Download or read book A Coupled Wellbore reservoir Simulator to Model Multiphase Flow and Temperature Distribution written by Peyman Pourafshary and published by . This book was released on 2007 with total page 0 pages. Available in PDF, EPUB and Kindle. Book excerpt: Hydrocarbon reserves are generally produced through wells drilled into reservoir pay zones. During production, gas liberation from the oil phase occurs due to pressure decline in the wellbore. Thus, we expect multiphase flow in some sections of the wellbore. As a multi-phase/multi-component gas-oil mixture flows from the reservoir to the surface, pressure, temperature, composition, and liquid holdup distributions are interrelated. Modeling these multiphase flow parameters is important to design production strategies such as artificial lift procedures. A wellbore fluid flow model can also be used for pressure transient test analysis and interpretation. Considering heat exchange in the wellbore is important to compute fluid flow parameters accurately. Modeling multiphase fluid flow in the wellbore becomes more complicated due to heat transfer between the wellbore fluids and the surrounding formations. Due to mass, momentum, and energy exchange between the wellbore and the reservoir, the wellbore model should be coupled with a numerical reservoir model to simulate fluid flow accurately. This model should be non-isothermal to consider the effect of temperature. Our research shows that, in some cases, ignoring compositional effects may lead to errors in pressure profile prediction for the wellbore. Nearly all multiphase wellbore simulations are currently performed using the "black oil" approach. The primary objective of this study was to develop a non-isothermal wellbore simulator to model transient fluid flow and temperature and couple the model to a reservoir simulator called General Purpose Adaptive Simulator (GPAS). The coupled wellbore/reservoir simulator can be applied to steady state problems, such as production from, or injection to a reservoir as well as during transient phenomena such as well tests to accurately model wellbore effects. Fluid flow in the wellbore may be modeled either using the blackoil approach or the compositional approach, as required by the complexity of the fluids. The simulation results of the new model were compared with field data for pressure gradients and temperature distribution obtained from wireline conveyed pressure recorder and acoustic fluid level measurements for a gas/oil producer well during a buildup test. The model results are in good agreement with the field data. Our simulator gave us further insights into the wellbore dynamics that occur during transient problems such as phase segregation and counter-current multiphase flow. We show that neglecting these multiphase flow dynamics would lead to unreliable results in well testing analysis.

Download or read book Development of a Coupled Wellbore reservoir Compositional Simulator for Horizontal Wells written by Mahdy Shirdel and published by . This book was released on 2010 with total page 402 pages. Available in PDF, EPUB and Kindle. Book excerpt: Two-phase flow occurs during the production of oil and gas in the wellbores. Modeling this phenomenon is important for monitoring well productivity and designing surface facilities. Since the transient time period in the wellbore is usually shorter than reservoir time steps, stabilized flow is assumed in the wellbore. As such, semi-steady state models are used for modeling wellbore flow dynamics. However, in the case that flow variations happen in a short period of time (i.e., a gas kick during drilling) the use of a transient two-phase model is crucial. Over the last few years, a number of numerical and analytical wellbore simulators have been developed to mimic wellbore-reservoir interaction. However, some issues still remain a concern in these studies. The main issues surrounding a comprehensive wellbore model consist of fluid property calculations, such as black-oil or compositional models, governing equations, such as mechanistic or correlation-based models, effect of temperature variation and non-isothermal assumption, and methods for coupling the wellbore to the reservoir. In most cases, only standalone wellbore models for blackoil have been used to simulate reservoir and wellbore dynamic interactions. Those models are based on simplified assumptions that lead to an unrealistic estimation of pressure and temperature distributions inside the well. In addition, most reservoir simulators use rough estimates for the perforation pressure as a coupling condition between the wellbore and the reservoir, neglecting pressure drops in the horizontal section. In this study, we present an implementation of a compositional, pseudo steady-state, non-isothermal, coupled wellbore-reservoir simulator for fluid flow in wellbores with a vertical section and a horizontal section embedded on the producing reservoir. In addition, we present the implementation of a pseudo-compositional, fully implicit, transient two-fluid model for two-phase flow in wellbores. In this model, we solve gas/liquid mass balance, gas/liquid momentum balance, and two-phase energy equations in order to obtain the five primary variables: liquid velocity, gas velocity, pressure, holdup and temperature. In our simulation, we compared stratified, bubbly, intermittent flow effects on pressure and temperature distributions in either a transient or steady-state condition. We found that flow geometry variation in different regimes can significantly affect the flow parameters. We also observed that there are significant differences in flow rate prediction between a coupled wellbore-reservoir simulator and a stand-alone reservoir simulator, at the early stages of production. The outcome of this research leads to a more accurate and reliable simulation of multiphase flow in the wellbore, which can be applied to surface facility design, well performance optimization, and wellbore damage estimation.

Download or read book Development of an Integrated Compositional Wellbore reservoir Simulator for Flow Assurance Problems written by Ali Abouie and published by . This book was released on 2019 with total page 0 pages. Available in PDF, EPUB and Kindle. Book excerpt: Flow assurance problems such as asphaltene and geochemical scale precipitation and deposition are among the major operational challenges encountered during oil production. The variations in thermodynamic conditions such as pressure, temperature, and/or fluid composition can result in formation and deposition of solid particles (e.g., asphaltene and scale particles) in the reservoir and wellbore. Although asphaltene and scale precipitation and deposition can occur in the reservoir and near-wellbore regions, this problem is mainly observed in the production wells. Precipitation and deposition of asphaltene and scale particles in the wellbore can cause partial or total plugging of tubing. Asphaltene and scale precipitation from the reservoir fluids can also cause formation damage problems (i.e., pore throat plugging and wettability alteration) in the reservoir and near-wellbore region. These factors affect the economics of the project by lowering the production rate and requiring remediation. Application of improved oil recovery techniques such as waterflooding and miscible gas flooding has also increased the chances of scale and asphaltene formation in the wellbore and near-wellbore region. In this dissertation, we developed an integrated compositional coupled wellbore-reservoir simulator to accurately predict the detrimental effects of asphaltene and scale deposition on production performance of the oilfields. The simulation results illustrate the time and the location at which asphaltene and scale deposition damage the efficiency and productivity of the production wells. This prediction is highly crucial to monitor the production performance of the field, to optimize the field operating condition which leads to minimum asphaltene or scale formation, and to propose the effective remediation techniques. The developed wellbore model has the flexibility to work in standalone mode or in conjunction with the reservoir simulator. To accurately model the asphaltene phase behavior as a function of pressure, temperature, and hydrocarbon fluid composition, PC-SAFT equation-of-state is implemented into a non-isothermal, multiphase, multi-component compositional wellbore simulator (UTWELL). PC-SAFT models asphaltene precipitation by performing a three-phase flash calculation to determine the formation of the second-liquid phase or asphaltene-rich phase. Flocculation and deposition models are also integrated with the thermodynamic models to mimic the dynamics of asphaltene deposition during multiphase flow in the wellbore. In addition, the computational time of the reservoir simulator (UTCOMP) with PC-SAFT EOS was improved by parallelizing the phase behavior module. To investigate the dynamics of asphaltene deposition under fluid flow condition, several mechanisms such as asphaltene precipitation, asphaltene deposition, porosity and permeability reduction, wettability alteration, and viscosity modification were included in the developed model. For mechanistic modeling of scale deposition in the wellbore, a detailed procedure is presented through which a comprehensive geochemical package, IPhreeqc, is integrated within the wellbore simulator. The integrated model has the capability to model reversible, irreversible, and ion exchange reactions under non-isothermal, non-isobaric, and local equilibrium or kinetic conditions inside the wellbore. In addition, the effects of hydrocarbon components and weak acids dissolutions in the aqueous phase are included in the integrated model to accurately predict scale deposition profile. Moreover, the developed wellbore model and the reservoir simulator were coupled to investigate the effects of key parameters such as pressure, temperature, hydrocarbon fluid composition, aqueous phase composition, breakthrough time, particle transportation, and flow dynamics on asphaltene/scale precipitation and deposition. The coupled wellbore-reservoir model can also be applied to achieve the optimum solution (e.g., operating condition, injection water composition, injection gas composition) with minimum asphaltene/scale problems in the production system. Finally, continuous chemical injection model was implemented within the wellbore simulator to investigate the effectiveness of chemical injection on prevention of asphaltene precipitation. The simulation results revealed that proper selection of the type and injection rate of solvent can minimize asphaltene deposition in the wellbore

Download or read book An Introduction to Multiphase Multicomponent Reservoir Simulation written by Matthew Balhoff and published by Elsevier. This book was released on 2022-10-26 with total page 348 pages. Available in PDF, EPUB and Kindle. Book excerpt: An Introduction to Petroleum Reservoir Simulation is aimed toward graduate students and professionals in the oil and gas industry working in reservoir simulation. It begins with a review of fluid and rock properties and derivation of basic reservoir engineering mass balance equations. Then equations and approaches for numerical reservoir simulation are introduced. The text starts with simple problems (1D, single phase flow in homogeneous reservoirs with constant rate wells) and subsequent chapters slowly add complexities (heterogeneities, nonlinearities, multi-dimensions, multiphase flow, and multicomponent flow). Partial differential equations and finite differences are then introduced but it will be shown that algebraic mass balances can also be written directly on discrete grid blocks that result in the same equations. Many completed examples and figures will be included to improve understanding. An Introduction to Petroleum Reservoir Simulation is designed for those with their first exposure to reservoir simulation, including graduate students in their first simulation course and working professionals who are using reservoir simulators and want to learn more about the basics. - Presents basic equations and discretization for multiphase, multicomponent transport in subsurface media in a simple, easy-to-understand manner - Features illustrations that explain basic concepts and show comparison to analytical solutions and commercial simulators - Includes dozens of completed example problems on a small number of grid blocks - Offers pseudocode and exercises to allow the reader to develop their own computer-based numerical simulator that can be verified against analytical solutions and commercial simulators

Download or read book Transient Fluid and Heat Flow Modeling in Coupled Wellbore reservoir Systems written by Bulent Izgec and published by . This book was released on 2010 with total page pages. Available in PDF, EPUB and Kindle. Book excerpt: Modeling of changing pressure, temperature, and density profiles in a wellbore as a function of time is crucial for design and analysis of pressure-transient tests (particularly when data are gathered above perforations), real-time management of annular-pressure buildup (ABP) and identifying potential flow-assurance issues. Other applications of this modeling approach include improving design of production tubulars and artificial-lift systems and gathering pressure data for continuous reservoir management. This work presents a transient wellbore model coupled with a semianalytic temperature model for computing wellbore-fluid-temperature profile in flowing and shut-in wells. The accuracy of the analytic heat-transfer calculations improved with a variable-formation temperature model and a newly developed numerical-differentiation scheme. Surrounding formation temperature is updated in every timestep up to a user specified distance to account for changes in heat-transfer rate between the hotter wellbore fluid and the cooler formation. Matrix operations are not required for energy calculations because of the semianalytic formulation. This efficient coupling with the semianalytic heat-transfer model increased the computational speed significantly. Either an analytic or a numeric reservoir model can be coupled with the transient wellbore model for rapid computations of pressure, temperature, and velocity. The wellbore simulator is used for modeling a multirate test from a deep offshore well. Thermal distortion and its effects on pressure data is studied using the calibrated model, resulting in development of correlations for optimum gauge location in both oil and gas wells. Finally, predictive capabilities of the wellbore model are tested on multiple onshore wells experiencing annular-pressure buildup problems. Modeling results compare quite well with the field data and also with the state-of-the-art commercial wellbore simulator.

Download or read book Development of a Coupled Wellbore reservoir Compositional Simulator for Damage Prediction and Remediation written by Mahdy Shirdel and published by . This book was released on 2013 with total page 0 pages. Available in PDF, EPUB and Kindle. Book excerpt: During the production and transportation of oil and gas, flow assurance issues may occur due to the solid deposits that are formed and carried by the flowing fluid. Solid deposition may cause serious damage and possible failure to production equipment in the flow lines. The major flow assurance problems that are faced in the fields are concerned with asphaltene, wax and scale deposition, as well as hydrate formations. Hydrates, wax and asphaltene deposition are mostly addressed in deep-water environments, where fluid flows through a long path with a wide range of pressure and temperature variations (Hydrates are generated at high pressure and low temperature conditions). In fact, a large change in the thermodynamic condition of the fluid yields phase instability and triggers solid deposit formations. In contrast, scales are formed in aqueous phase when some incompatible ions are mixed. Among the different flow assurance issues in hydrocarbon reservoirs, asphaltenes are the most complicated one. In fact, the difference in the nature of these molecules with respect to other hydrocarbon components makes this distinction. Asphaltene molecules are the heaviest and the most polar compounds in the crude oils, being insoluble in light n-alkenes and readily soluble in aromatic solvents. Asphaltene is attached to similarly structured molecules, resins, to become stable in the crude oils. Changing the crude oil composition and increasing the light component fractions destabilize asphaltene molecules. For instance, in some field situations, CO2 flooding for the purpose of enhanced oil recovery destabilizes asphaltene. Other potential parameters that promote asphaltene precipitation in the crude oil streams are significant pressure and temperature variation. In fact, in such situations the entrainment of solid particulates in the flowing fluid and deposition on different zones of the flow line yields serious operational challenges and an overall decrease in production efficiency. The loss of productivity leads to a large number of costly remediation work during a well life cycle. In some cases up to $5 Million per year is the estimated cost of removing the blockage plus the production losses during downtimes. Furthermore, some of the oil and gas fields may be left abandoned prematurely, because of the significance of the damage which may cause loss about $100 Million. In this dissertation, we developed a robust wellbore model which is coupled to our in-house developed compositional reservoir model (UTCOMP). The coupled wellbore/reservoir simulator can address flow restrictions in the wellbore as well as the near-wellbore area. This simulator can be a tool not only to diagnose the potential flow assurance problems in the developments of new fields, but also as a tool to study and design an optimum solution for the reservoir development with different types of flow assurance problems. In addition, the predictive capability of this simulator can prescribe a production schedule for the wells that can never survive from flow assurance problems. In our wellbore simulator, different numerical methods such as, semi-implicit, nearly implicit, and fully implicit schemes along with blackoil and Equation-of-State compositional models are considered. The Equation-of-State is used as state relations for updating the properties and the equilibrium calculation among all the phases (oil, gas, wax, asphaltene). To handle the aqueous phase reaction for possible scales formation in the wellbore a geochemical software package (PHREEQC) is coupled to our simulator as well. The governing equations for the wellbore/reservoir model comprise mass conservation of each phase and each component, momentum conservation of liquid, and gas phase, energy conservation of mixture of fluids and fugacity equations between three phases and wax or asphaltene. The governing equations are solved using finite difference discretization methods. Our simulation results show that scale deposition is mostly initiated from the bottom of the wellbore and near-wellbore where it can extend to the upper part of the well, asphaltene deposition can start in the middle of the well and the wax deposition begins in the colder part of the well near the wellhead. In addition, our simulation studies show that asphaltene deposition is significantly affected by CO2 and the location of deposition is changed to the lower part of the well in the presence of CO2. Finally, we applied the developed model for the mechanical remediation and prevention procedures and our simulation results reveal that there is a possibility to reduce the asphaltene deposition in the wellbore by adjusting the well operation condition.

Download or read book Determination of a suitable mud window under HM and THM coupled conditions in real time written by Xuan Luo and published by Cuvillier Verlag. This book was released on 2015-08-18 with total page 158 pages. Available in PDF, EPUB and Kindle. Book excerpt: This study proposes solutions to determine a suitable mud pressure gradient window in real-time considering the HM- and THM-coupled effects. Six boundaries (FG, SFG, PPG, MHSG, RTFG and VSG) were employed to determine the mud pressure windows based on the failure mechanism of borehole wall. Models were developed to calculate the FG, SFG, and RTFG for different rocks under HM- and THM-coupled conditions. Sensitivity analyses were undertaken to categorize the input parameters into three groups, which were “must-have”, “high-sensitive” and “low-sensitive” groups. To carry out a mud pressure window calculation in real-time, the “must-have” and “high-sensitive” parameters should be determined from logging data. The existing and relevant methods and empirical equations for calculating the UCS, IFA and PPG using logging data were analyzed and evaluated. Three methods for computing Biot’s coefficient using logging data were developed. Two methods to estimate the horizontal in-situ stresses were also developed, one method was based on analyzing the breakout shape, and the other based on shear wave splitting. To investigate the thermal effects, a semi-analytical method was developed to simulate the depth-dependent temperature profiles in the annulus, tubing and surrounding rocks. Finally, two case studies were undertaken to verify the whole solutions of a suitable mud pressure window in real-time.

Download or read book Intelligent Systems in Science and Information 2014 written by Kohei Arai and published by Springer. This book was released on 2015-02-13 with total page 412 pages. Available in PDF, EPUB and Kindle. Book excerpt: The book Intelligent Systems in Science and Information 2014 is the carefully edited collection of 25 extended chapters from selected papers in the field of Computational Intelligence that , which received highly recommended feedback during the Science and Information Conference (SAI) 2014 review process. All chapters have gone through substantial extension and consolidation and were subject to another round of rigorous review and additional modification and represent the state of the art of the cutting-edge research and technologies in the related areas.

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 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 Integrated Modeling of Reservoir Fluid Properties and Multiphase Flow in Offshore Production Systems written by Tobias R. Gessner and published by Springer Nature. This book was released on 2023-11-04 with total page 296 pages. Available in PDF, EPUB and Kindle. Book excerpt: The book is intended for practicing engineers in the oil industry, researchers, and graduate students interested in designing and simulating offshore hydrocarbon production systems. It approaches offshore oil production systems from an integrated perspective that combines the modeling of thermophysical properties of reservoir fluids and their flow as a multiphase mixture in wellbores, flow lines, and risers. The first part of the book presents an internally consistent method to compute the critical parameters and acentric factor of Single Carbon Number (SCN) fractions of petroleum mixtures using state-of-the-art multivariate fitting techniques. The procedure is illustrated and validated using flash and differential liberation data from actual field samples. In the second part of the book, mechanistic multiphase flow models are discussed in light of their ability to predict the pressure, temperature, and phase holdup of production fluids in wellbores, flow lines, and risers. Multivariate fitting procedures are again applied to evaluate the sensitivity of the results with respect to closure relationship parameters, such as slug body gas holdup, wall shear stress, and wall roughness in pipelines and production tubing. Finally, the modeling framework is validated using actual field data from offshore production wells.

Download or read book A Comprehensive Statistically Based Method to Interpret Real Time Flowing Measurements written by and published by . This book was released on 2005 with total page pages. Available in PDF, EPUB and Kindle. Book excerpt: This project is motivated by the increasing use of distributed temperature sensors for real-time monitoring of complex wells (horizontal, multilateral and multi-branching wells) to infer the profiles of oil, gas, and water entry. Measured information can be used to interpret flow profiles along the wellbore including junction and build section. In this second project year, we have completed a forward model to predict temperature and pressure profiles in complex wells. As a comprehensive temperature model, we have developed an analytical reservoir flow model which takes into account Joule-Thomson effects in the near well vicinity and multiphase non-isothermal producing wellbore model, and couples those models accounting mass and heat transfer between them. For further inferences such as water coning or gas evaporation, we will need a numerical non-isothermal reservoir simulator, and unlike existing (thermal recovery, geothermal) simulators, it should capture subtle temperature change occurring in a normal production. We will show the results from the analytical coupled model (analytical reservoir solution coupled with numerical multi-segment well model) to infer the anomalous temperature or pressure profiles under various conditions, and the preliminary results from the numerical coupled reservoir model which solves full matrix including wellbore grids. We applied Ramey's model to the build section and used an enthalpy balance to infer the temperature profile at the junction. The multilateral wellbore temperature model was applied to a wide range of cases varying fluid thermal properties, absolute values of temperature and pressure, geothermal gradients, flow rates from each lateral, and the trajectories of each build section.

Download or read book Coupled Modeling of Dynamic Reservoir Well Interactions Under Liquid loading Conditions written by Akkharachai Limpasurat and published by . This book was released on 2014 with total page pages. Available in PDF, EPUB and Kindle. Book excerpt: Liquid loading in a gas well occurs when the upward gas flow rate is insufficient to lift the coproduced liquid to the surface, which results in an accumulation of liquid at the bottom of the well. The liquid column in the tubing creates backpressure on the formation, which decreases the gas production rate and may stop the well from flowing. To model these phenomena, the dynamic interaction between the reservoir and the wellbore must be characterized. Due to wellbore phase re-distribution and potential phase-reinjection into the reservoir, the boundary conditions must be able to handle changing flow direction through the connections between the two subsystems. This study presents a new formulation of the wellbore boundary condition used in reservoir simulators. The boundary condition uses the new state variable, the multiphase zero flow pressure (MPZFP, p0), to determine flow direction in the connection grid block. If the wellbore pressure is less than the p0, the connection is producing; otherwise, it is injecting. The volumetric proportion of the flow is always determined by the upstream side. The new reservoir simulator is used in coupled modeling associated with liquid loading phenomena. The metastable condition can be modeled in a simple manner without any limiting assumptions and numerical stability problems. We also applied this simulator for history matching of a gas well flowing with an intermittent production strategy. A basic transient wellbore model was developed for this purpose. The long-term tubinghead pressure (THP) history can be traced by our coupled simulation. Our modeling examples indicated that, the new wellbore boundary condition is suitable in modeling the dynamic interactions between reservoir and wellbore subsystems during liquid loading. The flow direction through the connection grid block can be automatically detected by our boundary condition without numerical difficulty during the course of the simulation. In addition, the capillary pressure can be accounted at the connection grid blocks when applying our new formulation in the reservoir simulator. The electronic version of this dissertation is accessible from http://hdl.handle.net/1969.1/151699

