Download or read book Modeling Wettability Alteration in Naturally Fractured Carbonate Reservoirs written by Ali Goudarzi and published by . This book was released on 2011 with total page 180 pages. Available in PDF, EPUB and Kindle. Book excerpt: The demand for energy and new oil reservoirs around the world has increased rapidly while oil recovery from depleted reservoirs has become more difficult. Oil production from fractured carbonate reservoirs by water flooding is often inefficient due to the commonly oil-wet nature of matrix rocks. Chemical enhanced oil recovery (EOR) processes such as surfactant-induced wettability alteration and interfacial tension reduction are required to decrease the residual oil saturation in matrix blocks, leading to incremental oil recovery. However, improvement in recovery will depend on the degree of wettability alteration and interfacial tension (IFT) reduction, which in turn are functions of matrix permeability, fracture intensity, temperature, pressure, and fluid properties. The oil recovery from fractured carbonate reservoirs is frequently considered to be dominated by the spontaneous imbibition mechanism which is a combination of viscous, capillary, and gravity forces. The primary purpose of this study is to model wettability alteration in the lab scale for both coreflood and imbibition cell tests using the chemical flooding reservoir simulator. The experimental recovery data for fractured carbonate rocks with different petrophysical properties were history-matched with UTCHEM, The University of Texas in-house compositional chemical flooding simulator, using a highly heterogeneous permeability distribution. Extensive simulation work demonstrates the validity and ranges of applicability of upscaled procedures, and also indicates the importance of viscous and capillary forces in larger fields. The results of this work will be useful for designing field-scale chemical EOR processes.
Download or read book Experiments and Modeling of Wettability Alteration in Low Permeability Porous Media written by Prateek Kathel and published by . This book was released on 2015 with total page 0 pages. Available in PDF, EPUB and Kindle. Book excerpt: Naturally fractured reservoirs contain a significant amount of global hydrocarbon reserves. In fractured reservoirs, the efficiency of water flood is governed by spontaneous imbibition of water into oil-containing matrix blocks. When the matrix is oil-wet or mixed-wet, little oil can be recovered by imbibition. Wettability alteration provides a possible solution to enhance oil recovery in oil/mixed-wet fractured formations. Different chemicals such as surfactants, enzymes, selective ions can be used to alter wettability from oil-wet towards more water-wet which can substantially increase the oil recovery. Understanding recovery mechanisms for these processes at different inverse bond numbers (ratio of capillary to buoyancy forces) and developing scaling rules are critical for estimating feasibility at field scale. Surfactants were identified which altered the wettability of a low permeability (0.03 - 0.23 mD) mixed-wet/oil-wet sandstone reservoir. Static imbibition experiments in the surfactant solution resulted in high oil recovery (42-68% OOIP) compared to 15% OOIP in formation brine. High (>240) inverse bond numbers for these experiments indicate recovery mechanism as counter-current imbibition driven by capillary forces. Numerically simulated saturation and velocity profiles on validated datasets were analyzed to study the recovery mechanisms. Velocity profiles indicate counter current flows with velocity vectors pointing outwards. Similar visual observations were made during experiments, which were captured through images. The saturation front moves radially inward with symmetric profiles at the top and bottom. An analysis of scaling laws for the capillary driven flow suggests that imbibition recovery curves do not correlate with traditional scaling groups (Mattax and Kyte, 1962; Ma et al. 1997). The scaling equations analyzed are for strongly water-wet porous media and are insufficient to explain the dynamics of changing wettability from oil-wet to water-wet. The recovery data shows that oil recovery varies linearly with square root of time. It was observed that the rate of recovery was higher for the higher IFT cases in experiments performed on cores with almost same initial oil saturation using the same surfactant, but at different salinities. As a result of varying the salinity, interfacial tension between oil/water is varied. To evaluate the application of wettability altering processes at larger scales experiments were performed on outcrop cores of different dimensions and at dynamic conditions. Surfactant formulation was developed which altered the wettability from oil-wet to water-wet on outcrop rocks Estaillades Limestone and Texas Cream Limestone. Using the surfactant formulation static and dynamic imbibition experiments were performed on cores with different dimensions and boundary conditions. It is observed that dynamic imbibition process recovers oil faster than static imbibition. Imbibition experiments