heriot-Watt University, 1988. http://hdl.handle.net/10399/1481.

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CAMIZA, DANILLO DURAN. "SECONDARY RECOVERY IN NATURALLY FRACTURED RESERVOIRS." PONTIFÍCIA UNIVERSIDADE CATÓLICA DO RIO DE JANEIRO, 2015. http://www.maxwell.vrac.puc-rio.br/Busca_etds.php?strSecao=resultado&nrSeq=26967@1.

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Todos os reservatórios de petróleo apresentam algum grau de fraturamento. Muitas vezes, a presença de fraturas afeta de forma significativa o fluxo dos fluidos nele contidos, seja por incrementarem a permeabilidade do meio, criando caminhos preferenciais de escoamento, seja por imporem algum tipo de barreira ao fluxo. Quando submetidos à injeção de água, reservatórios naturalmente fraturados podem apresentar graves problemas de produção prematura de água e baixíssimas eficiências de varrido. Os estudos realizados neste trabalho procuraram contribuir para o melhor entendimento dos processos de recuperação envolvidos na produção de reservatórios fraturados, bem como o impacto de cada um dos principais parâmetros que condicionam o fluxo no meio poroso fraturado. Foi realizada, ainda, uma análise de possíveis estratégias de drenagem para esse tipo de reservatório. Por fim, foram realizadas simulações para estudar possíveis ganhos da injeção de emulsão de óleo em água, como método de recuperação, em comparação com a injeção de água.
All oil reservoirs have some degree of fracturing. Often, the presence of fractures affects significantly the flow of the fluids contained in the reservoir, increasing the permeability and creating preferential flow paths or by imposing some barrier to the flow. When subjected to waterflooding, naturally fractured reservoirs may have serious problems like early production of water or very low swept efficiencies. The analyses conducted in this study contemplated the understanding of recovery processes involved in the production of fractured reservoirs and the impact of each of the main parameters that influence the flow in fractured porous media. Also, an analysis of possible draining strategies for this type of reservoir was performed. Finally, simulations were performed to study the possible gains of emulsion injection, as a recovery method, compared with water injection.
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Al, Harbi Mishal H. "Streamline-based production data integration in naturally fractured reservoirs." Texas A&M University, 2003. http://hdl.handle.net/1969.1/2445.

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Streamline-based models have shown great potential in reconciling high resolution geologic models to production data. In this work we extend the streamline-based production data integration technique to naturally fractured reservoirs. We use a dualporosity streamline model for fracture flow simulation by treating the fracture and matrix as separate continua that are connected through a transfer function. Next, we analytically compute the sensitivities that define the relationship between the reservoir properties and the production response in fractured reservoirs. Finally, production data integration is carried out via the Generalized Travel Time inversion (GTT). We also apply the streamline-derived sensitivities in conjunction with a dual porosity finite difference simulator to combine the efficiency of the streamline approach with the versatility of the finite difference approach. This significantly broadens the applicability of the streamlinebased approach in terms of incorporating compressibility effects and complex physics. The number of reservoir parameters to be estimated is commonly orders of magnitude larger than the observation data, leading to non-uniqueness and uncertainty in reservoir parameter estimate. Such uncertainty is passed to reservoir response forecast which needs to be quantified in economic and operational risk analysis. In this work we sample parameter uncertainty using a new two-stage Markov Chain Monte Carlo (MCMC) that is very fast and overcomes much of its current limitations. The computational efficiency comes through a substantial increase in the acceptance rate during MCMC by using a fast linearized approximation to the flow simulation and the likelihood function, the critical link between the reservoir model and production data. The Gradual Deformation Method (GDM) provides a useful framework to preserve geologic structure. Current dynamic data integration methods using GDM are inefficient due to the use of numerical sensitivity calculations which limits the method to deforming two or three models at a time. In this work, we derived streamline-based analytical sensitivities for the GDM that can be obtained from a single simulation run for any number of basis models. The new Generalized Travel Time GDM (GTT-GDM) is highly efficient and achieved a performance close to regular GTT inversion while preserving the geologic structure.
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Huapaya, Lopez Christian A. "The imbibition process of waterflooding in naturally fractured reservoirs." Texas A&M University, 2003. http://hdl.handle.net/1969.1/1632.

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This thesis presents procedures to properly simulate naturally fractured reservoirs using dual-porosity models. The main objectives of this work are to: (1) determine if the spontaneous imbibition can be simulated using a two phase CMG simulator and validate it with laboratory experiments in the literature; (2) study the effect of countercurrent imbibition in field scale applications; and (3) develop procedures for using the dual-porosity to simulate fluid displacement in a naturally fractured reservoir. Reservoir simulation techniques, analytical solutions and numerical simulation for a two phase single and dual-porosity are used to achieve our objectives. Analysis of a single matrix block with an injector and a producer well connected by a single fracture is analyzed and compared with both two phase single and dual-porosity models. Procedures for obtaining reliable results when modeling a naturally fractured reservoir with a two phase dual-porosity model are presented and analyzed.
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Tellapaneni, Prasanna Kumar. "Simulation of naturally fractured reservoirs using empirical transfer function." Thesis, Texas A&M University, 2003. http://hdl.handle.net/1969.1/248.

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This research utilizes the imbibition experiments and X-ray tomography results for modeling fluid flow in naturally fractured reservoirs. Conventional dual porosity simulation requires large number of runs to quantify transfer function parameters for history matching purposes. In this study empirical transfer functions (ETF) are derived from imbibition experiments and this allows reduction in the uncertainness in modeling of transfer of fluids from the matrix to the fracture. The application of the ETF approach is applied in two phases. In the first phase, imbibition experiments are numerically solved using the diffusivity equation with different boundary conditions. Usually only the oil recovery in imbibition experiments is matched. But with the advent of X-ray CT, the spatial variation of the saturation can also be computed. The matching of this variation can lead to accurate reservoir characterization. In the second phase, the imbibition derived empirical transfer functions are used in developing a dual porosity reservoir simulator. The results from this study are compared with published results. The study reveals the impact of uncertainty in the transfer function parameters on the flow performance and reduces the computations to obtain transfer function required for dual porosity simulation.
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Rojas, Paico Danny Hubert. "A new procedure for history matching naturally fractured reservoirs /." May be available electronically:, 2008. http://proquest.umi.com/login?COPT=REJTPTU1MTUmSU5UPTAmVkVSPTI=&clientId=12498.

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Shaik, Abdul Ravoof Petroleum Engineering Faculty of Engineering UNSW. "Simulation of stress dependent fluid flow in naturally fractured reservoirs." Publisher:University of New South Wales. Petroleum Engineering, 2008. http://handle.unsw.edu.au/1959.4/43266.

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Naturally fractured reservoirs represent significant portion of the world's oil and gas reserves. In most of the reservoirs, fractures are important contributors to fluid flow. Thus, modeling and simulation of discrete fracture network is essential to assess responses of the reservoirs under stimulation pressure, develop the best hydraulic fracture treatments, carry out feasibility studies, design optimum production methods and improve reservoir potentials. It is also a very complicated process. Natural fractures are by nature highly heterogeneous with different size, orientation and spatial distribution. The complexity is further raised, taking into account the role of matrix, the flow interaction between matrix and fractures, the effect of production-induced stress on fluid flow. Previous works fail to balance sufficient geological complexity and excessive needs of high computational resources. This thesis presents an innovative procedure to simulate stress-dependent fluid flow through discrete fracture network. Three numerical models (tensor, flow and deformation) are developed and coupled iteratively for this purpose. - A tensor model calculates grid based permeability tensor from discrete fracture network model, which includes individual fracture properties such as spatial distribution, length, location and orientation. The tensor model accounts for fluid flow from the matrix to matrix and matrix to fracture. It also includes flow through connected and disconnected fractures. - An unsteady state simulation model investigates fluid flow through the fracture system and gives pressure profile, velocity profile as output. - A dual continuum deformation model studies the reservoir rock deformation and its effects on fluid flow. The geo-mechanic solution is decomposed into matrix and fracture parts that allow calculation of dynamic porosity and permeability separately. The proposed work procedure has been validated to match nicely with analytical results. Furthermore, several case study scenarios are carried out to illustrate how it could help evaluate different aspects of reservoir performance including fracture connectivity, rock deformation, well injectivity and productivity, recovery and even distribution of fluid inside reservoir as a result of rock deformation. The case studies have proven the method to be very efficient in terms computational resources. It also eliminates most of the limitations in the previous models such as handling fracture connectivity, permeability anisotropy and change in effective stress.
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Ahmed, Elfeel Mohamed. "Improved upscaling and reservoir simulation of enhanced oil recovery processes in naturally fractured reservoirs." Thesis, Heriot-Watt University, 2014. http://hdl.handle.net/10399/2755.

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Naturally fractured reservoirs (NFR) contain a significant amount of remaining petroleum reserves and are now considered for Enhanced Oil Recovery (EOR) schemes that involve three-phase flow such as water-alternating-gas (WAG) injection. Accurate numerical simulation of flow in NFR is essential for sound reservoir management decisions to maximise oil recovery and minimise the cost of field development. In this thesis, two important issues related to flow simulation in NFR are investigated. First, a step-wise upscaling approach is developed to evaluate the accuracy of dual porosity models in estimating matrix-fracture transfer duringWAG injection. It was found that the classical dual porosity models generally overestimate recovery from matrix blocks. Hence, a double block model was developed and extended to a multi-rate dual porosity (MRDP). The multi-rate double block model showed significant improvements in matching detailed fine grid simulations of three-phase matrix-fracture transfer. Second, the accuracy of upscaling discrete fracture networks (DFN) is assessed and its impact on history matching was investigated on a real fractured reservoir. A new method to upscale the shape factors needed for MRDP models from DFN is presented. This method is a notable step towards more accurate but still efficient reservoir simulation in NFR.
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Books on the topic "Naturally fractured reservoirs"

1

Naturally fractured reservoirs. 2nd ed. Tulsa, Okla: PennWell Books, 1995.

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Narr, Wayne. Naturally fractured reservoir characterization. Richardson, TX: Society of Petroleum Engineers, 2006.

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Geologic analysis of naturally fractured reservoirs. 2nd ed. Boston: Gulf Professional Pub., 2001.

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Nelson, Ronald A. Geologic analysis of naturally fractured reservoirs. Houston: Gulf Pub. Co., Book Division, 1985.

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Barros Galvis, Nelson Enrique. Geomechanics, Fluid Dynamics and Well Testing, Applied to Naturally Fractured Carbonate Reservoirs. Cham: Springer International Publishing, 2018. http://dx.doi.org/10.1007/978-3-319-77501-2.

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Pashin, Jack C. Three-dimensional computer models of natural and induced fractures in coalbed methane reservoirs of bhe Black Warrior Basin. Tuscaloosa, Ala: Geological Survey of Alabama, 2004.

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Joint Symposium of the Canadian Society of Petroleum Geologists and the Canadian Well Logging Society (1st 1995 Calgary, Alta.). Savanna Creek, Alberta: A fractured carbonate reservoir in a complex structural setting : Canadian Society of Petroleum Geologists and Canadian Well Logging Society first joint symposium, 1995. Calgary: Canadian Society of Petroleum Geologists, 1995.

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Geologic Analysis of Naturally Fractured Reservoirs. Elsevier, 2001. http://dx.doi.org/10.1016/b978-0-88415-317-7.x5000-3.

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Galvis, Nelson Enrique Barros. Geomechanics, Fluid Dynamics and Well Testing, Applied to Naturally Fractured Carbonate Reservoirs: Extreme Naturally Fractured Reservoirs. Springer, 2019.

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Galvis, Nelson Enrique Barros. Geomechanics, Fluid Dynamics and Well Testing, Applied to Naturally Fractured Carbonate Reservoirs: Extreme Naturally Fractured Reservoirs. Springer, 2018.

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Book chapters on the topic "Naturally fractured reservoirs"

1

Ganat, Tarek Al-Arbi Omar. "Naturally Fractured Reservoirs." In Fundamentals of Reservoir Rock Properties, 131–52. Cham: Springer International Publishing, 2019. http://dx.doi.org/10.1007/978-3-030-28140-3_9.

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Arbogast, Todd, Jim Douglas, and Juan E. Santos. "Two-Phase Immiscible Flow in Naturally Fractured Reservoirs." In Numerical Simulation in Oil Recovery, 47–66. New York, NY: Springer US, 1988. http://dx.doi.org/10.1007/978-1-4684-6352-1_3.

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Chen, Zhangxin, and Jim Douglas. "Modelling of Compositional Flow in Naturally Fractured Reservoirs." In Environmental Studies, 65–96. New York, NY: Springer New York, 1996. http://dx.doi.org/10.1007/978-1-4613-8492-2_3.

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Barros Galvis, Nelson Enrique. "Analytical Model for Stress Sensitive Naturally Fractured Carbonate Reservoirs (NFCRs)." In Springer Theses, 93–102. Cham: Springer International Publishing, 2018. http://dx.doi.org/10.1007/978-3-319-77501-2_5.

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Barros Galvis, Nelson Enrique. "Analytical Model for Non Stress Sensitive Naturally Fractured Carbonate Reservoirs (NFCRs)." In Springer Theses, 77–91. Cham: Springer International Publishing, 2018. http://dx.doi.org/10.1007/978-3-319-77501-2_4.

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Shaik, Abdul Ravoof, Nam H. Tran, Mohammed A. Aghighi, Altaf H. Syed, and Sheikh S. Rahman. "Partially Coupled Fluid Flow Modeling for Stress Sensitive Naturally Fractured Reservoirs." In Thermo-Hydromechanical and Chemical Coupling in Geomaterials and Applications, 277–88. Hoboken, NJ, USA: John Wiley & Sons, Inc., 2013. http://dx.doi.org/10.1002/9781118623565.ch27.

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Arbogast, Todd. "The Double Porosity Model for Single Phase Flow in Naturally Fractured Reservoirs." In Numerical Simulation in Oil Recovery, 23–45. New York, NY: Springer US, 1988. http://dx.doi.org/10.1007/978-1-4684-6352-1_2.

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Douglas, Jim, P. J. Paes Leme, Felipe Pereira, and Li-Ming Yeh. "A Massively Parallel Iterative Numerical Algorithm for Immiscible Flow in Naturally Fractured Reservoirs." In Flow in Porous Media, 75–93. Basel: Birkhäuser Basel, 1993. http://dx.doi.org/10.1007/978-3-0348-8564-5_8.

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Sun, Hedong, Yongping Cui, Xiaopei Wang, Jianye Zhang, and Wen Cao. "Build-up Analysis of Multi-Well System in Naturally Fractured HTHP Gas Reservoirs." In Springer Series in Geomechanics and Geoengineering, 1850–69. Singapore: Springer Singapore, 2018. http://dx.doi.org/10.1007/978-981-10-7560-5_166.

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Douglas, Jim, Jeffrey L. Hensley, and Paulo Jorge Paes Leme. "A Study of the Effect of Inhomogeneities on Immiscible Flow in Naturally Fractured Reservoirs." In Flow in Porous Media, 59–74. Basel: Birkhäuser Basel, 1993. http://dx.doi.org/10.1007/978-3-0348-8564-5_7.

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Conference papers on the topic "Naturally fractured reservoirs"

1

Tiab, Djebbar, Dora Patrici Restrepo, and Alpheus Olorunwa Igbokoyi. "Fracture Porosity of Naturally Fractured Reservoirs." In International Oil Conference and Exhibition in Mexico. Society of Petroleum Engineers, 2006. http://dx.doi.org/10.2118/104056-ms.

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Daniels, S., R. Holdsworth, K. McCaffrey, J. Long, R. Jones, and R. Walker. "Characterising Fractured Basement Reservoirs." In Fourth Naturally Fractured Reservoir Workshop. European Association of Geoscientists & Engineers, 2020. http://dx.doi.org/10.3997/2214-4609.2020622024.

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Baker, Richard O., and Frank Kuppe. "Reservoir Characterization for Naturally Fractured Reservoirs." In SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers, 2000. http://dx.doi.org/10.2118/63286-ms.

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Kazemi, H., S. Atan, M. Al-Matrook, J. Dreier, and E. Ozkan. "Multilevel Fracture Network Modeling of Naturally Fractured Reservoirs." In SPE Reservoir Simulation Symposium. Society of Petroleum Engineers, 2005. http://dx.doi.org/10.2118/93053-ms.

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Torres, L. F. L., S. Salimzadeh, and H. M. Nick. "Interplay of heat transport and fracture aperture in fractured reservoirs." In Fourth Naturally Fractured Reservoir Workshop. European Association of Geoscientists & Engineers, 2020. http://dx.doi.org/10.3997/2214-4609.2020622031.

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Cipolla, C. L., P. T. Branagan, and S. J. Lee. "Fracture Design Considerations in Naturally Fractured Reservoirs." In International Meeting on Petroleum Engineering. Society of Petroleum Engineers, 1988. http://dx.doi.org/10.2118/17607-ms.

