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 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 750 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 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 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 570 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 Integration of Numerical and Machine Learning Protocols for Coupled Reservoir wellbore Models written by Venkataramana Putcha and published by . This book was released on 2017 with total page pages. Available in PDF, EPUB and Kindle. Book excerpt: As the reservoir pressure declines with time, many of the wells do not have adequate bottom-hole pressure to carry the fluids to the surface. Under such circumstances, artificial lift mechanisms must be employed. Amongst various artificial lift mechanisms, a significant proportion of wells utilize the gas-lift mechanism, which is an extension of the natural flow. In gas-lift implementation, high pressure gas is injected into the wellbore through a valve, where injected gas supports production by altering the composition and reducing the density, and increasing the velocity of the produced fluids. In order to design a gas-lift system, a study of the inflow performance of the fluid from the reservoir into the wellbore, combined with the outflow performance of the fluids from the bottom of the wellbore to the surface is necessary. For this purpose, existing technologies for optimization of gas-lift systems predominantly use empirical correlations in order to reduce the computational overhead. These systems use a single-equation based inflow performance relations and black-oil outflow performance correlations that have restricted applicability in systems where the fluid composition varies spatially and temporally. The contemporary protocols consider the oil flow rate, water cut and formation gas-liquid ratio and well productivity index at a given instant of time to calculate the optimal quantity of gas lift injection. Due to this methodology, the effects of pressure decline and subsequent variations in well performance are not adequately captured. This results in a solution which determines the maximum liquid flow rate expected for a given gas lift injection rate only for the instantaneous period at which the study has been performed. This optimal gas lift injection rate may or may not provide the maximum total output of oil over the producing life of the well. As a first step, a compositional coupled numerical reservoir and wellbore hydraulics models has been developed as a part of this work. These hard-computing tools simulate the variations in composition, pressure and production profiles of a gas lift well and its associated reservoir from inception to abandonment. One more advantage of this method is that it can predict the future performance of a well with or without the details of well production history. This capability can be useful when gas lift is introduced in a well immediately after its completion post a drilling or a work-over job. Soft computing tools have gained popularity in the petroleum industry due to their speed, simplicity, wide range of applicability, capacity to identify patterns and ability to provide inverse solutions. The fully numerical coupled reservoir-wellbore simulator developed is computationally expensive. In order to develop a faster system, firstly, an ANN based wellbore hydraulics tool is developed and coupled with the numerical reservoir simulator. The data utilized for training the ANN tool was generated using the numerical wellbore hydraulics tool. Both the numerical and ANN wellbore hydraulics models were validated against cases from the field and another compositional numerical model from the literature. The average relative deviation with respect to field data was observed to be 2.2% and 2.4% respectively for the ANN and numerical wellbore hydraulics model, respectively. When compared against another compositional numerical model, the average relative deviation for the ANN based model was observed to be between 3.3% and 7.1%, while it was between 2.3% and 8.1% for the numerical model developed in this work. While the ANN based wellbore hydraulics model maintained the accuracy of the numerical model, it outperformed its counterpart the numerical model, by four orders of magnitude in terms of speed-up. The ANN based wellbore model was also coupled with the numerical reservoir simulator. This resultant model which involves a coupled numerical-ANN system is faster than the fully numerical coupled system by about 160 times. This coupled tool was used to generate a gas lift database of cumulative oil production of a well with various reservoir and wellbore operating conditions under a range of operating gas lift injection depths and flow rates. This database was used to develop an ANN based gas lift model that is capable of generating performance curves plotting total oil produced during the producing life of a well as a function of gas lift injection rate. Blind testing of the ANN gas lift model showed an average absolute error of 16.6 % with respect to the predictions of the coupled numerical-ANN reservoir wellbore model. This fully ANN based gas lift model provided a speed-up by four orders of magnitude with respect to the coupled numerical-ANN based model. Hence, a fast, robust and versatile model has been developed for maximizing total primary oil recovery using gas lift optimization through integration of numerical and neuro-simulation.

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 Development and Application of a Compositional Wellbore Simulator for Modeling Flow Assurance Issues and Optimization of Field Production written by Ali Abouie and published by . This book was released on 2015 with total page 296 pages. Available in PDF, EPUB and Kindle. Book excerpt: Flow assurance is crucial in the oil industry since it guarantees the success and economic production of hydrocarbon fluid, especially in offshore and deep water oil fields. In fact, the ultimate goal of flow assurance is to maintain flow in the wellbore and pipelines as long as possible. One of the most common challenges in flow assurance is the buildup of solids, such as asphaltene and scale particles. These Solid particles can deposit in the wellbore, flowline, and riser and affect the wellbore performance by reducing the cross section of the pipeline, which eventually results in pipeline blockage. Hence, neglecting the importance of flow assurance problems and failure in thorough understanding of the fluid behavior in the production systems may result in plugged pipeline, production loss, flowline replacement, and early abandonments of the well. As a result, continuous evaluations are needed at the development stage and during the life of reservoirs to predict the potential, the extent, and the severity of the problem to plan for inhibition and remediation jobs. In fact, it is more preferable to prevent flow assurance problems through the designing and operating procedures rather than remediating the problems, which has higher risks of success and higher loss of revenue due to frequent well shut down. As a part of this research, we enhanced the capabilities of our in-house compositional wellbore simulator (UTWELL) to model various production and flow assurance scenarios. Initially, we developed and implemented a robust gas lift model into UTWELL to model artificial lift technique for reservoirs with low pressure. The developed model is able to model both steady state and transient flow along with blackoil and Equation-of-State compositional models. The improved version was successfully validated against a commercial simulator. Then, we applied our dynamic model to track the behavior of asphaltene during gas lift processes and evaluated the risk of asphaltene deposition. Several deposition mechanisms were incorporated to study the transportation, entrainment, and deposition of solid particles in the wellbore. The simulation results illustrated the effect of light gas injection on asphaltene deposition and well performance. Finally, a step by step algorithm is presented for coupling a geochemical package, IPhreeqc, with UTWELL. The developed model is able to model homogenous and heterogeneous, non-isothermal, non-isobaric aqueous phase reactions assuming local equilibrium or kinetic conditions. This tool was then utilized to model scale deposition in the wellbore for various scenarios. In addition, the results showed that integrating IPhreeqc has promise in terms of CPU time compared to the traditional approach of reading and writing the input and output files.

Download or read book A Coupled Geomechanics and Reservoir Simulator and Its Application to Reservoir Development Strategies written by Chao Gao (Ph. D.) and published by . This book was released on 2019 with total page 0 pages. Available in PDF, EPUB and Kindle. Book excerpt: A new Coupled Geomechanics and Reservoir Simulator, CGRS, and a wellbore stability model, WSM, are utilized to provide dynamic infill drilling strategies - where to drill, when to drill and how to drill - that greatly improve upon the traditional constant stress path method. The stress path, defined as the ratio of the change of far-field horizontal stress to change of pore pressure, has a profound influence on wellbore stability while drilling in a depleted reservoir. Based on the common assumptions of uniaxial strain and homogenous depletion, the traditional analytical stress path solution is a function of Biot's coefficient and Poisson's ratio. Pore pressure depletion, however, is location and time dependent, not homogeneous. Thus, the objective of this study is to analyze the wellbore stability of infill wells with a coupled geomechanics and reservoir simulator. Two wellbore stability models, first a conventional wellbore stability model (CWSM) and second a Coupled Geomechanics and Reservoir Simulator Wellbore Stability Model (CGRS-WSM), were developed. For CWSM, the analytical stress path solution is applied to get updated far-field horizontal stresses. CGRS-WSM, however, does not require changes in far-field horizontal stress with pressure depletion. Rather, CGRS gives the stress field of the whole reservoir, and those stress components at a specific point in Cartesian coordinates are used directly in CGRS-WSM to calculate the mud weight window. For CGRS, an in-house coupled geomechanics and reservoir simulator is developed that considers lateral displacements and inhomogeneous depletion of the reservoir. In addition, an Abaqus model is also developed to analyze the influence of plasticity and stress arching on pore pressure and stress change during depletion, which are used in CGRS-WSM to investigate wellbore stability. Different shear failure criteria are utilized in a new CGRS wellbore stability model. The upper bounds of shear failure are given by Drucker-Prager Inscribes and Griffith Theory, while the lower bound is given by Drucker-Prager Circumscribe. Several case studies for drilling in a depleted reservoir compare CWSM with CGRS-WSM. There is a significant difference in the two maximum mud weights, with operational consequences, for example, as related to potential lost circulation problems. For some examples, the narrower mud weight from CGRS-WSM, as compared to CWSM, is a more realistic unsafe region warning. CGRS-WSM can quantify the influence of azimuth on the minimum and the maximum mud weight during the depletion when initial maximum horizontal stress equals minimum horizontal stress. In addition, CGRS-WSM can give the output of a location-dependent mud weight map for the entire reservoir. Neither of the above two functions can be realized by a conventional wellbore stability model. The CGRS-WSM in this work is a significant step in drilling infill wells in depleted zones, owing to its ability to quantify horizontal displacements, inhomogeneous depletion, plasticity, and stress arching, which cannot be done with the traditional analytical stress path procedure. Moreover, the connection of a coupled geomechanics and reservoir simulator with a wellbore stability simulator provides dynamic information useful to quantify where to drill, when to drill and how to drill. This new model can be used to investigate 'what if' scenarios, parameter sensitivity studies, case study reviews, and previously drilled well critiques

Download or read book Reservoir Wellbore Coupled Simulation of Liquid Loaded Gas Well Performance written by Muhammad Feldy Riza and published by . This book was released on 2014 with total page pages. Available in PDF, EPUB and Kindle. Book excerpt: Liquid loading of gas wells causes production difficulty and reduces ultimate recovery from these wells. In 1969, Turner proposed that existence of annular two-phase flow at the wellhead is necessary for the well to avoid liquid loading. In this work we applied Turner's approach to the entire wellbore. Analysis of available data from literature showed that transition from annular flow occurs much earlier at well bottom than at the wellhead. This entire wellbore approach proved to be more accurate in predicting onset of liquid loading. In addition, we developed a simple pseudo-steady-state reservoir flow model that was seamlessly connected to a wellbore two-phase flow model. The model is capable of predicting the time a gas well will produce without getting loaded with liquid and the length of time it can produce since loading inception if no intervention is carried out. We were able to develop a normalized time function applicable many reservoirs that would be indicative of loading-free productive life of a gas well. The electronic version of this dissertation is accessible from http://hdl.handle.net/1969.1/151637

Download or read book Development and Application of a Coupled Geomechanics Model for a Parallel Compositional Reservoir Simulator written by Feng Pan (Ph. D.) and published by . This book was released on 2009 with total page 652 pages. Available in PDF, EPUB and Kindle. Book excerpt: For a stress-sensitive or stress-dependent reservoir, the interactions between its seepage field and in situ stress field are complex and affect hydrocarbon recovery. A coupled geomechanics and fluid-flow model can capture these relations between the fluid and solid, thereby presenting more precise history matchings and predictions for better well planning and reservoir management decisions. A traditional reservoir simulator cannot adequately or fully represent the ongoing coupled fluid-solid interactions during the production because of using the simplified update-formulation for porosity and the static absolute permeability during simulations. Many researchers have studied multiphase fluid-flow models coupled with geomechanics models during the past fifteen years. The purpose of this research is to develop a coupled geomechanics and compositional model and apply it to problems in the oil recovery processes. An equation of state compositional simulator called the General Purpose Adaptive Simulator (GPAS) is developed at The University of Texas at Austin and uses finite difference / finite control volume methods for the solution of its governing partial differential equations (PDEs). GPAS was coupled with a geomechanics model developed in this research, which uses a finite element method for discretization of the associated PDEs. Both the iteratively coupled solution procedure and the fully coupled solution procedure were implemented to couple the geomechanics and reservoir simulation modules in this work. Parallelization, testing, and verification for the coupled model were performed on parallel clusters of high-performance workstations. MPI was used for the data exchange in the iteratively coupled procedure. Different constitutive models were coded into GPAS to describe complicated behaviors of linear or nonlinear deformation in the geomechanics model. In addition, the geomechanics module was coupled with the dual porosity model in GPAS to simulate naturally fractured reservoirs. The developed coupled reservoir and geomechanics simulator was verified using analytical solutions. Various reservoir simulation case studies were carried out using the coupled geomechanics and GPAS modules.

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 and Application of a Coupled Geomechanics Model for a Parallel Compositional Reservoir Simulator written by Feng Pan and published by . This book was released on 2009 with total page 652 pages. Available in PDF, EPUB and Kindle. Book excerpt: For a stress-sensitive or stress-dependent reservoir, the interactions between its seepage field and in situ stress field are complex and affect hydrocarbon recovery. A coupled geomechanics and fluid-flow model can capture these relations between the fluid and solid, thereby presenting more precise history matchings and predictions for better well planning and reservoir management decisions. A traditional reservoir simulator cannot adequately or fully represent the ongoing coupled fluid-solid interactions during the production because of using the simplified update-formulation for porosity and the static absolute permeability during simulations. Many researchers have studied multiphase fluid-flow models coupled with geomechanics models during the past fifteen years. The purpose of this research is to develop a coupled geomechanics and compositional model and apply it to problems in the oil recovery processes. An equation of state compositional simulator called the General Purpose Adaptive Simulator (GPAS) is developed at The University of Texas at Austin and uses finite difference / finite control volume methods for the solution of its governing partial differential equations (PDEs). GPAS was coupled with a geomechanics model developed in this research, which uses a finite element method for discretization of the associated PDEs. Both the iteratively coupled solution procedure and the fully coupled solution procedure were implemented to couple the geomechanics and reservoir simulation modules in this work. Parallelization, testing, and verification for the coupled model were performed on parallel clusters of high-performance workstations. MPI was used for the data exchange in the iteratively coupled procedure. Different constitutive models were coded into GPAS to describe complicated behaviors of linear or nonlinear deformation in the geomechanics model. In addition, the geomechanics module was coupled with the dual porosity model in GPAS to simulate naturally fractured reservoirs. The developed coupled reservoir and geomechanics simulator was verified using analytical solutions. Various reservoir simulation case studies were carried out using the coupled geomechanics and GPAS modules.

Download or read book Horizontal Well and Near well Region Simulation Using Coupled Axial radial Productivity Models written by Jie Cao and published by . This book was released on 2017 with total page pages. Available in PDF, EPUB and Kindle. Book excerpt: Directional drilling technologies have dramatically increased the application of advanced wells in reservoir development since the 1990s, including horizontal, deviated, multilateral and smart wells. The great demand for highly accurate and efficient well models arrives from the fact that drilling technology has outpaced simulation techniques. The well model, usually coupled with the reservoir model, is crucial for productivity estimation and prediction. The main objectives of this research are to develop a well/near-well model and associated simulation techniques using coupled axial-radial productivity models for advanced wells. The analytical coupled axial-radial flow models were recently developed and described in research notes. These ideas originate from the observation that the axial reservoir pressure gradient cannot be ignored since pressure gradients exist in horizontal wellbores. The analytical models consider both axial reservoir flow and radial well inflow in the near-well reservoir, physically representing a two dimensional problem. These models were solved under both steady state and semi-steady state conditions, using external boundary pressure and average reservoir/grid block pressure, thereby generating the coupled axial-radial productivity (CARP) models. The main focus in this work is to apply the CARP models in the construction of a numerical scheme for horizontal well and near-well region simulation (i.e. the well/near-well model), in which wellbore hydraulics are included. In steady state and semi steady state flow, the pressure solutions are analytical in each grid block and result in curved surfaces of near-well reservoir pressure, contrary to the constant pressure distribution used in the finite difference method. Hence, the new numerical scheme is demonstrated, and proved in the steady state case, to be a higher order method than the standard finite difference method. The simulation results show that the new method requires less grid block refinement to achieve the same accuracy compared to the finite difference method. The CPU time needed for the same grid blocks to achieve the same accuracy is greatly reduced using the new method compared to the finite difference method. This reduces the need for grid block refinement in the near-well region. Furthermore, the numerical well/near-well models are applied in heterogeneous reservoirs and special cases where cross flow occurs. Wide permeability ranges can be dealt with in these models in a stable manner without special treatment. Both the axial and radial flow directions are solved as unknowns in these models; hence the cross flow between the well and the near-well reservoir can be represented. Besides, the new well/near-well model can be coupled with standard finite difference reservoir simulators such that both the well completion effects and remote reservoir effects are taken into consideration. An iterative coupling scheme is used in this research, and calculated examples considering unevenly distributed skin factors also demonstrate the application of the new well/near-well model and the stability of the coupling scheme. The well/near-well model is also developed for anisotropic reservoirs using average reservoir pressure. Based on previous research notes, this is achieved through a permeability tensor used for axial reservoir flow and well inflow equations. This permeability tensor is generated using a unique transformation that converts the anisotropic media into a virtually equivalent isotropic media in the axial and radial directions. This transformation is only applied in the near-well region without changing boundary conditions, and it preserves volume, flow rates and pressure. The cylindrical near-well region is transformed into elliptical cylinders; consequently, Dietz shape factors for ellipses are used in productivity models.

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 Development and Application of a 3D Equation of state Compositional Fluid flow Simulator in Cylindrical Coordinates for Near wellbore Phenomena written by Rohollah Abdollah Pour and published by . This book was released on 2011 with total page 476 pages. Available in PDF, EPUB and Kindle. Book excerpt: Well logs and formation testers are routinely used for detection and quantification of hydrocarbon reserves. Overbalanced drilling causes invasion of mud filtrate into permeable rocks, hence radial displacement of in-situ saturating fluids away from the wellbore. The spatial distribution of fluids in the near-wellbore region remains affected by a multitude of petrophysical and fluid factors originating from the process of mud-filtrate invasion. Consequently, depending on the type of drilling mud (e.g. water- and oil-base muds) and the influence of mud filtrate, well logs and formation-tester measurements are sensitive to a combination of in-situ (original) fluids and mud filtrate in addition to petrophysical properties of the invaded formations. This behavior can often impair the reliable assessment of hydrocarbon saturation and formation storage/mobility. The effect of mud-filtrate invasion on well logs and formation-tester measurements acquired in vertical wells has been extensively documented in the past. Much work is still needed to understand and quantify the influence of mud-filtrate invasion on well logs acquired in horizontal and deviated wells, where the spatial distribution of fluids in the near-wellbore region is not axial-symmetric in general, and can be appreciably affected by gravity segregation, permeability anisotropy, capillary pressure, and flow barriers. This dissertation develops a general algorithm to simulate the process of mud-filtrate invasion in vertical and deviated wells for drilling conditions that involve water- and oil-base mud. The algorithm is formulated in cylindrical coordinates to take advantage of the geometrical embedding imposed by the wellbore in the spatial distribution of fluids within invaded formations. In addition, the algorithm reproduces the formation of mudcake due to invasion in permeable formations and allows the simulation of pressure and fractional flow-rate measurements acquired with dual-packer and point-probe formation testers after the onset of invasion. An equation-of-state (EOS) formulation is invoked to simulate invasion with both water- and oil-base muds into rock formations saturated with water, oil, gas, or stable combinations of the three fluids. The algorithm also allows the simulation of physical dispersion, fluid miscibility, and wettability alteration. Discretized fluid flow equations are solved with an implicit pressure and explicit concentration (IMPEC) scheme. Thermodynamic equilibrium and mass balance, together with volume constraint equations govern the time-space evolution of molar and fluid-phase concentrations. Calculations of pressure-volume-temperature (PVT) properties of the hydrocarbon phase are performed with Peng-Robinson's equation of state. A full-tensor permeability formulation is implemented with mass balance equations to accurately model fluid flow behavior in horizontal and deviated wells. The simulator is rigorously and successfully verified with both analytical solutions and commercial simulators. Numerical simulations performed over a wide range of fluid and petrophysical conditions confirm the strong influence that well deviation angle can have on the spatial distribution of fluid saturation resulting from invasion, especially in the vicinity of flow barriers. Analysis on the effect of physical dispersion on the radial distribution of salt concentration shows that electrical resistivity logs could be greatly affected by salt dispersivity when the invading fluid has lower salinity than in-situ water. The effect of emulsifiers and oil-wetting agents present in oil-base mud was studied to quantify wettability alteration and changes in residual water saturation. It was found that wettability alteration releases a fraction of otherwise irreducible water during invasion and this causes electrical resistivity logs to exhibit an abnormal trend from shallow- to deep-sensing apparent resistivity. Simulation of formation-tester measurements acquired in deviated wells indicates that (i) invasion increases the pressure drop during both drawdown and buildup regimes, (ii) bed-boundary effects increase as the wellbore deviation angle increases, and (iii) a probe facing upward around the perimeter of the wellbore achieves the fastest fluid clean-up when the density of invading fluid is larger than that of in-situ fluid.

Download or read book The Control Theory and Application for Well Pattern Optimization of Heterogeneous Sandstone Reservoirs written by Dehua Liu and published by Springer. This book was released on 2017-03-15 with total page 394 pages. Available in PDF, EPUB and Kindle. Book excerpt: The book is focused primarily on characteristics and determinative methods of reservoir orientation, the concept of vector well pattern and corresponding realistic techniques of well pattern deployment, well pattern control principles, Optimum design of well pattern based on the reservoir direction characteristics, and the schemes of well spacing density regulation at different stages of development. The procedures for improving water flooding efficiency have been provided. This book is suitable for reservoir engineering managers, reservoir engineers, and students of petroleum engineering.

Download or read book Horizontal Well Simulation with Local Grid Refinement written by Liyan Zhao and published by . This book was released on 1994 with total page 370 pages. Available in PDF, EPUB and Kindle. Book excerpt: