Getting the Best From the Black-oil Approach for Complex Reservoir Fluids

Montel, François; Quettier, L.

doi:10.2118/90926-ms

Cited by 6 publications

(4 citation statements)

References 2 publications

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“…Third, if a generalized black-oil model is used, it can be cast into a two-hydrocarbon (light "l" and heavy "h") compositional model where (6) being the ratio of gas and oil molar volumes at standard conditions, and (R s , R v ) being the gas solubilization and oil vaporization ratios, respectively (Montel & Quettier, 2004). We here recall the well-known definitions (7) where V go , V oo , V og , V gg are the standard volumes of gas reference component ("l") from reservoir oil phase, oil reference component ("h") from reservoir oil phase, and so on.…”

Section: Thermodynamic Equilibrium In Natural Variables Based Ihrrsmentioning

confidence: 99%

“…(7)) as a function of the oil saturation as (8) with (9) S o max is defined (and updated during the simulation if needed) in each computational cell as the largest historical oil saturation, evaluated from the first gas appearance for cells originally above bubble point, while 1 and h are positive model parameters entered using the VAPPARS keyword. The effect of such model is to reduce the amount of vaporized oil and dissolved gas as the oil saturation drops, and was first used as a "patch" in cases where, for instance, black-oil tables underestimate the saturation pressure (Montel & Quettier, 2004). This usage will not be further discussed.…”

Section: Sdtec In Black-oil Simulationmentioning

confidence: 99%

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Simulation of Residual oil Saturation in Near-miscible gas Flooding Through Saturation-dependent Tuning of the Equilibrium Constants

Patacchini

Duchenne

Bourgeois

et al. 2014

Abu Dhabi International Petroleum Exhibition and Conference

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Conventional miscible or near-miscible gas flooding simulation often overestimates oil recovery, mostly because it does not capture a series of physical effects tending to limit interphase compositional exchanges. Those can be for instance microscopic bypassing of oil situated in dead-end pores or blocked by water films, as well as macroscopic bypassing due to sub-grid size heterogeneities or fingering.We here present a new engineering solution to this problem in the near-miscible case, relying on our in-house research reservoir simulator (IHRRS). The principle is, while using a black-oil or an equation of state description, to dynamically decrease the K-value of heavy components and possibly increase the K-value of light components as the oil saturation reaches the desired residual limit; this enables changing the phase boundaries when needed while preserving the original fluid behavior during the initial production stages.The benefits of the proposed method are demonstrated on a reservoir conditions tertiary gas injection experiment, performed in our laboratories, for which residual saturations as well as oil phase and individual components production rate have easily and successfully been history matched. Results are then compared to matches obtained using saturation exclusion and ␣-factors methods. As a proof of concept, suitability of the method to simulate incomplete revaporization of condensate during gas cycling is also illustrated, on the third SPE comparative solution project case.

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Section: Thermodynamic Equilibrium In Natural Variables Based Ihrrsmentioning

confidence: 99%

Section: Sdtec In Black-oil Simulationmentioning

confidence: 99%

Simulation of Residual oil Saturation in Near-miscible gas Flooding Through Saturation-dependent Tuning of the Equilibrium Constants

Patacchini

Duchenne

Bourgeois

et al. 2014

Abu Dhabi International Petroleum Exhibition and Conference

View full text Add to dashboard Cite

show abstract

“…After addition of more gas than initially present in the original live oil, the pressure is increased until the gas disappears at the new bubble point. Montel and Quettier (2004) stated that for the case of gas injection in an undersaturated oil reservoir, the extrapolation of black oil properties above the initial saturation pressure should be done by adding increasing quantities of injection gas with initial oil.…”

Section: Introductionmentioning

confidence: 99%

Extrapolation of black- and volatile-oil fluid properties with application to immiscible/miscible gas injection

Nojabaei

Johns

2016

Journal of Natural Gas Science and Engineering

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Black-oil fluid properties are determined by lab measurements or can be calculated through flash calculations of the reservoir fluid. Allowing for variable bubble-point pressures in black-or volatile-oil models requires a table of fluid properties be extended above the original bubble-point. Reservoir simulation accuracy, however, may be affected by discontinuities in the input data and poor predictions of extrapolated fluid properties. Common practice is to add surface gas to the original oil in the lab and increase the pressure to reach a new bubble-point. Another approach is to use linear extrapolation of oil and gas K-values with pressure on a log-log plot, where K-values are equal to 1.0 at a pseudo-critical or convergence pressure. The latter approach results in discontinuities in the phase behavior.We calculate continuous black-oil fluid properties above the original bubble-point by adding a fraction of the equilibrium gas at one bubble-point pressure to achieve a larger bubble-point pressure. This procedure continues until a critical point is reached at the top of the pseudocomponent pressure-composition diagram. Unlike other methods commonly used or recently proposed, the approach provides a smooth and continuous pressure-composition curve to the critical point. The model further allows for reinjection of produced gas, methane, or CO 2 to increase oil recovery for both volatile and black oils. Further, the approach allows the use of black-oil or volatile-oil properties for tight rocks where capillary pressure alters the saturation pressures by decreasing the bubble-point pressure or increasing the dew-point pressure. Bubble-point pressure in the new model is a function of both capillary pressure (effective pore radius) and gas content. The phase behavior is illustrated using ternary diagrams for up to four components (water, oil, gas, and CO 2 or CH 4 ) and three phases (aqueous, oleic, gaseous) to allow for miscible and immiscible injection of various gases. The new phase behavior could be easily incorporated in a compositionally-extended black-or volatile-oil simulator. The approach could also be used to model gas condensate reservoirs with or without gas injection and capillary pressure. Finally, 1-D slim-tube simulations are made with the extrapolated black oil fluid properties to estimate minimum miscibility pressure (MMP) to demonstrate the applicability of the approach. Shocks occur in the 1-D displacement consistent with a compositional simulator.

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“…After addition of more gas, the pressure is increased until the gas disappears at the new bubble point. Montel and Quettier (2004) stated that for the case of gas injection in an undersaturated oil reservoir, the extrapolation of black oil properties above the initial saturation pressure should be done by adding increasing quantities of injection gas with initial oil.…”

Section: Introductionmentioning

confidence: 99%

Consistent Extrapolation of Black and Volatile Oil Fluid Properties Above Original Saturation Pressure for Tight and Conventional Reservoirs

Nojabaei

Johns

2015

SPE Reservoir Simulation Symposium

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Black-oil fluid properties are determined by lab measurements or can be calculated through flash calculations of the reservoir fluid. Allowing for a variable bubble-point pressure in black-or volatile-oil models requires a table of fluid properties be extended above the original bubble-point. Reservoir simulation accuracy, however, may be affected by discontinuities in the input data and poor predictions of extrapolated fluid properties. Common practice is to add surface gas to the original oil in the lab and increase the pressure to reach a new bubble-point. Another approach is to use linear extrapolation of oil and gas K-values with pressure on a log-log plot, where K-values are equal to 1.0 at a pseudo-critical or convergence pressure. The latter approach results in discontinuities in the phase behavior.We calculate continuous black-oil fluid properties above the original bubble-point by adding a fraction of the equilibrium gas at one bubble-point pressure to achieve a larger bubble-point pressure. This procedure continues until a critical point is reached at the top of the pseudocomponent pressurecomposition diagram. Unlike other methods commonly used or recently proposed, the approach provides a smooth and continuous pressure-composition curve to the critical point. The model further allows for reinjection of produced gas, methane, or CO 2 to increase oil recovery for both volatile and black oils. We show how to tune the models to the MMP by matching the appropriate critical point pressure. Further, the approach allows the use of black-oil or volatile-oil properties for tight rocks where capillary pressure alters the saturation pressures by decreasing the bubble-point pressure or increasing the dew-point pressure. Bubble-point pressure in the new model is a function of both capillary pressure (effective pore radius) and gas content. The phase behavior is also described on ternary diagrams for up to four components (water, oil, gas, and CO 2 or CH 4 ) and three phases (aqueous, oleic, gaseous) to allow for miscible and immiscible injection (or soaking) of various gases. The new phase behavior could be easily incorporated in a compositionally-extended black-or volatile-oil simulator. The approach could also be extended to model gas condensate reservoirs with or without gas injection and capillary pressure.

show abstract

Getting the Best From the Black-oil Approach for Complex Reservoir Fluids

Cited by 6 publications

References 2 publications

Simulation of Residual oil Saturation in Near-miscible gas Flooding Through Saturation-dependent Tuning of the Equilibrium Constants

Simulation of Residual oil Saturation in Near-miscible gas Flooding Through Saturation-dependent Tuning of the Equilibrium Constants

Extrapolation of black- and volatile-oil fluid properties with application to immiscible/miscible gas injection

Consistent Extrapolation of Black and Volatile Oil Fluid Properties Above Original Saturation Pressure for Tight and Conventional Reservoirs

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