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Abstract In a finite difference scheme, continuous multi-phase flow variables that appear in conservation equations such as saturation are spacially discretized on grid blocks. When coarse grid blocks are used for reservoir simulation, the numerical solution tends to magnify the discretization error. This causes numerical errors called as coarse grid effect. Through a coarse grid reservoir simulation, injection pressure showed quite difference with that of fine grid model. This is because total mobility at the injection well is defined by the finite difference based average saturation in the injection well grid block. In other words, the saturation gradient that would appear in the near-well region is ignored in such coarse-grid system. In this study, the areal average saturation in the injection well grid block was calculated analytically by the newly derived radial displacement approximation which was extende from the Buckley-Leverett linear displacement problem, taking account of pressure difference between the injection well and the injection well grid block. Consequently, the corrected total mobility was provided, by defining new value of total well index and transmissibility. The injection pressure computed by this technique with for coarse grid model is reasonably agreed with the numerical solution of fine grid model. The practical application of the developed well-pseudo is validated through an actual reservoir simulation study. Introduction The upscaling is one of the reservoir simulation techniques to reduce the number of cells in a geological model to the appropriate level for a flow simulation. The upscaling process defines a coarse grid system where each coarse grid block contains several fine grid blocks and assigns effective flow properties to each coarse grid block accounting for the flow fields simulated in a fine grid model. In near-well region, since pressure shows drastic change in radial direction, the upscaling approach for linear pressure region cannot be applied. Therefore, another approach i.e. well-pseudo which accounts for such pressure change in the near-well region is required. Historically, well-pseudo was firstly introduced to describe coning problems. In literatures, only several papers treat upscaling in the near well region. Durlofsky et al. showed an approach to calculate transmissibility and well index for single-phase flow. This method is based on the solution of local well-driven flow problems subject to generic boundary conditions. Simulation results with their method indicates improved predictions compared to those obtained by conventional techniques. However they did not take frontal advance into consideration. We developed a new well-pseudo to account for flow fields representing the near-well regions and frontal advance. A new analytical well-pseudo, it is derived by discretizing a continuous solution to Buckley-Leverett type radial displacement. The approach is an extension of Hewett et al. which analytically calculate pseudofunctions required for discretization on a coarse grid. In this paper, first, we describe the detail of the new well-pseudo. Secondly, several characteristics of coarse grid effects are revealed through calculations of well-pseudos with changing reference relative permeabilities. Finally, the practical approach of the developed well-pseudo is validated through the application to an actual reservoir model. Derivation of Analytical Well-pseudo In this section, continuous analytical solutions for single-phase and two-phase flow problems were described. Assumptions were given in radial flow system of incompressible fluid where no gravity and no capillary forces were considered. Single-Phase Property Under a single-phase radial steady-state flow condition, the pressure distribution around an injector is given by the following equation.
- Asia (0.47)
- North America > United States (0.46)
- Reservoir Description and Dynamics > Reservoir Simulation > Scaling methods (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Slug Tracking in Pipelines: Part I - Experiments and Analysis
Yoshida, Y. (Japan National Oil Corporation / Technology Research Center) | Sharma, Y. (Japan National Oil Corporation / Technology Research Center) | Miyata, K. (Japan National Oil Corporation / Technology Research Center) | Manabe, R. (Japan National Oil Corporation / Technology Research Center) | Ikeda, K. (Japan National Oil Corporation / Technology Research Center) | Takahashi, S. (Japan National Oil Corporation / Technology Research Center) | Ihara, M. (Japan National Oil Corporation / Technology Research Center)
Abstract A large-scale multiphase flow experimental facility is used to study slug tracking behavior in pipelines. The description of the flow loop, testing procedure, analyses of data, and development of closure terms for a slug tracking model are the focus of this paper. Pressure, temperature, and liquid holdup were collected for 286 tests. Each test was characterized by a superficial liquid velocity, superficial gas velocity, length of pipeline, diameter of pipeline, and length and angle of the inclined sections of the pipeline in a hilly terrain configuration. Data collected in flow tests were analyzed to yield;slug translational velocity, liquid holdup in slug and film, and slug length distribution. Correlations were derived for the slug translational velocity in the inclined sections. These correlations have been compared with an existing relation. It is the intent to use the correlations in a slug tracking model under development and validate the numerical simulator with the processed data. Introduction The slug structure is a common and complex flow pattern which occurs in a pipeline transporting a multiphase mixture. It consists of a region of liquid with entrained gases, referred to as the liquid slug body, a gas bubble or pocket, and a liquid film. Figure 1 shows a slug flow in a horizontal pipe. The case of slug flow in a vertical pipe is shown in Figure 2. An example of the flow situation in the case of a hilly terrain pipeline is illustrated in Figure 3. In the multiphase pipelines, slugs can be further differentiated according to the mode of formation. The slug flow structure may be initiated by flow instabilities, such as the Kelvin-Helmholtz instability. These are termed hydrodynamic slugs. In other cases, the geometry of the pipeline plays an important role in the slug formation. An example of this is a pipeline-riser pipe system. At low fluid flow rates, there is blockage at the base of the riser leading to an intermittent flow behavior termed severe slugging. Slugs formed as a result of the geometry are commonly referred to as terrain induced slugs. An initiated slug can grow or decay as it moves along a pipeline due to expansion, wake, and terrain induced effects. Slug tracking is the process whereby the development of the slug is traced from the initiation point to the point of decay or to the exit of the pipeline. An understanding and knowledge of the slug flow characteristics are necessary to permit,a design of downstream process equipment such as slug catchers and separators, an analysis of the impact of the pressure and flow transients created by this complex flow on the reservoir, an analysis of the impact of the pressure and flow transients created by this complex flow on equipment and structures, and the effect of slugging on corrosion rates. The following sections describe an experimental study of slug flow in a hilly terrain pipeline. The main intention of the experiments is to obtain data on slug growth and slug dissipation in a hilly terrain configuration. The data obtained on tracking the slugs are to be used in the validation of a mathematical and numerical simulator currently under development. Details of the latter are to be presented in a paper at a later date.
Abstract Multi-lateral completion technology is evolving rapidly and continuing to mature in order to provide new methods for reservoir management and increase production potential. ZADCO (Zakum Development Company) in conjunction with ADNOC (Abu Dhabi National Oil Company) / JODCO (Japan Oil Development Company) / JNOC-TRC (Japan National Oil Coraporation -Technology Research Center) / ADMA-OPCO (Abu Dhabi Marine Operating Company) and SSDS (Sperry-Sun Drilling Services) has successfully completed MLTBS Phase-1 (Multi- Lateral Tie Back System) utilizing an existing well, a level 5 TAML (Technology Assessment Multi-Laterals) completion and level 4 TAML hydraulic isolation. MLT(Multi-Lateral Technology) application for the existing well was the first achievement in the world. In addition, several new technologies such as running and full cementing 7" liner in 8–1/2" lateral, recording cement evaluation logs over the cased lateral using TLCS (Tough Logging Condition System), and perforating the cased lateral with one run using TCP (Tubing Conveyed Perforator) were firstly implemented in UAE. Three years of R&D, integrated planning, and testing were required by MLTBS project team before attempting the extremely aggressive trial. The ultimate success of the Phase-1 trial on Well-A will encourage introducing MLTBS into Upper Zakum field to -:Re-establish dry oil production by locating the horizontal section in an optimum layer of upper reservoir. Allow access to upper cased lateral and lower barefoot lateral on demand through the newly designed dual completion. Achieve effective stimulation increasing production capacity of both upper cased lateral and lower barefoot lateral. Leave future options for reservoir monitoring and extending the well life by drilling a secondary lateral or applying selective water shut-off in the upper cased lateral. MLTBS will provide planning flexibility to exploit reservoirs to their maximum potential, allowing ZADCO to create new development strategies. Introduction The upper and lower reservoirs have been developed simultaneously adopting a five spot water injection pattern in Upper Zakum field since 1984. First water breakthrough was confirmed in the upper reservoir in the middle of 1991. Since then, the number of water cut strings gradually increased to reach about 40% of the total production strings. Well production capacity has declined rapidly once water breakthrough occurred. A high permeable layer at the bottom of the upper reservoir caused the unexpected early water breakthrough (Fig. 1). Horizontal drilling technology has been widely applied since 1989. Dual or Multi-lateral drilling technology combined with dual completion with no access function to the lateral(s) in the upper reservoir has been applied for developing both reservoirs since 1994. It was believed that an optimum placement of the lateral as well as introducing a new completion system with access function might offer an effective mean to improve productivity, monitor the breakthrough and reduce (or delay) the water production from the upper reservoir.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government > UAE Government (0.54)