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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)
Exploration Applications of Downhole Measurement of Crude Oil Composition and Fluorescence
Betancourt, Soraya S. (Schlumberger-Doll Research) | Fujisawa, Go (Schlumberger-Doll Research) | Mullins, Oliver C. (Schlumberger-Doll Research) | Eriksen, Kare Otto (Statoil ASA) | Dong, Chengli (Schlumberger) | Pop, Julian (Schlumberger) | Carnegie, Andrew (Schlumberger)
Abstract In addition to geological and petrophysical data acquisition during the exploration stage, in-situ fluid analysis provides a wealth of information for the appraisal of new discoveries. A recently introduced wireline sampling tool incorporating a downhole fluid analyzer is capable of analyzing fluid composition in real time at downhole conditions, and of measuring the fluorescence spectra of crude oils. These new measurements provide valuable information necessary for the identification and validation of reservoir structures that define the distribution of fluids in the accumulation. The relevance of high quality fluid data in the early stages of the producing life of the reservoir is widely recognized. We present field results of the application of the new sampling tool in an exploration well, where a composition gradient was detected along a 30m liquid hydrocarbon column grading from a 45API crude on the top to a 33API crude on the bottom. During the sampling of the gas cap, retrograde dew formation was detected identifying the fluid and identifying valid sampling conditions. This new information was used to modify the sampling program. Fluid composition analysis relies on optical absorption methods and is currently capable of providing the mass fraction of three hydrocarbon molecular groups: C1, C2โ5 and C6+, and CO2. We perform fluorescence spectroscopy by measuring light emission in the green and red ranges of the spectrum after excitation with blue light. Fluorescence in this range is related to the concentration of polycyclic aromatic hydrocarbons (PAH's) in the crude oil. Using the pump-out module to segregate different fluid phase enhances phase detection with fluorescence. Introduction Fluid properties relevant to reservoir evaluation are determined, for the most part, by laboratory analysis of recovered samples, with the laboratory results being only as good as the samples provided. One main issue therefore for reservoir characterization is fluid sample validity/quality. Bottomhole samples are expected to be more representative of the original hydrocarbon since they are acquired and maintained at conditions similar to those in the reservoir. Valid sampling must satisfy two conditions: first, a minimum amount of contamination from foreign agents especially miscible mud filtrate should be present in the sample; and second, that sampling should be conducted under conditions guaranteeing that the fluid has not undergone any phase transitions; different phase have different mobilities yielding acquisition of nonrepresentative samples. Phase transitions may be induced by changes in pressure and/or temperature, the former being the most commonly encountered when sampling with wireline tools. Miscible contamination can also alter phase behavior. When the saturation pressure of the reservoir is unknown, as is mostly the case, the monitoring of fluid composition and fluorescence will indicate if the sampling pressure has fallen below the saturation pressure of the fluid. The sample will then be collected or not according to criteria based on the stability of the composition, and the minimization of filtrate contamination. To identify a retrograde condensate, one can steadily drop the sampling pressure below the saturation pressure of the fluid to observe the change in the fluorescence signal that will occurs with dew formation at the dew point pressure. This is a useful test for reservoir development since it identifies the existence of retrograde condensate, provides a real-time estimate of the fluid dew pressure, and gives information about the effects of two-phase flow on production performance. We can also monitor the estimated dew point against oil based mud (OBM) contamination.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.34)
Abstract A field study by compositional simulation results in expensive computation by a huge number of phase equilibrium calculations. The common method of reducing the computation time is to describe the fluid by lumping its components into several pseudo-components. The main drawback of pseudoization is the loss of detailed compositional information on reservoir fluids. This paper reports results of evaluation studies on accuracy and efficiency of different computing methods of equation-of-state incorporated in a compositional simulation model. The compositional model was formulated by the IMPES approach. The computation methods used for iterative EOS flash calculations are the successive substitution iteration (SSI) method, Newton method, their combination, and a generalized Michelsen method to reduce the number of independent variables. Performances of the flash computation methods were evaluated by simulating behavior of a single well in gas condensate and volatile oil reservoirs, where the reservoir fluids were grouped into 5, 10, and 16 pseudo-components for each reservoir. Simulation demonstrated high effectiveness of the parameter reduction method showing significant decreases in flash computation time compared to the conventional methods, particularly when the number of pseudo-components was increased. Introduction There have been developed three basic methods of formulation for equation-of-state (EOS) compositional modelling; fully implicit, implicit-pressure explicit-composition and saturation (IMPES), and semi-implicit methods. Coats proposed a fully implicit EOS compositional model in 1980. The fully implicit formulation generally requires the simultaneous solution of 2nc+ 4 equations of the mass balance, the phase equilibrium constraints, and the saturation constraint, for the same number of unknowns of the component mole fractions in oil and gas phases, pressure, and saturation. The phase equilibrium and saturation constraints are then coupled into the mass balance equations to reduce the system to nc+ 1 equations for nc+ 1 unknowns. Although the fully implicit method promises numerical stability, the computation time increases with the square of the number of components. This causes a major drawback of this method such that the number of components is limited for a field-scale simulation. The IMPES model proposed by Nghiem et al. in 1981 solves a system of equations by an iterative-sequential method. An implicit formulation of the pressure equation, obtained by combining the material balance equation on the water phase and the molar balance equation of the hydrocarbon system, is solved by a direct or Newton-like iterative method. Once pressures in the new iteration step are obtained, water saturation and total mole fractions of the hydrocarbon components are computed explicitly. Flash calculations are carried out at this stage for each grid block to obtain component mole fractions in the oil and gas phases, phase molar densities, and phase mole fractions. Based on the flash, the oil and gas saturations are computed. These procedures are repeated until convergence conditions are met. The drawback of this formulation is the time-step size limitation due to explicit treatment of compositions and transmissibilities. Branco and Rodrigues presented a semi-implicit formulation for compositional simulation, where the component mole fractions in the flow terms of the component mass balance equations are treated explicitly, one iteration step behind. The linearized system of equations allows the two-step reductions. First, the system is reduced to nc+ 1 equations, just as done by Coats. Secondly, the system is partitioned into one that consists of 3 equations for 3 unknowns, similar to a black-oil system, and the other system with nc- 2 equations for component mole fractions of a phase. The level of implicitness of this method was confirmed to be intermediate between the IMPES and fully implicit methods.
This paper was prepared for presentation at the 1998 SPE Asia Pacific Conference on Integrated Modelling for Asset Management held in Kuala Lumpur, Malaysia, 23-24 March 1998.
- North America > United States > California > Ventura County (0.28)
- Asia > Malaysia > Kuala Lumpur > Kuala Lumpur (0.24)
- Geology > Geological Subdiscipline > Geomechanics (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.42)
- Oceania > New Zealand > North Island > Taranaki Basin > Waihapa (PML 38140) License > Waihapa Ngaere Field > Waihapa Field (0.99)
- Oceania > New Zealand > North Island > Taranaki Basin > Tariki (PML 38138) License > Waihapa Ngaere Field > Waihapa Field (0.99)
- Oceania > New Zealand > North Island > Taranaki Basin > Ngaere (PML 38141) License > Waihapa Ngaere Field > Waihapa Field (0.99)
- (2 more...)
Abstract This paper proposes a new compositional simulation approach which has an implicit equation for the oil-phase pressure and water saturation, an explicit equation for the hydrocarbon saturation, and explicit equation for the overall composition of each hydrocarbon component that satisfies thermodynamic equilibrium. The proposed formulation uses an Equation of State for phase equilibrium and property calculations. Interfacial tension effects are included in this research to characterize the thermodynamically dynamic nature of the relative permeability. A two-dimensional relative permeability algorithm is included which handles lumped hydrocarbon phase hydrocarbon phase as well as individual phase flows. For each grid block two equations are required, namely total hydrocarbon and water-phase flow equations. These equations are highly non-linear and they are linearized by using Newton-Raphson method. The resulting set of equations are solved by an efficient Conjugate Gradient based iterative technique to obtain pressures and saturations simultaneously, and hydrocarbon-phase saturations are deduced from their respective equations. The new compositional simulation approach is validated through analytical and other numerical methods. lt is demonstrated in this present paper that the results are compared favourably with analytical techniques and published numerical results. They also confirm that the proposed codified formulation is unconditionally stable and it is as stable as the fully compositional model yet the computational cost reduction was substantial. Impact of sequence-based on correlation style on volatile oil recovery is modelled with this approach. Specifically, the effect of clino-formal permeability barriers on predicted displacement efficiency of oil by injected water and injected gas into volatile oil reservoirs is assessed. The results show that oil recovery factors are strongly affected by the combination of the structure of permeability and the transmissibility barriers between the layers. P. 281
- Europe > Norway > North Sea (0.46)
- North America > United States > California (0.46)
- Europe > United Kingdom > North Sea > Northern North Sea (0.28)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.61)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > PL 123 > Block 211/19 > Murchison Field > Brent Group Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > North Viking Graben > Block 211/26a > Cormorant Field > Etive Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > North Viking Graben > Block 211/26a > Cormorant Field > Brent Group Formation (0.99)
- (8 more...)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
Abstract Many oil and gas reservoirs have their associated aquifers, which provide them with some pressure support and form a hydraulic system. When material balance calculations are applied to such reservoirs, aquifer behavior models are required. In practice, the most common procedure is to assume an aquifer model, which has an analytical solution that can readily be implemented. The simplest methods are based on the Steady State (Schilthuis), Modified Steady State (Hurst), and the Unsteady State (Van Everdingen and Hurst), models. For correct description of the hydraulic system using the available techniques, it is required to have a minimum set of information about the reservoir and aquifer, such as: viscosities, compressibilities, permeabilities, volumetric factors, and geometry of aquifer and reservoir. To overcome possible lack of some of this information, the technology of aquifer influence function "AIF" has been developed and therefore employed. Most of the previous work was mainly concerned with AIF models for gas reservoirs. This study has focused on devising a methodology for assessing water influx into undersaturated oil reservoirs based on AIF models. After developing the AIF model, it was validated using actual field data and then applied to four real field cases from the Gulf of Suez region. The results of this application have shown that, the developed model can generate an accurate aquifer influence function for the given reservoir that may directly be extended for future predictions of the reservoir and aquifer performances. The model results have indicated good agreement with actual field data. The model required some basic historical data to run without assumption of reservoir and aquifer rock and fluid properties or aquifer geometry. The semi-analytical approach devised in this work, with Levenberg-Marquardt Non-Linear technique, provided a quick, easy and yet accurate procedure for calculating the aquifer influence function. Four field cases have been studied in this work, namely: October-Nubia, October "J"-Nubia, October "J"-Asl, and Ramadan-Nubia "C" reservoirs. Confirmed by the actual field studies, for different reservoir- aquifer geometry and strengths, the model has proven to be capable of:evaluating the reservoir-aquifer performance, defining an appropriate AIF, and predicting reservoir pressures under varying production schemes. Sensitivity cases have also shown that better description of the aquifer influence function model can always be achieved and consistently improved by using additional production data when available. P. 219
- Asia (0.88)
- Africa > Middle East > Egypt > Gulf of Suez (0.17)
- Africa > Middle East > Egypt > Gulf of Suez > Gulf of Suez Basin > October Field (0.99)
- Africa > Middle East > Egypt > Gulf of Suez > Gulf of Suez Basin > Nubia Formation (0.99)