Download or read book Comparison of Single Double and Triple Linear Flow Models for Shale Gas oil Reservoirs written by Vartit Tivayanonda and published by . This book was released on 2012 with total page pages. Available in PDF, EPUB and Kindle. Book excerpt: There have been many attempts to use mathematical method in order to characterize shale gas/oil reservoirs with multi-transverse hydraulic fractures horizontal well. Many authors have tried to come up with a suitable and practical mathematical model. To analyze the production data of a shale reservoir correctly, an understanding and choosing the proper mathematical model is required. Therefore, three models (the homogeneous linear flow model, the transient linear dual porosity model, and the fully transient linear triple porosity model) will be studied and compared to provide correct interpretation guidelines for these models. The analytical solutions and interpretation guidelines are developed in this work to interpret the production data of shale reservoirs effectively. Verification and derivation of asymptotic and associated equations from the Laplace space for dual porosity and triple porosity models are performed in order to generate analysis equations. Theories and practical applications of the three models (the homogeneous linear flow model, the dual porosity model, and the triple porosity model) are presented. A simplified triple porosity model with practical analytical solutions is proposed in order to reduce its complexity. This research provides the interpretation guidelines with various analysis equations for different flow periods or different physical properties. From theoretical and field examples of interpretation, the possible errors are presented. Finally, the three models are compared in a production analysis with the assumption of infinite conductivity of hydraulic fractures.

Download or read book A Transport Model for Shale Gas and Oil Reservoirs Including Adsorption and Non Darcy Flow Effects written by Xinya Xiong and published by . This book was released on 2013 with total page 166 pages. Available in PDF, EPUB and Kindle. Book excerpt:

Download or read book Shale Gas and Tight Oil Reservoir Simulation written by Wei Yu and published by Gulf Professional Publishing. This book was released on 2018-07-29 with total page 432 pages. Available in PDF, EPUB and Kindle. Book excerpt: Shale Gas and Tight Oil Reservoir Simulation delivers the latest research and applications used to better manage and interpret simulating production from shale gas and tight oil reservoirs. Starting with basic fundamentals, the book then includes real field data that will not only generate reliable reserve estimation, but also predict the effective range of reservoir and fracture properties through multiple history matching solutions. Also included are new insights into the numerical modelling of CO2 injection for enhanced oil recovery in tight oil reservoirs. This information is critical for a better understanding of the impacts of key reservoir properties and complex fractures. - Models the well performance of shale gas and tight oil reservoirs with complex fracture geometries - Teaches how to perform sensitivity studies, history matching, production forecasts, and economic optimization for shale-gas and tight-oil reservoirs - Helps readers investigate data mining techniques, including the introduction of nonparametric smoothing models

Download or read book Challenges in Modelling and Simulation of Shale Gas Reservoirs written by Jebraeel Gholinezhad and published by Springer. This book was released on 2017-12-27 with total page 96 pages. Available in PDF, EPUB and Kindle. Book excerpt: This book addresses the problems involved in the modelling and simulation of shale gas reservoirs, and details recent advances in the field. It discusses various modelling and simulation challenges, such as the complexity of fracture networks, adsorption phenomena, non-Darcy flow, and natural fracture networks, presenting the latest findings in these areas. It also discusses the difficulties of developing shale gas models, and compares analytical modelling and numerical simulations of shale gas reservoirs with those of conventional reservoirs. Offering a comprehensive review of the state-of-the-art in developing shale gas models and simulators in the upstream oil industry, it allows readers to gain a better understanding of these reservoirs and encourages more systematic research on efficient exploitation of shale gas plays. It is a valuable resource for researchers interested in the modelling of unconventional reservoirs and graduate students studying reservoir engineering. It is also of interest to practising reservoir and production engineers.

Download or read book Unconventional Reservoir Geomechanics written by Mark D. Zoback and published by Cambridge University Press. This book was released on 2019-05-16 with total page 495 pages. Available in PDF, EPUB and Kindle. Book excerpt: A comprehensive overview of the key geologic, geomechanical and engineering principles that govern the development of unconventional oil and gas reservoirs. Covering hydrocarbon-bearing formations, horizontal drilling, reservoir seismology and environmental impacts, this is an invaluable resource for geologists, geophysicists and reservoir engineers.

Download or read book Comparison of Various Deterministic Forecasting Techniques in Shale Gas Reservoirs with Emphasis on the Duong Method written by Krunal Jaykant Joshi and published by . This book was released on 2012 with total page pages. Available in PDF, EPUB and Kindle. Book excerpt: There is a huge demand in the industry to forecast production in shale gas reservoirs accurately. There are many methods including volumetric, Decline Curve Analysis (DCA), analytical simulation and numerical simulation. Each one of these methods has its advantages and disadvantages, but only the DCA technique can use readily available production data to forecast rapidly and to an extent accurately. The DCA methods in use in the industry such as the Arps method had originally been developed for Boundary dominated flow (BDF) wells but it has been observed in shale reservoirs the predominant flow regime is transient flow. Therefore it was imperative to develop newer models to match and forecast transient flow regimes. The SEDM/SEPD, the Duong model and the Arps with a minimum decline rate are models that have the ability to match and forecast wells with transient flow followed by boundary flow. I have revised the Duong model to forecast better than the original model. I have also observed a certain variation of the Duong model proves to be a robust model for most of the well cases and flow regimes. The modified Duong has been shown to work best compared to other deterministic models in most cases. For grouped datasets the SPED & Duong models forecast accurately while the Modified Arps does a poor job.

Download or read book Evaluation of the Stretched Exponential Production Decline Model and Comparison to Other Decline Models for Shale Reservoirs written by Dong Li and published by . This book was released on 2013 with total page pages. Available in PDF, EPUB and Kindle. Book excerpt: The discovery and development of shale oil/gas has changed the energy industry. By 2040, shale gas production will account for 50% of the total natural gas production of the U.S. Due to the extremely low permeability of shale reservoirs, shale gas wells exhibit much longer transient flow periods than conventional wells, and this makes it inappropriate to use conventional methods of evaluating estimated ultimate recovery (EUR) of wells in these reservoirs. Therefore, new methods of forecasting shale wells are needed. In this study, I focused on the stretched exponential production decline model (SEPD), and particularly Yu’s modification of the model (YM-SEPD). I compared the results with other methods, including Duong’s method, and the Arps hyperbolic model. SEPD provided the most reliable EURs for shale gas well when excluding early off-trend data. YM-SEPD gave results comparable to SEPD and is much easier to apply. It is therefore the method we recommend for shale wells.

Download or read book Development of a Compositional Simulator for Liquid Rich Shale Reservoirs written by Vaibhav Rajput and published by . This book was released on 2016 with total page pages. Available in PDF, EPUB and Kindle. Book excerpt: Hydrocarbon production from shales has gained significant momentum in recent years with the advancement in hydraulic fracturing and horizontal drilling technologies, and production from shales (and unconventional sources in general) is beginning to garner greater share in US energy portfolio. However, storage and production mechanisms in these ultra-tight reservoirs is not well understood. It is widely believed that adsorption accounts for a significant portion of stored gas in shale gas reservoirs. However, whether this mechanism is important in liquid-rich systems is not well established. In addition to this, due to the matrix permeabilities existing in nano-darcy ranges, it is hard to establish physics of flow on Darcys law alone.In this work, we have developed a new thermodynamically consistent adsorption model that is made applicable to liquid-rich shale systems. Standalone calculations reveal that neglecting this storage mechanism could result in under-estimation of reserves by about 5-15%. The model is based on the ideal adsorbate solution theory (IAST), which has been successfully applied to coalbed methane and dry-gas shale systems earlier.Additionally, a new approach for multi-mechanistic flow formulation is applied in this study. Previously, multi-mechanistic studies include modeling diffusional flow based on the difference in concentration or molar density. However, this approach becomes handicapped when we have a single phase condition (gas/oil) in the matrix and the other single phase condition (oil/gas) in fractures, since it is not possible to consistently define concentration gradient across discontinuous phases. Such a condition is frequently expected to take place in shale systems, where pressure in fractures would be significantly different from that in the matrix, and therefore fractures may have two hydrocarbon phases, while matrix will still be in single phase condition. In our work, we have defined diffusive flux based on gradient in chemical potential, with the resulting equation being mathematically equivalent to the one defined based on concentration gradient. This approach is consistent across all the thermodynamic conditions (single and/or two phasic conditions).Finally, flow modeling in near-wellbore region is of utmost importance, especially in shale systems where early production phase is characterized by depletion through the hydraulically fractured region. It is established in literature that flow in near-wellbore region of horizontal well is of ellipsoidal nature. This is more emphasized when we consider that micro-seismic studies state that the fracturing process forms an ellipsoidal region. Thus, in order to model the flow pattern correctly, we have modeled the reservoir in ellipsoidal coordinates. A comparison of our models performance is made with analytical models presented for horizontal wells in homogenous regions.In addition, we also generated pressure-transient and pressure-derivative type curves using the ellipsoidal model. These type curves were validated using type-curve matching process, with satisfactory results. At the end, an in-depth sensitivity analysis was performed on certain important parameters and presented. Also, a case study is shown, using reservoir parameters from Utica and Marcellus shales. Sensitivity analysis is performed on drainage area and SRV volume, with some recommendations provided on economically-feasible drainage area per well.In summary, we have developed a three-phase, 3D, dual-porosity, dual-permeability compositional reservoir simulator in this study. The features presented above are incorporated in this model. Case studies illustrating the effect of important parameters in each of the above phenomenon are carried out and results are reported.

Download or read book A New Type Curve Analysis for Shale Gas oil Reservoir Production Performance with Dual Porosity Linear System written by Haider Jaffar Abdulal and published by . This book was released on 2012 with total page pages. Available in PDF, EPUB and Kindle. Book excerpt: With increase of interest in exploiting shale gas/oil reservoirs with multiple stage fractured horizontal wells, complexity of production analysis and reservoir description have also increased. Different methods and models were used throughout the years to analyze these wells, such as using analytical solutions and simulation techniques. The analytical methods are more popular because they are faster and more accurate. The main objective of this paper is to present and demonstrate type curves for production data analysis of shale gas/oil wells using a Dual Porosity model. Production data of horizontally drilled shale gas/oil wells have been matched with developed type curves which vary with effective parameters. Once a good match is obtained, the well dual porosity parameters can be calculated. A computer program was developed for more simplified matching process and more accurate results. As an objective of this thesis, a type curve analytical method was presented with its application to field data. The results show a good match with the synthetic and field cases. The calculated parameters are close to those used on the synthetic models and field cases.

Download or read book An Introduction to Reservoir Simulation Using MATLAB GNU Octave written by Knut-Andreas Lie and published by Cambridge University Press. This book was released on 2019-08-08 with total page 677 pages. Available in PDF, EPUB and Kindle. Book excerpt: Presents numerical methods for reservoir simulation, with efficient implementation and examples using widely-used online open-source code, for researchers, professionals and advanced students. This title is also available as Open Access on Cambridge Core.

Download or read book Phase Behavior And Flow Analysis Of Shale Reservoirs Using A Compositionally extended Black oil Approach written by Bahareh Nojabaei and published by . This book was released on 2015 with total page pages. Available in PDF, EPUB and Kindle. Book excerpt: Pore sizes are on the order of nanometers for shale and tight rock formations. Such small pores can affect the phase behavior of in-situ oil and gas owing to increased capillary pressure. Not accounting for increased capillary pressure can lead to inaccurate estimates of ultimate recovery. In this research, capillary pressure is coupled with phase equilibrium equations and the resulting system of nonlinear fugacity equations is solved to present a comprehensive examination of the effect of small pores on saturation pressures and fluid properties. The results show, for the first time, that accounting for the impact of small pore throats on PVT properties explains the inconsistent GOR behavior observed in tight formations. The small pores decrease bubble-point pressures and either decrease or increase dew-point pressures depending on which part of the two-phase envelope is examined. To estimate production from shale reservoirs, a simulation model should be designed to account for the effect of high capillary pressure on fluid properties. We have chosen to use a compositionally-extended black-oil approach since it is faster and more robust compared to a fully compositional simulation model. Black-oil fluid properties are calculated by flash calculations of the reservoir fluid. Allowing for a variable bubble-point pressure in black- or volatile-oil models requires a table of fluid properties be extended above the original bubble-point. We calculate continuous black-oil fluid properties above the original bubble-point by adding a fraction of the equilibrium gas at one bubble-point pressure to achieve a larger bubble-point pressure. This procedure continues until a critical point is reached. Unlike other commonly used methods, our approach provides a smooth and continuous pressure-composition curve to the critical point. If another component is added, the model further allows for injection of methane or CO2 to increase oil recovery. Further, the approach allows the use of black-oil or volatile-oil properties for tight rocks where capillary pressure affects hydrocarbon phase behavior. The compositional equations (gas, oil, and water components) are solved directly with principle unknowns of oil pressure, overall gas composition, and water saturation. Flash calculations in the model are non-iterative and are based on K-values calculated explicitly from the black-oil data. The advantage of solving the black-oil model using the compositional equations is to increase robustness of the simulations owing to a variable bubble-point pressure that is a function of two parameters, namely gas content and capillary pressure. Leverett J-functions are used to establish the effective pore size-Pc-saturation relationship. The input fluid data to the simulator are pre-calculated fluid properties as functions of pressure for three fixed pore sizes. During the simulation, at any pressure and saturation, fluid properties are calculated at the effective pore radius by using linear interpolation between these three data sets. Our results show that there is up to a 90% increase in recovery when capillary pressure is included in flash calculations. Reservoir initial pressure, reservoir permeability, initial water saturation, and critical gas saturation are among the factors influencing the increase in recovery due to the effect of capillary pressure.

Download or read book A Novel Approach For the Simulation of Multiple Flow Mechanisms and Porosities in Shale Gas Reservoirs written by Bicheng Yan and published by . This book was released on 2013 with total page 64 pages. Available in PDF, EPUB and Kindle. Book excerpt: The state of the art of modeling fluid flow in shale gas reservoirs is dominated by dual porosity models that divide the reservoirs into matrix blocks that significantly contribute to fluid storage and fracture networks which principally control flow capacity. However, recent extensive microscopic studies reveal that there exist massive micro- and nano- pore systems in shale matrices. Because of this, the actual flow mechanisms in shale reservoirs are considerably more complex than can be simulated by the conventional dual porosity models and Darcy's Law. Therefore, a model capturing multiple pore scales and flow can provide a better understanding of complex flow mechanisms occurring in these reservoirs. Through the use of a unique simulator, this research work establishes a micro-scale multiple-porosity model for fluid flow in shale reservoirs by capturing the dynamics occurring in three separate porosity systems: organic matter (mainly kerogen); inorganic matter; and natural fractures. Inorganic and organic portions of shale matrix are treated as sub-blocks with different attributes, such as wettability and pore structures. In the organic matter or kerogen, gas desorption and diffusion are the dominant physics. Since the flow regimes are sensitive to pore size, the effects of smaller pores (mainly nanopores and picopores) and larger pores (mainly micropores and nanopores) in kerogen are incorporated in the simulator. The separate inorganic sub-blocks mainly contribute to the ability to better model dynamic water behavior. The multiple porosity model is built upon a unique tool for simulating general multiple porosity systems in which several porosity systems may be tied to each other through arbitrary transfer functions and connectivities. This new model will allow us to better understand complex flow mechanisms and in turn to extend simulation to the reservoir scale including hydraulic fractures through upscaling techniques. The electronic version of this dissertation is accessible from http://hdl.handle.net/1969.1/151163

Download or read book Petroleum Abstracts written by and published by . This book was released on 1997 with total page 492 pages. Available in PDF, EPUB and Kindle. Book excerpt:

Download or read book Application of the Stretched Exponential Production Decline Model to Forecast Production in Shale Gas Reservoirs written by James Cody Statton and published by . This book was released on 2012 with total page pages. Available in PDF, EPUB and Kindle. Book excerpt: Production forecasting in shale (ultra-low permeability) gas reservoirs is of great interest due to the advent of multi-stage fracturing and horizontal drilling. The well renowned production forecasting model, Arps' Hyperbolic Decline Model, is widely used in industry to forecast shale gas wells. Left unconstrained, the model often overestimates reserves by a great deal. A minimum decline rate is imposed to prevent overestimation of reserves but with less than ten years of production history available to analyze, an accurate minimum decline rate is currently unknown; an educated guess of 5% minimum decline is often imposed. Other decline curve models have been proposed with the theoretical advantage of being able to match linear flow followed by a transition to boundary dominated flow. This thesis investigates the applicability of the Stretched Exponential Production Decline Model (SEPD) and compares it to the industry standard, Arps' with a minimum decline rate. When possible, we investigate an SEPD type curve. Simulated data is analyzed to show advantages of the SEPD model and provide a comparison to Arps' model with an imposed minimum decline rate of 5% where the full production history is known. Long-term production behavior is provided by an analytical solution for a homogenous reservoir with homogenous hydraulic fractures. Various simulations from short-term linear flow (~1 year) to long-term linear flow (~20 years) show the ability of the models to handle onset of boundary dominated flow at various times during production history. SEPD provides more accurate reserves estimates when linear flow ends at 5 years or earlier. Both models provide sufficient reserves estimates for longer-term linear flow scenarios. Barnett Shale production data demonstrates the ability of the models to forecast field data. Denton and Tarrant County wells are analyzed as groups and individually. SEPD type curves generated with 2004 well groups provide forecasts for wells drilled in subsequent years. This study suggests a type curve is most useful when 24 months or less is available to forecast. The SEPD model generally provides more conservative forecasts and EUR estimates than Arps' model with a minimum decline rate of 5%.

Download or read book Multiphase Fluid Flow in Porous and Fractured Reservoirs written by Yu-Shu Wu and published by Gulf Professional Publishing. This book was released on 2015-09-23 with total page 420 pages. Available in PDF, EPUB and Kindle. Book excerpt: Multiphase Fluid Flow in Porous and Fractured Reservoirs discusses the process of modeling fluid flow in petroleum and natural gas reservoirs, a practice that has become increasingly complex thanks to multiple fractures in horizontal drilling and the discovery of more unconventional reservoirs and resources. The book updates the reservoir engineer of today with the latest developments in reservoir simulation by combining a powerhouse of theory, analytical, and numerical methods to create stronger verification and validation modeling methods, ultimately improving recovery in stagnant and complex reservoirs. Going beyond the standard topics in past literature, coverage includes well treatment, Non-Newtonian fluids and rheological models, multiphase fluid coupled with geomechanics in reservoirs, and modeling applications for unconventional petroleum resources. The book equips today's reservoir engineer and modeler with the most relevant tools and knowledge to establish and solidify stronger oil and gas recovery. - Delivers updates on recent developments in reservoir simulation such as modeling approaches for multiphase flow simulation of fractured media and unconventional reservoirs - Explains analytical solutions and approaches as well as applications to modeling verification for today's reservoir problems, such as evaluating saturation and pressure profiles and recovery factors or displacement efficiency - Utilize practical codes and programs featured from online companion website

Download or read book Accounting for Exterior Flow Using the Modified Logistic Growth Model for Unconventional Geopressured Shale Reservoirs written by Julio Cesar Villarroel Salvatierra and published by . This book was released on 2023 with total page 0 pages. Available in PDF, EPUB and Kindle. Book excerpt: The flow of gas in shale gas wells is known to be linear from the matrix through fractures. At early times, the rate declines in proportion to the inverse of square root of time (t−1/2). Once fractures start interfering each other, the rate from the stimulated reservoir volume (SRV) declines exponentially (Patzek et al, 2013). The scope of this work is to assess the flow beyond boundary-dominated flow. Defining the existence of “exterior flow” and further use of decline curve analysis in unconventional reservoirs. This regime is the linear flow of gas from the non-stimulated matrix “feeding into” the depleted stimulated reservoir volume, at late times, beyond boundary-dominated flow. Additionally, we present novel diagnostic plots on rate-time data to obtain the characteristic time of switching from boundary-dominated to exterior flow that enables the prediction of additional volumes produced under this new flow regime. These volumes could be justified as probable reserves (P2). Clark, et al. (2011) presented a decline curve model based on nature’s theory of logistic growth that enlightened the use of the carrying capacity parameter “K” as a proxy for the Estimated Ultimate Recovery (EUR). However, in geopressured shales such as the Haynesville Shale, where Arps (1945) or any of the decline curve models currently available may not fit production curves, a flow regime analysis is needed in order to characterize the entire well history data and fit a model. Since all decline curve models are empirical, after appropriate flow regime identification, the modified logistic growth model (m-LGM) provides some physical meaning about the EUR. The logistic growth model fits all periods in a typical shale gas well: ramp-up, plateau, sharp decline; and the period described as exterior flow, which is evident as a kink in the slope of the logarithm of rate vs. time plot, is characterized by using an exponential decline tail (b-factor = 0). Moreover, for all the wells observed, the characteristic time of switching from boundary-dominated to exterior flow is between 4.5-5.0 years independent of well completion schemes and/or location. When volumes obtained from exterior flow are forecasted to economic limit rate, an additional 10-20% is observed compared to the EUR forecasted using classic decline curve analysis. As the Pareto Principle states: 80% of production comes from the most important 20% of the resource (ideally, the depleted stimulated reservoir volume, in this case). Thus, the remaining 20% from exterior flow. This could be a significant volume if hundreds or thousands of wells are accounted for in the basin. Finally, we present new diagnostic plots using rate-time data to better understand the flow regimes existing in a geopressured shale production curve that enables estimates of the volumes beyond boundary-dominated flow. This method accounts for an additional recovery that could be justified and categorized as probable reserves

Download or read book A Comprehensive Numerical Model for Simulating Two phase Flow in Shale Gas Reservoirs with Complex Hydraulic and Natural Fractures written by Mohammad Hamad AlTwaijri and published by . This book was released on 2017 with total page 158 pages. Available in PDF, EPUB and Kindle. Book excerpt: Increase in energy demand has played a significant role in the persistent exploitation and exploration of unconventional oil and gas resources. Shale gas reservoirs are one of the major unconventional resources. Advancements in horizontal drilling and hydraulic fracturing techniques have been the key to achieve economic rates of production from these shale gas reservoirs. In addition to their ultra-low permeability, shale gas reservoirs are characterized by their complex gas transport mechanisms and complex natural and induced (hydraulic) fracture geometries. Production from shale gas reservoirs is predominantly composed of two-phase flow of gas and water. However, proper modeling of the two-phase behavior as well as incorporating the complex fracture geometries have been a challenge within the industry. Due to the limitation of the local grid refinement (LGR) approach, hydraulic fractures are assumed to be planar (orthogonal), which is an unrealistic assumption. Although more flexible approaches are available, such as the use of unstructured grids, they require significantly high computational powers. In this research, an efficient embedded discrete fracture model (EDFM) is introduced to explicitly model complex fracture geometries. The EDFM approach is capable of explicitly modeling complex fracture geometries without increasing the computational demand. Utilizing EDFM alongside a commercial simulator, a 3D reservoir model is constructed to investigate the effect of complex fracture geometries on the two-phase flow of a shale gas well. In this investigation, varying degrees of hydraulic fracture complexity with 1-set and 2-set natural fractures were tested. The simulation results confirm the importance of properly modeling fracture complexity, highlighting that it plays an integral part in the estimation of gas and water recoveries. In addition, the simulation results hint to the pronounced effect of fracture interference as fracture complexity increases. Finally, variable fracture conductivities and initial water saturation values were analyzed to further assess their effect on the two-phase production behavior of the shale gas well. This study examines the effect of non-orthogonal complex fracture geometry on the two-phase flow of shale gas wells. The work can provide a significant insight toward understanding the extent to which fracture complexity can affect the performance of shale gas wells.