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Barton, N. R. "Characterization of Fracture Shearing for 4D Interpretation of Fractured Reservoirs." In Second Workshop on Naturally Fractured Reservoirs. Netherlands: EAGE Publications BV, 2013. http://dx.doi.org/10.3997/2214-4609.20132017.

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Price Projects and Technology, S., and L. Wei. "The Relative Importance of Fracture Parameters During Fractured Reservoir Development." In Second Workshop on Naturally Fractured Reservoirs. Netherlands: EAGE Publications BV, 2013. http://dx.doi.org/10.3997/2214-4609.20132028.

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Ukar, E. "Importance of diagenesis in naturaly fractured reservoirs." In Fourth Naturally Fractured Reservoir Workshop. European Association of Geoscientists & Engineers, 2020. http://dx.doi.org/10.3997/2214-4609.2020622040.

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Couples, G. D. "Keynote: Geomechanical Aspects of Fractured Reservoirs." In Second Workshop on Naturally Fractured Reservoirs. Netherlands: EAGE Publications BV, 2013. http://dx.doi.org/10.3997/2214-4609.20132007.

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Reports on the topic "Naturally fractured reservoirs"

1

Holcomb, D. J., S. R. Brown, J. C. Lorenz, W. A. Olsson, L. W. Teufel, and N. R. Warpinski. Geomechanics of horizontally-drilled, stress-sensitive, naturally-fractured reservoirs. Office of Scientific and Technical Information (OSTI), September 1994. http://dx.doi.org/10.2172/10190146.

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Wiggins, Michael L., Raymon L. Brown, Frauk Civan, and Richard G. Hughes. Development of Reservoir Characterization Techniques and Production Models for Exploiting Naturally Fractured Reservoirs. Office of Scientific and Technical Information (OSTI), August 2001. http://dx.doi.org/10.2172/784394.

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Wiggins, Michael L., Raymon L. Brown, Faruk Civan, and Richard G. Hughes. Development of Reservoir Characterization Techniques and Production Models for Exploiting Naturally Fractured Reservoirs. Office of Scientific and Technical Information (OSTI), February 2003. http://dx.doi.org/10.2172/807678.

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Wiggins, Michael L., Raymon L. Brown, Faruk Civan, and Richard G. Hughes. Development of Reservoir Characterization Techniques and Production Models for Exploiting Naturally Fractured Reservoirs. Office of Scientific and Technical Information (OSTI), October 2002. http://dx.doi.org/10.2172/802153.

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Wiggins, M. L., R. D. Evans, R. L. Brown, and A. Gupta. Development of Reservoir Characterization Techniques and Production Models for Exploiting Naturally Fractured Reservoirs. Office of Scientific and Technical Information (OSTI), March 2001. http://dx.doi.org/10.2172/776494.

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Michael L. Wiggins, Raymon L. Brown, Faruk Civan, and Richard G. Hughes. DEVELOPMENT OF RESERVOIR CHARACTERIZATION TECHNIQUES AND PRODUCTION MODELS FOR EXPLOITING NATURALLY FRACTURED RESERVOIRS. Office of Scientific and Technical Information (OSTI), December 2002. http://dx.doi.org/10.2172/820941.

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Lawrence W. Teufel, Her-Yuan Chen, Thomas W. Engler, and Bruce Hart. OPTIMIZATION OF INFILL DRILLING IN NATURALLY-FRACTURED TIGHT-GAS RESERVOIRS. Office of Scientific and Technical Information (OSTI), May 2004. http://dx.doi.org/10.2172/828437.

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Reis, J., and M. Miller. Oil recovery from naturally fractured reservoirs by steam injection methods. Office of Scientific and Technical Information (OSTI), January 1991. http://dx.doi.org/10.2172/6180458.

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Mojdeh Delshad, Gary A. Pope, and Kamy Sepehrnoori. Modeling Wettability Alteration using Chemical EOR Processes in Naturally Fractured Reservoirs. Office of Scientific and Technical Information (OSTI), September 2007. http://dx.doi.org/10.2172/927590.

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SEIDL, Georg, Philipp LANG, and Stephan MATTHÄI. Investigating Effects of Counter-Current Imbibition in Naturally-Fractured Reservoirs by Discrete Fracture Network Simulations. Cogeo@oeaw-giscience, September 2011. http://dx.doi.org/10.5242/iamg.2011.0182.

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