Download or read book Parallel Simulation of Coupled Flow and Geomechanics in Porous Media written by Bin Wang and published by . This book was released on 2015 with total page 386 pages. Available in PDF, EPUB and Kindle. Book excerpt: In this research we consider developing a reservoir simulator capable of simulating complex coupled poromechanical processes on massively parallel computers. A variety of problems arising from petroleum and environmental engineering inherently necessitate the understanding of interactions between fluid flow and solid mechanics. Examples in petroleum engineering include reservoir compaction, wellbore collapse, sand production, and hydraulic fracturing. In environmental engineering, surface subsidence, carbon sequestration, and waste disposal are also coupled poromechanical processes. These economically and environmentally important problems motivate the active pursuit of robust, efficient, and accurate simulation tools for coupled poromechanical problems. Three coupling approaches are currently employed in the reservoir simulation community to solve the poromechanics system, namely, the fully implicit coupling (FIM), the explicit coupling, and the iterative coupling. The choice of the coupling scheme significantly affects the efficiency of the simulator and the accuracy of the solution. We adopt the fixed-stress iterative coupling scheme to solve the coupled system due to its advantages over the other two. Unlike the explicit coupling, the fixed-stress split has been theoretically proven to converge to the FIM for linear poroelasticity model. In addition, it is more efficient and easier to implement than the FIM. Our computational results indicate that this approach is also valid for multiphase flow. We discretize the quasi-static linear elasticity model for geomechanics in space using the continuous Galerkin (CG) finite element method (FEM) on general hexahedral grids. Fluid flow models are discretized by locally mass conservative schemes, specifically, the mixed finite element method (MFE) for the equation of state compositional flow on Cartesian grids and the multipoint flux mixed finite element method (MFMFE) for the single phase and two-phase flows on general hexahedral grids. While both the MFE and the MFMFE generate cell-centered stencils for pressure, the MFMFE has advantages in handling full tensor permeabilities and general geometry and boundary conditions. The MFMFE also obtains accurate fluxes at cell interfaces. These characteristics enable the simulation of more practical problems. For many reservoir simulation applications, for instance, the carbon sequestration simulation, we need to account for thermal effects on the compositional flow phase behavior and the solid structure stress evolution. We explicitly couple the poromechanics equations to a simplified energy conservation equation. A time-split scheme is used to solve heat convection and conduction successively. For the convection equation, a higher order Godunov method is employed to capture the sharp temperature front; for the conduction equation, the MFE is utilized. Simulations of coupled poromechanical or thermoporomechanical processes in field scales with high resolution usually require parallel computing capabilities. The flow models, the geomechanics model, and the thermodynamics model are modularized in the Integrated Parallel Accurate Reservoir Simulator (IPARS) which has been developed at the Center for Subsurface Modeling at the University of Texas at Austin. The IPARS framework handles structured (logically rectangular) grids and was originally designed for element-based data communication, such as the pressure data in the flow models. To parallelize the node-based geomechanics model, we enhance the capabilities of the IPARS framework for node-based data communication. Because the geomechanics linear system is more costly to solve than those of flow and thermodynamics models, the performance of linear solvers for the geomechanics model largely dictates the speed and scalability of the coupled simulator. We use the generalized minimal residual (GMRES) solver with the BoomerAMG preconditioner from the hypre library and the geometric multigrid (GMG) solver from the UG4 software toolbox to solve the geomechanics linear system. Additionally, the multilevel k-way mesh partitioning algorithm from METIS is used to generate high quality mesh partitioning to improve solver performance. Numerical examples of coupled poromechanics and thermoporomechanics simulations are presented to show the capabilities of the coupled simulator in solving practical problems accurately and efficiently. These examples include a real carbon sequestration field case with stress-dependent permeability, a synthetic thermoporoelastic reservoir simulation, poroelasticity simulations on highly distorted hexahedral grids, and parallel scalability tests on a massively parallel computer.

Download or read book Iteratively Coupled Reservoir Simulation for Multiphase Flow in Porous Media written by Bo Lu and published by . This book was released on 2008 with total page 296 pages. Available in PDF, EPUB and Kindle. Book excerpt: Fully implicit and IMPES are two primary reservoir simulation schemes that are currently used widely. However, neither of them is sufficiently accurate or efficient, given the increasing size and degree of complexity of highly heterogeneous reservoirs. In this dissertation, an iterative coupling approach is proposed and developed to solve multiphase flow problems targeting the efficient, robust and accurate simulation of the hydrocarbon recovery process. In the iterative coupling approach, the pressure equation is solved implicitly, followed by the saturation equation, which is solved semi-implicitly. These two stages are iteratively coupled at the end of each time step by evaluating material balance, both locally and globally, to check the convergence of each iteration. Additional iterations are conducted, if necessary; otherwise the simulation proceeds to the next time step. Several numerical techniques are incorporated to speed up the program convergence and cut down the number of iterations per time step, thus greatly improving iterative model performance. The iterative air-water model, the oil-water model, and the black oil model are all developed in this work. Several numerical examples have been tested using the iterative approach, the fully implicit method, and the IMPES method. Results show that with the iterative method, about 20%-40% of simulation time is saved when compared to the fully implicit method with similar accuracy. As compared to the IMPES method, the iterative method shows better stability, allowing larger time steps in simulation. The iterative method also produces better mass balance than IMPES over the same time. The iterative method is developed for parallel implementation, and several test cases have been run on parallel clusters with large numbers of processors. Good parallel scalability enables the iterative method to solve large problems with millions of elements and highly heterogeneous reservoir properties. Linear solvers take the greatest portion of CPU time in reservoir simulations. This dissertation investigates advanced linear solvers for high performance computers (HPC) for reservoir simulation. Their performance is compared and discussed.

Download or read book Modeling of Multiphase Flow in the Near wellbore Region of the Reservoir Under Transient Conditions written by He Zhang and published by . This book was released on 2010 with total page pages. Available in PDF, EPUB and Kindle. Book excerpt: In oil and gas field operations, the dynamic interactions between reservoir and wellbore cannot be ignored, especially during transient flow in the near-wellbore region. As gas hydrocarbons are produced from underground reservoirs to the surface, liquids can come from condensate dropout, water break-through from the reservoir, or vapor condensation in the wellbore. In all three cases, the higher density liquid needs to be transported to the surface by the gas. If the gas phase does not provide sufficient energy to lift the liquid out of the well, the liquid will accumulate in the wellbore. The accumulation of liquid will impose an additional backpressure on the formation that can significantly affect the productivity of the well. The additional backpressure appears to result in a "U-shaped" pressure distribution along the radius in the near-wellbore region that explains the physics of the backflow scenario. However, current modeling approaches cannot capture this U-shaped pressure distribution, and the conventional pressure profile cannot explain the physics of the reinjection. In particular, current steady-state models to predict the arrival of liquid loading, diagnose its impact on production, and screen remedial options are inadequate, including Turner's criterion and Nodal Analysis. However, the dynamic interactions between the reservoir and the wellbore present a fully transient scenario, therefore none of the above solutions captures the complexity of flow transients associated with liquid loading in gas wells. The most satisfactory solution would be to couple a transient reservoir model to a transient well model, which will provide reliable predictive models to link the well dynamics with the intermittent response of a reservoir that is typical of liquid loading in gas wells. The modeling work presented here can be applied to investigate liquid loading mechanisms, and evaluate any other situation where the transient flow behavior of the near-wellbore region of the reservoir cannot be ignored, including system start-up and shut-down.

Download or read book T2Well written by and published by . This book was released on 2011 with total page pages. Available in PDF, EPUB and Kindle. Book excerpt: