Reservoir-Wellbore Coupled Simulation of Liquid Loaded Gas Well Performance PDF Download
Are you looking for read ebook online? Search for your book and save it on your Kindle device, PC, phones or tablets. Download Reservoir-Wellbore Coupled Simulation of Liquid Loaded Gas Well Performance PDF full book. Access full book title Reservoir-Wellbore Coupled Simulation of Liquid Loaded Gas Well Performance by Muhammad Feldy Riza. Download full books in PDF and EPUB format.
Author: Muhammad Feldy Riza
Publisher:
ISBN:
Category :
Languages : en
Pages :
Get Book Here
Book Description
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
Author: Muhammad Feldy Riza
Publisher:
ISBN:
Category :
Languages : en
Pages :
Get Book Here
Book Description
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
Author: Akkharachai Limpasurat
Publisher:
ISBN:
Category :
Languages : en
Pages :
Get Book Here
Book Description
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
Author: Venkataramana Putcha
Publisher:
ISBN:
Category :
Languages : en
Pages :
Get Book Here
Book Description
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.
Author: Mahdy Shirdel
Publisher:
ISBN:
Category :
Languages : en
Pages : 402
Get Book Here
Book Description
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.
Author: Peyman Pourafshary
Publisher:
ISBN:
Category : Gas wells
Languages : en
Pages : 0
Get Book Here
Book Description
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.
Author: John R. Fanchi
Publisher: Gulf Professional Publishing
ISBN: 0128155647
Category : Technology & Engineering
Languages : en
Pages : 374
Get Book Here
Book Description
Reservoir engineers today need to acquire more complex reservoir management and modeling skills. Principles of Applied Reservoir Simulation, Fourth Edition, continues to provide the fundamentals on these topics for both early and seasoned career engineers and researchers. Enhanced with more practicality and with a focus on more modern reservoir simulation workflows, this vital reference includes applications to not only traditional oil and gas reservoir problems but specialized applications in geomechanics, coal gas modelling, and unconventional resources. Strengthened with complementary software from the author to immediately apply to the engineer's projects, Principles of Applied Reservoir Simulation, Fourth Edition, delivers knowledge critical for today's basic and advanced reservoir and asset management. - Gives hands-on experience in working with reservoir simulators and links them to other petroleum engineering activities - Teaches on more specific reservoir simulation issues such as run control, tornado plot, linear displacement, fracture and cleat systems, and modern modelling workflows - Updates on more advanced simulation practices like EOR, petrophysics, geomechanics, and unconventional reservoirs
Author: Sabastine Anibueze
Publisher:
ISBN:
Category :
Languages : en
Pages : 0
Get Book Here
Book Description
Author: Brandon G. Thomas
Publisher:
ISBN:
Category : Oil reservoir engineering
Languages : en
Pages : 296
Get Book Here
Book Description
Author: Paulo Waltrich
Publisher:
ISBN:
Category :
Languages : en
Pages :
Get Book Here
Book Description
Liquid loading in gas wells is generally described as the inability of the well to lift the co-produced liquids up the tubing, which may ultimately kill the well. There is a lack of dedicated models that can mimic the transient features that are typical of liquid loading. Improved characterization of liquid loading in gas wells and enhanced prediction of future well performance can be achieved from the measurements and analyses resulting from this project. An experimental investigation was carried out to study the onset of liquid loading and the subsequent transient phenomena, using a large scale flow loop to visualize two-phase flow regimes, and to measure pressure and liquid holdup along a 42-m long vertical tube. From this investigation, it is possible to conclude that liquid loading should not be characterized based on onset criteria alone, and that it may not be a wellbore-only problem, as it would seem that the reservoir also plays a key role in determining if/when/how liquid loading manifests itself. Additionally, the results from the experimental campaign were used to compare the performance of different wellbore flow simulators. State-of-the-art simulators do not seem to fully capture the nature of liquid loading in vertical tubes. A simplified model is roposed here to evaluate the liquid transport during the transition from one flow regime to another, during the loading sequence.
Author: Michael Golan
Publisher:
ISBN:
Category : Technology & Engineering
Languages : en
Pages : 696
Get Book Here
Book Description
Explores the engineering operations and tasks involved with analyzing the production behaviour of oil and gas wells. The book discusses the effect of well size, reservoir data and operating conditions on the production site.
