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Collaborating Authors
Reservoir Simulation
Abstract Dispersivity affects the displacement and sweep efficiencies and the required slug size of a displacing fluid. Unfortunately, the dispersivity values estimated from field tests are a few orders of magnitude greater than the values obtained in laboratory tests. This investigation studies the effect of small scale (or core scale) heterogeneities on the effective dispersivity value in a typical gridblock size used in a reservoir simulator. The study is restricted to contact miscible displacements with unit mobility ratio. A finite element simulator is used to investigate these effects. Physical dispersion is explicitly included in the simulator. Results show that the effective dispersivity is affected by the degree of heterogeneity, the average length of heterogeneity, the length of the system, and the manner in which the permeability values are spatially distributed. The effect of heterogeneity becomes significant if the coefficient of variance is greater than 0.4. The effect of dimensionless scale length (ratio of average length of heterogeneity to length of the system) on effective dispersivity is insignificant for dimensionless scale values less than .01; above that value dispersivity increases with an increase in the scale length. The effective dispersivity increases almost linearly with an increase in the length of the system for constant dimensionless scale length. This provides an explanation for the similar trend reported for field dispersivity data. A simple correlation is proposed to calculate the effective dispersivity of the porous medium. The effect of the way in which given permeability values are distributed across the medium on the dispersivity cannot be correlated with the parameters investigated, probably indicating that the effective dispersivity is a unique function of the manner in which permeability values are distributed. This effect was not noted previously in the literature; however, it does not affect the general trends. Introduction Dispersion is important in understanding reservoir performance during enhanced oil recovery processes. Large values of dispersivity reduce the displacement efficiency of multiple contact miscible displacements and increase the sweep efficiency. The net result of dispersion may be to increase the required slug size of a displacing fluid. Unfortunately, the values obtained in the laboratory do not coincide with the values obtained in the field. The reasons for the discrepancy between the field and the lab values may include the effects of heterogeneities in reservoir properties and reservoir stratification. This discrepancy should not arise if all the possible heterogeneities in the reservoir, including the small scale heterogeneities, can be described rigorously. However, this type of description may not be practical. Generally, a reservoir simulator gridblock is the smallest unit by which heterogeneities in the reservoir may be represented. This investigation is restricted to study the effects of permeability variations in porous medium on the effective values of dispersivity. In cases studied, the permeability variations are the heterogeneities with length of variation about the same as that of the core length, (for example, several inches to several feet), sometimes called small scale heterogeneities. The effects of these small scale heterogeneities on the effective dispersivity value in a typical block size in a reservoir simulator are investigated. In other words, we are addressing the question of dispersivity scaling from laboratory to a typical block size in a field scale simulator. The studies are restricted to unit mobility ratio and contact miscible displacements. P. 215^
- 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)
Abstract Multiphase equilibrium calculations for binary, ternary, and quaternary hydrocarbon-water systems at high temperature were performed using the Schmidtz-Wenzel equation of state. The solubility of water in the hydrocarbon-itch liquid phase and vapor phases is modelled using a constant binary interaction parameter between water and hydrocarbon, while the solubility of hydrocarbons in the aqueous phase is calculated using a temperature dependent binary interaction parameter. Two and three phase equilibrium calculations were performed using the method of successive substitution. A stability analysis using the tangent plane criterion was used to determine the correct number of phases present. At high temperature the solubility of water in hydrocarbon liquids can be quite large. Using the procedure outlined above the solubility of water in the hydrocarbon-itch liquid phase was calculated accurately both for mixtures of water and pure hydrocarbon components, and for mixtures of water and petroleum fractions. The binary interaction parameters used in the hydrocarbon-rich liquid phase and the vapor phase were found to be dependent on the type of hydrocarbon. The interaction parameters for components in the same homologous group such as alkanes, aromatics, and alkenes were found to be almost the same. The solubility of hydrocarbons in the aqueous phase was calculated reasonably accurately using temperature dependent interaction coefficients in the aqueous phase. Above 200 the binary interaction parameters in the aqueous phase were linear functions of temperature. Binary interaction parameters from two phase binary data were found to be quite adequate to calculate three phase multicomponent equilibrium. Introduction Three phase equilibrium calculations with hydrocarbon and water phases are required in the modelling of many reservoir processes. At low temperatures, the solubility of water in the hydrocarbon-rich liquid phase and the solubility of hydrocarbon components in the aqueous phase is small. Thus the hydrocarbon phases and the water phase can be treated as being completely immiscible for the purposes of modelling without introducing significant error. At high temperatures, however, the solubility of water in the hydrocarbon-rich liquid phase can be quite large and the solubility of light hydrocarbons and acid gases in the aqueous phase is appreciable. Hoot and Brady et al. have given experimental data for the solubility of water in pure hydrocarbon components and petroleum fractions at the three phase pressure as a function of temperature. The solubility of water in hydrocarbon liquids increases exponentially with temperature, and at temperatures above 500F, it can be as high as 40 mole %. The solubility of water in hydrocarbons is primarily dependent on the temperature and the paraffin/aromatic characteristics of the hydrocarbons with only a slight effect of carbon number and molecular weights. The solubility of water at a given temperature is the lowest in alkanes and napthenes and the highest in aromatics, particularly benzene (see Figs. 1 and 2). The solubility of water in alkenes lies between its solubility in alkanes and aromatics. The solubility of hydrocarbons in water is considerably less than the solubility of water in hydrocarbons. At high temperature, the solubility of light hydrocarbon components such as methane and acid gas components such as CO2 and H2S can be greater than 10 mole %. The solubility of hydrocarbons in water drops off sharply with increased molecular weight. Given approximate equivalence of molecular weight, alkanes, then alkenes, then napthenes, and finally aromatics are progressively more soluble in water. Several papers in the literature deal with the modelling of hydrocarbon-water systems using equations of state (EOS). Heidemann used the Wilson modification of the Redlich-Kwong EOS to perform three phase flash calculations for hydrocarbon-water systems at temperatures below 300F. The calculation DID procedure was based on the minimization of the Gibbs free energy of the system by integration along the path of steepest descent. Heidemann's scheme used the component material balances and iterated on the component compositions in each phase so that the Gibbs energy of the system was minimized. He tested his procedure by modelling a three component and a six component system. Heidemann used a constant interaction parameter in all phases and was able to match the water content of the hydrocarbon liquid and vapor phases reasonably well. However, the predicted solubility of hydrocarbons in the aqueous phase was orders of magnitude too low. The efficiency of the method was poor, and a large number of iterations were necessary to obtain convergence. P. 733^
- Research Report > New Finding (0.46)
- Research Report > Experimental Study (0.46)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Oil & Gas > Downstream (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
Abstract The Weeks Island S sand Reservoir B (S RB) gravity-stable CO2 field test is almost complete. Injection started in October 1978 and production began in January 1981 in this high-permeability, steeply dipping sandstone reservoir. Through 1987, about 261,000 barrels of oil or about 64 percent of the starting volume has been recovered. A 24-percent pore-volume slug of CO2 mixed with about six mole percent of natural gas (mostly methane) was injected at the start of the pilot. During 1983, when gas production rates started to increase, CO2 containing produced gas was reinjected. Through 1987, CO2 usage statistics are 7.90 MCF/BO with recycle and 3.26 MCF/BO based on purchased CO2. This report is a review of early pilot history and a more detailed account of the post-June 1981 results. A reservoir-simulation history match of pilot performance plus core and log data from a 1983 swept-zone evaluation well are included. Introduction The Weeks Island field is located in New Iberia Parish, Louisiana. The structural features of the Weeks Island reservoirs are typical of many piercement salt-dome fields in the Gulf Coast. Sand quality and continuity in most reservoirs in the field are exceptionally good. Oil recoveries are typically 60 to 70 percent of original oil in place, and water-displacement sweep efficiencies are very high in these strong water-drive reservoirs. Residual oil volumes remaining in the larger reservoirs represent sizeable enhanced oil recovery (EOR) targets. The reservoirs at Weeks Island are deep and hot, e.g., 13,000 feet and 225F in the pilot. The dip in the S RB is about 26 degrees and permeability is high. Under these reservoir conditions, gravity-stable CO2 flooding is the selected EOR process. The implementation and about half of the operational life of the pilot were a joint effort with the U.S. Department of Energy. Reports by Perry and others document pilot design, implementation and early results for the 1977 to June 1981 time period. RESERVOIR DESCRIPTION The S sand Reservoir B was chosen for the pilot because it has properties similar to the largest EOR candidate reservoir at Weeks Island and because it is relatively small and well confined by faulting. The S RB originally contained about three million STB of oil underlying a 38-BCF gas cap. The oil column was first produced by gas-cap expansion and later by water injection. The one oil production well was completed near the gas-oil contact. Figure 1 is a structure map of the pilot portion of the S RB illustrating the relative position of the pilot wells. The gas cap extends along the face of the dome to the right in this figure. Table 1 shows key reservoir parameters plus production and injection volumes prior to the start of CO2 injection. The original oil-water contact was not logged in this reservoir; therefore, the original oil in place is uncertain. The prepilot oil-column production history ended in July 1978 in preparation of CO2 injection. P. 317^
- North America > United States > Louisiana > Iberia Parish (0.25)
- North America > United States > Oklahoma > Osage County (0.24)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.54)
- Reservoir Description and Dynamics > Reservoir Simulation > History matching (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
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