performed on cores with varying height and diameter show that oil recovery decreases with increasing diameter and height. Study of numerically simulated velocity and saturation profile on validated input datasets established the recovery mechanism as gravity dominated flow. Analytical scaling groups for gravity dominated flow were tested considering pressure drop only in water phase, pressure drop only in oil phase, and pressure drop across both water and oil phases. The model with pressure drop in both phases captures the decrease in recovery with increase in diameter and height of the core. Sensitivity to change in oil recovery with change in height is fairly accurate whereas the model over-predicts oil recovery with change in diameter. A new space-time scaling function (t/DH) is proposed for surfactant aided gravity dominated processes. Data with same boundary conditions, rock, fluids and varying dimensions can be correlated with the scaling function at early times with no fitting parameters involved. A good correlation is obtained with the data from different studies indicating the effectiveness of the scaling function. The scaling is applicable to both static as well as dynamic imbibition cases. Corefloods were performed on cores from different reservoirs to study the effect of wettability altering surfactant flood in a viscous pressure gradient driven process (as opposed to capillary or buoyancy driven imbibition process). Incremental oil recoveries over waterflood were analyzed for different injection schemes. Incremental recoveries over waterflood of 16% and 11% were obtained for secondary surfactant flood and slug process (surfactant slug injection after short initial waterflood) respectively for carbonate reservoir 1. Similarly, incremental recoveries over waterflood of 11% and 7% were obtained for secondary surfactant flood and slug process respectively for carbonate reservoir 2. The incremental oil recovery due to surfactant injection is attributed to the favorable increase in the relative permeability values of oil as the wettability is changed from oil-wet to water-wet. Experiments indicate that surfactant performance at the reservoir conditions (temperature, salinity, heterogeneity) is a key variable in these processes. Despite the differences in these conditions, for both the reservoirs oil recovery is more in the secondary surfactant injection mode compared to the slug process.
Download or read book Simulation Study to Investigate the Effect of Natural Fractures on the Performance of Surfactant polymer Flood in Carbonate Reservoirs written by Nawaf Ibrahim A. Sayedakram and published by . This book was released on 2011 with total page pages. Available in PDF, EPUB and Kindle. Book excerpt: This thesis presents a comprehensive simulation study on the impact of natural fractures on the performance of surfactant polymer flood in a field scale surfactant-polymer flood. The simulation model utilized for the study is a dual porosity dual permeability model representing 1/8 of a 20-acre 5-spot pattern. The model parameters studied include wettability alteration, IFT changes and mobility reduction effect. The results of this study clearly indicate the importance of reservoir description and fracture modeling for a successful surfactant-polymer flood. Naturally fractured carbonate reservoirs are usually characterized by mixed wettability and low matrix permeability which leads to low oil recovery and high remaining oil saturation. Enhanced oil recovery methods such as surfactant-polymer flood (SPF) enhance the recovery by increasing the spontaneous imbibitions either by lowering the interfacial tension or altering the wettability. However, one of the main reasons for failed surfactant-polymer floods is under-estimating the importance of the reservoir especially the description of natural fractures and their effect on recovery. Sensitivity runs were made to compare oil recovery capillary force, buoyancy force and viscous force. The simulation study indicates that critical water saturation should be reached before the start of surfactant-polymer flood to maximize oil recovery and utilize the capillary force. Also, when a surfactant alters the rock wettability, an optimum IFT should be identified for faster and higher imbibitions. The study shows that a contrast in permeability between that of the fracture and that of the matrix will result in a slightly lower oil recovery. Having the fracture perpendicular to the injector producer will result in a higher areal sweep and lower residual oil. A sensitivity study on the effect of the size of surfactant polymer slug was not conclusive. Maximum adsorption capacity was reached which was one of the causes of low imbibitions rate. Following the surfactant-polymer with water flood was able to reverse the adsorption and restore some of the movable oil. The results show that if the enhanced fluid that alter the wettability, imbibed in the matrix, injecting high IFT brine will increase the rate of imbibition. The study calls for further investigation of this phenomenon through research using a scaled laboratory model to verify the simulation results.
Download or read book Geomechanics Fluid Dynamics and Well Testing Applied to Naturally Fractured Carbonate Reservoirs written by Nelson Enrique Barros Galvis and published by Springer. This book was released on 2018-05-02 with total page 166 pages. Available in PDF, EPUB and Kindle. Book excerpt: This thesis presents an important step towards a deeper understanding of naturally fractured carbonate reservoirs (NFCRs). It demonstrates the various kinds of discontinuities using geological evidence, mathematical kinematics model and computed tomography and uses this as a basis for proposing a new classification for NFCRs. Additionally, this study takes advantage of rock mechanics theory to illustrate how natural fractures can collapse due to fluid flow and pressure changes in the fractured media. The explanations and mathematical modeling developed in this dissertation can be used as diagnostic tools to predict fluid velocity, fluid flow, tectonic fracture collapse, pressure behavior during reservoir depleting, considering stress-sensitive and non-stress-sensitive, with nonlinear terms in the diffusivity equation applied to NFCRs. Furthermore, the book presents the description of real reservoirs with their field data as the principal goal in the mathematical description of the realistic phenomenology of NFCRs.
Download or read book Naturally Fractured Reservoirs written by Roberto Aguilera and published by PennWell Books. This book was released on 1980 with total page 730 pages. Available in PDF, EPUB and Kindle. Book excerpt: This book deals exclusively with naturally fractured reservoirs and includes many subjects usually treated in separate volumes. A highly practical edition, Naturally Fractured Reservoirs is written for students, reservoir geologists, log analysts and petroleum engineers.
Download or read book Low Salinity and Engineered Water Injection for Sandstone and Carbonate Reservoirs written by Emad Walid Al Shalabi and published by Gulf Professional Publishing. This book was released on 2017-06-14 with total page 179 pages. Available in PDF, EPUB and Kindle. Book excerpt: Low Salinity and Engineered Water Injection for Sandstone and Carbonate Reservoirs provides a first of its kind review of the low salinity and engineered water injection (LSWI/EWI) techniques for today’s more complex enhanced oil recovery methods. Reservoir engineers today are challenged in the design and physical mechanisms behind low salinity injection projects, and to date, the research is currently only located in numerous journal locations. This reference helps readers overcome these challenging issues with explanations on models, experiments, mechanism analysis, and field applications involved in low salinity and engineered water. Covering significant laboratory, numerical, and field studies, lessons learned are also highlighted along with key areas for future research in this fast-growing area of the oil and gas industry. After an introduction to its techniques, the initial chapters review the main experimental findings and explore the mechanisms behind the impact of LSWI/EWI on oil recovery. The book then moves on to the critical area of modeling and simulation, discusses the geochemistry of LSWI/EWI processes, and applications of LSWI/EWI techniques in the field, including the authors’ own recommendations based on their extensive experience. It is an essential reference for professional reservoir and field engineers, researchers and students working on LSWI/EWI and seeking to apply these methods for increased oil recovery. Teaches users how to understand the various mechanisms contributing to incremental oil recovery using low salinity and engineering water injection (LSWI/EWI) in sandstones and carbonates Balances guidance between designing laboratory experiments, to applying the LSWI/EWI techniques at both pilot-scale and full-field-scale for real-world operations Presents state-of-the-art approaches to simulation and modeling of LSWI/EWI
Download or read book Foam Assisted Surfactant gas Flooding in Naturally Fractured Carbonate Reservoirs written by Hayrettin Aygol and published by . This book was released on 2017 with total page 0 pages. Available in PDF, EPUB and Kindle. Book excerpt: In naturally fractured reservoirs, water flood performance and efficiency for oil recovery is usually limited by capillary forces. Wettability and interfacial tension (IFT) between oil and water phases are essential factors that limit the potential for oil production in naturally fractured reservoirs. The permeability of such reservoirs is in range of 1~20 md (majority of carbonate reservoirs) with the matrix wettability preferentially oil-wet to mixed-wet. Hence, water and/or gas flood performances are not efficient due to the tendency of water or gas flow through fractures. Surfactants are used to reduce IFT between oil and water, alter the wettability of matrix to proficiently water-wet, and generate in-situ foam as a drive and for mobility control. Spontaneous imbibition between the fractures and the matrix is achieved by both wettability alteration and ultra-low interfacial tensions. Experimental studies show that co-injection or alternate injection of surfactant solution and gas are very promising to mobilize and solubilize the remaining oil. In this study, we overview to provide a technical background and review the literature extensively in order to understand surfactant flooding and foam performance in porous media. Results show that surfactants are induced to matrix through fractures not only by spontaneous imbibition, but also by foam that diverts surfactant solutions into low permeability matrix. The finding results by several authors in lab-scale indicate that surfactant type, foam properties, capillary pressure properties corresponding to different wetting states, and oil-water interfacial tension are crucial factors that significantly impact the efficiency of such processes. In general, summary of this work shows that foam plays a dominant role as a drive to displace the oil in matrix when capillary forces are not strong to retain the oil in presence of surfactants. Although there is very restricted work that claim foam efficiency in presence of oil, mobilized oils are displaced and moved toward fractures as pure oil bank (oil phase). Some laboratory measurements and simulation study reveal with both core and reservoir scales that such process provides great sweep efficiency and recover a significant amount of remaining oil from the matrix to fracture.
Download or read book Fractured Vuggy Carbonate Reservoir Simulation written by Jun Yao and published by Springer. This book was released on 2017-08-08 with total page 253 pages. Available in PDF, EPUB and Kindle. Book excerpt: This book solves the open problems in fluid flow modeling through the fractured vuggy carbonate reservoirs. Fractured vuggy carbonate reservoirs usually have complex pore structures, which contain not only matrix and fractures but also the vugs and cavities. Since the vugs and cavities are irregular in shape and vary in diameter from millimeters to meters, modeling fluid flow through fractured vuggy porous media is still a challenge. The existing modeling theory and methods are not suitable for such reservoir. It starts from the concept of discrete fracture and fracture-vug networks model, and then develops the corresponding mathematical models and numerical methods, including discrete fracture model, discrete fracture-vug model, hybrid model and multiscale models. Based on these discrete porous media models, some equivalent medium models and methods are also discussed. All the modeling and methods shared in this book offer the key recent solutions into this area.
Download or read book Wettability Alteration by Glycine and Seawater Injection in Carbonate Reservoirs written by Ricardo Antonio Lara Orozco and published by . This book was released on 2022 with total page 0 pages. Available in PDF, EPUB and Kindle. Book excerpt: Carbonate reservoirs contain more than half of the world’s conventional oil reserves. However, since most carbonates are naturally fractured and oil- to mixed-wet there is often significant oil saturation remaining after waterflooding. This is because the injected water mostly flows through the fractures without imbibing into the oil-wet matrix. There is an increasing interest in finding low-cost and enviromentally-friendly wettability modifiers that promote water imbibition by shiftting the wetting state of the rock matrix. These injected chemicals, however, must be able to withstand the high temperatures and high salinity brines typically found in carbonate reservoirs. This study presents experimental investigation and modeling work of the application of glycine as a wettability modifier for carbonate reservoirs to improve oil recovery. We first investigated the potential of glycine in altering the wettability of carbonate surfaces. The experiment consisted of monitoring the contact angle of oil droplets placed on top of natural calcite pieces at 95°C for 5 days. The calcite surface remained oil-wet when submerged in formation brine with an average contact angle of 130°. Similar results were obtained with seawater (SW) with a contact angle of 128°. Low salinity water (LSW) was also tested by diluting SW ten times. It resulted in an average contact angle of 108°. In contrast, a strongly water-wet condition was obtained using FB with a glycine concentration of 5 wt% with an average contact angle of 50°. The oil droplets started to detach from the surface on the fourth day. This was direct evidence of the effect of glycine on altering the wetting-state of carbonate surfaces. We then investigated the enhance oil recovery in carbonate rocks by glycine. Spontaneous imbibition experiments were performed at 95 °C with Indiana Limestone cores. Glycine solutions were prepared with FB, SW, and LSW, with a concentration of 5 wt% and compared to LSW. On average, the glycine solutions recovered about 25% more oil than LSW. The recovery factor as a function of the squared root of time showed a linear trend typical of capillary-dominated flow. Glycine significantly enhanced oil recovery in high temperature and high salinity conditions by promoting spontaneous imbibition of water. An explanation to the previous experimental results is that glycine anion interacts with the positively charged surface of carbonate rocks. Wettability alteration then occurs by glycine adsorption and the corresponding removal of organic material from the rock surface. Based on this hypothesis, this research proposes a surface complexation reaction between glycine and carboxylic acids to model wettability alteration. The equilibrium constant was obtained by matching the zeta potential measurements of synthetic calcite in glycine solutions. The tuned surface complexation model (SCM) was used to investigate the desorption of carboxylic acids as a function of glycine concentration and temperature. The results correlated with the contact angle measurements and the recovery factor from the spontaneous imbibition experiments. High temperature was found to be critical for wettability alteration because it increases the concentration of glycine anion in the aqueous phase. Finally, we coupled the SCM in PHREEQC with a numerical model of two-phase flow displacement to investigate the major geochemical reactions driving wettability alteration in carbonates. We found that eight surface complexation reactions in the SCM can be simplified into a couple of anion exchange reactions between the injected wettability modifiers, glycine anion, sulfate ion, and the adsorbed carboxylic acids. Analytical solutions are then presented for the coupled two-phase and multicomponent reactive-transport model with anion exchange reactions to model the injection of wettability modifiers in carbonates
Download or read book The Applicability of Wettability Alteration to Naturally Fractured Reservoirs and Imbibition Waterflooding written by Daniel Joseph Bradley and published by . This book was released on 1983 with total page 118 pages. Available in PDF, EPUB and Kindle. Book excerpt:
Download or read book Drilling Geomechanics in Naturally Fractured Reservoirs Near Salt Structures written by Juan Pedro Morales Salazar and published by Springer Nature. This book was released on with total page 169 pages. Available in PDF, EPUB and Kindle. Book excerpt:
Download or read book Models for Naturally Fractured Carbonate Reservoir Simulations written by and published by . This book was released on 1998 with total page 16 pages. Available in PDF, EPUB and Kindle. Book excerpt: This report outlines the need for new tools for the simulation of fractured carbonate reservoirs. Several problems are identified that call for the development of new reservoir simulation physical models and numerical techniques. These include: karst and vuggy media wherein Darcy's and traditional multi-phase flow laws do not apply; the need for predicting the preproduction state of fracturing and stress so that the later response of effective stress-dependent reservoirs can be predicted; and methods for predicting the fracturing and collapse of vuggy and karst reservoirs in response to draw-down pressure created during production. Specific research directions for addressing each problem are outlined and preliminary results are noted.
Download or read book Modeling Conformance Control and Chemical EOR Processes Using Different Reservoir Simulators written by Ali Goudarzi and published by . This book was released on 2015 with total page 830 pages. Available in PDF, EPUB and Kindle. Book excerpt: Successful field waterflood is a crucial prerequisite for improving the performance before EOR methods, such as ASP, SP, and P flooding, are applied in the field. Excess water production is a major problem in mature waterflooded oil fields that leads to early well abandonment and unrecoverable hydrocarbon. Gel treatments at the injection and production wells to preferentially plug the thief zones are cost-effective methods to improve sweep efficiency in reservoirs and reduce excess water production during hydrocarbon recovery. There are extensive experimental studies performed by some researchers in the past to investigate the performance of gels in conformance control and decreasing water production in mature waterflooded reservoirs, but no substantial modeling work has been done to simulate these experiments and predict the results for large field cases. We developed a novel, 3-dimensional chemical compositional and robust general reservoir simulator (UTGEL) to model gel treatment processes. The simulator has the capability to model different types of microgels, such as preformed particle gels (PPG), thermally active polymers (TAP), pH-sensitive microgels, and colloidal dispersion gels (CDG). The simulator has been validated for gel flooding using laboratory and field scale data. The simulator helps to design and optimize the flowing gel injection for conformance control processes in larger field cases. The gel rheology, adsorption, resistance factor and residual resistance factor with salinity effect, gel viscosity, gel kinetics, and swelling ratio were implemented in UTGEL. Several simulation case studies in fractured and heterogeneous reservoirs were performed to illustrate the effect of gel on production behavior and water control. Laboratory results of homogeneous and heterogeneous sandpacks, and Berea sandstone corefloods were used to validate the PPG transport models. Simulations of different heterogeneous field cases were performed and the results showed that PPG can improve the oil recovery by 5-10% OOIP compared to waterflood. For recovery from fractured reservoirs by waterflooding, injected water will flow easily through fractures and most part of reservoir oil will remain in matrix blocks unrecovered. Recovery from these reservoirs depends on matrix permeability, wettability, fracture intensity, temperature, pressure, and fluid properties. Chemical processes such as polymer flooding (P), surfactant/polymer (SP) flooding and alkali/surfactant/polymer (ASP) flooding are being used to enhance reservoir energy and increase the recovery. Chemical flooding has much broader range of applicability than in the past. These include high temperature reservoirs, formations with extreme salinity and hardness, naturally fractured carbonates, and sandstone reservoirs with heavy and viscous crude oils. The recovery from fractured carbonate reservoirs is frequently considered to be dominated by spontaneous imbibition. Therefore, any chemical process which can enhance the rate of imbibition has to be studied carefully. Wettability alteration using chemicals such as surfactant and alkali has been studied by many researchers in the past years and is recognized as one of the most effective recovery methods in fractured carbonate reservoirs. Injected surfactant will alter the wettability of matrix blocks from oil-wet to water-wet and also reduce the interfacial tension to ultra-low values and consequently more oil will be recovered by spontaneous co-current or counter-current imbibition depending on the dominant recovery mechanism. Accurate and reliable up-scaling of chemical enhanced oil recovery processes (CEOR) are among the most important issues in reservoir simulation. The important challenges in up-scaling CEOR processes are predictability of developed dimensionless numbers and also considering all the required mechanisms including wettability alteration and interfacial tension reduction. Thus, developing new dimensionless numbers with improved predictability at larger scales is of utmost importance in CEOR processes. There are some scaling groups developed in the past for either imbibition or coreflood experiments but none of them were predictive because all the physics related to chemical EOR processes (interfacial tension reduction and wettability alteration) were not included. Furthermore, most of commercial reservoir simulators do not have the capability to model imbibition tests due to lack of some physics, such as surfactant molecular diffusion. The modeling of imbibition cell tests can aid to understand the mechanisms behind wettability alteration and consequently aid in up-scaling the process. Also, modeling coreflood experiments for fractured vuggy carbonates is challenging. Different approaches of random permeability distribution and explicit fractures were used to model the experiments which demonstrate the validity and ranges of applicability of upscaled procedures, and also indicate the importance of viscous and capillary forces in larger scales. The simulation models were then used to predict the recovery response times for larger cores.
Download or read book Carbonate Reservoirs written by Clyde H. Moore and published by Elsevier Inc. Chapters. This book was released on 2013-08-12 with total page 50 pages. Available in PDF, EPUB and Kindle. Book excerpt: Carbonate reservoirs are prone to natural fracturing. Fractures can act as enhanced permeability pathways, which may increase, decrease, or complicate reservoir production and development; healed fractures contribute to reservoir compartmentalization. A primary focus is placed upon the predictability of fracture set patterns and orientations, which vary according to carbonate lithofacies and the stress field(s) under which different types of fractures form. Extension fractures can form at the surface or at reservoir depths. Certain types of extension fracture sets (e.g., syndepositional, regional, and—to a lesser extent—karst-related fracture sets) exhibit predictable patterns and orientations with respect to the stress field under which they originated. Surface outcrops commonly exhibit multiple fracture sets; these are most frequently related to relaxation of compaction and/or thermal cooling. Such fracture sets are considered unlikely to resemble fracture sets in nearby reservoirs at depth; therefore, the use of surface fracture patterns as analogs for same-formation reservoirs, without comparative analysis of burial stress histories, is risky. Fault-related fractures have very high permeability potentials when newly formed, but their resulting role as fluid conduits typically leads to rapid healing, and therefore a higher likelihood of causing reservoir compartmentalization. These fractures typically cut across multiple beds. Fold-related fracture patterns are complex, typically consisting of both extension and conjugate shear-pair fractures, and show variable orientations in space and/or over time. However, they tend to follow the geometries of individual beds and are often confined to single beds, rather than aligning according to overall structural axes. Ekofisk Field, a naturally fractured North Sea chalk reservoir, is presented as an illustrative case of fold-related fracture abundance and effectiveness in enhancing fieldwide permeability parameters, without the drawback of creating major production problems during waterflooding.
Download or read book Predicting the Natural State of Fractured Carbonate Reservoirs written by and published by . This book was released on 1998 with total page 101 pages. Available in PDF, EPUB and Kindle. Book excerpt: The power of the reaction, transport, mechanical (RTM) modeling approach is that it directly uses the laws of geochemistry and geophysics to extrapolate fracture and other characteristics from the borehole or surface to the reservoir interior. The objectives of this facet of the project were to refine and test the viability of the basin/reservoir forward modeling approach to address fractured reservoir in E and P problems. The study attempts to resolve the following issues: role of fracturing and timing on present day location and characteristics; clarifying the roles and interplay of flexure dynamics, changing rock rheological properties, fluid pressuring and tectonic/thermal histories on present day reservoir location and characteristics; and test the integrated RTM modeling/geological data approach on a carbonate reservoir. Sedimentary, thermal and tectonic data from Andector Field, West Texas, were used as input to the RTM basin/reservoir simulator to predict its preproduction state. The results were compared with data from producing reservoirs to test the RTM modeling approach. The effects of production on the state of the field are discussed in a companion report. The authors draw the following conclusions: RTM modeling is an important new tool in fractured reservoir E and P analysis; the strong coupling of RTM processes and the geometric and tensorial complexity of fluid flow and stresses require the type of fully coupled, 3-D RTM model for fracture analysis as pioneered in this project; flexure analysis cannot predict key aspects of fractured reservoir location and characteristics; fracture history over the lifetime of a basin is required to understand the timing of petroleum expulsion and migration and the retention properties of putative reservoirs.
Download or read book Development Theories and Methods of Fracture Vug Carbonate Reservoirs written by Yang Li and published by Academic Press. This book was released on 2017-05-17 with total page 515 pages. Available in PDF, EPUB and Kindle. Book excerpt: Development Theories and Methods of Fracture-Vug Carbonate Reservoirs explores the theories and methods for successful development of a fracture-vug reservoir by presenting the developmental strategies used in the Tahe oilfield. Some of the theories and methods of developing the Tahe fracture-vug reservoirs have been inspired by two China national research projects: The ‘Basic research on development of fracture-vug carbonate reservoirs’ (2006-2010), and the ‘Basic research on production mechanism and oil recovery enhancement of fracture-vugcarbonate reservoirs’ (2011-2015), with support by the National Basic Research Program of China. These theories and methods have facilitated the successful development of the fracture-vug reservoir in the Tahe oilfield, providing effective technologies and inspirations to developing similar reservoirs everywhere. Provides information on both theoretical developments and technological innovations Applies the modern karst formation characterization and the fracture-vug hierarchical structure to geological investigations of fracture-vug carbonate reservoirs Introduces the karst facies-controlling 3D geologic modeling of fracture-vug reservoir formations Proposes the coupled-processing and equivalent multi-medium numerical simulation methods of fracture-vug reservoirs Presents development methodologies and techniques of water/gas flooding
