Pore-Scale Modeling of Three-Phase WAG Injection: Prediction of Relative Permeabilities and Trapping for Different Displacement Cycles

Suiçmez, Vural Sander; Piri, Mohammad; Blunt, Martin J.

doi:10.2118/95594-ms

Cited by 21 publications

(6 citation statements)

References 49 publications

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“…In our model, we have implemented a more accurate thermodynamic criterion for formation and collapse of oil layers (van Dijke et al 2004(van Dijke et al , 2007. The model of Piri and Blunt (2005a, b) was extended later (Suicmez et al 2006) by adding two new double-displacement mechanisms, double imbibition (water/oil/gas) and imbibition/drainage (water/gas/oil). Nardi et al (2009) developed a three-phase flow network model by use of networks extracted from 3D digital rocks.…”

Section: Introductionmentioning

confidence: 99%

Three-Phase Pore-Network Modeling for Reservoirs With Arbitrary Wettability

Al-Dhahli¹,

Geiger²,

Dijke³

2012

SPE Journal

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Oil reservoirs have structural heterogeneities across multiple length scales and, particularly in carbonates, complexly distributed wettabilities. The interplay of structural and wettability heterogeneities is the fundamental control for sweep efficiency and oil recovery. This interplay must be captured in physically robust flow functions, such as relative permeability and capillary pressure functions. Such flow functions then allow us to choose the best improved-oil-recovery (IOR) or enhanced-oil-recovery (EOR) process and forecast oil recovery with adequate precision. Obtaining flow functions for reservoir rocks with varying wettability is a challenging task, especially when three fluid phases coexist. In this work, we use pore-network modeling, a reliable and physically based simulation tool, to predict three-phase flow functions. We have developed a new pore-scale network model for rocks with variable wettability. Unlike other models, this model combines three new and important features. (1) Our network model comprises a novel thermodynamic criterion for the formation and collapse of oil layers. This captures film/layer flow of oil adequately, which affects the oil relative permeability at low oil saturation. We can therefore predict residual oil more accurately.(2) We implemented multiple displacement chains, in which injection of one phase at the inlet triggers a chain of interface displacements throughout the network. This allows us to accurately model the mobilization of disconnected phase clusters that arise during higher-order [water-alternating-gas (WAG)] floods. Again, this feature is key to a better prediction of residual oil saturation (ROS).(3) Our model takes realistic 3D pore networks extracted from pore-space reconstruction methods and X-ray computerizedtomography (CT) images as input. This preserves both topology and pore shape of the rock, providing better estimates of phase conductivities and relative permeability. We have validated our model by use of available experimental data for a range of wettabilities and demonstrated the impact of single vs. multiple displacement on residual oil. We also used a proof-of-concept study in which we use flow functions for different wettabilities that have been computed with our model in field-scale reservoir simulations to forecast oil recovery during tertiary gas injection. These results are compared with predictions that used empirical flow functions. Flow functions computed by our network model gave higher oil recovery than corresponding flow functions calculated by empirical models; oil recovery increases with decreasing water-wetness. This shows that the pore-scale physics encapsulated in our new network model leads to the right emergent behavior at the reservoir scale.

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Section: Introductionmentioning

confidence: 99%

Three-Phase Pore-Network Modeling for Reservoirs With Arbitrary Wettability

Al-Dhahli¹,

Geiger²,

Dijke³

2012

SPE Journal

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“…However, those empirical methods are not more physically-based which fall to capture the oil flow at its low saturation and this indicates imprecise prediction of residual oil. Furthermore, they have been developed with an assumption of that the rocks are strongly water-wet [34].…”

Section: Stone's Model I and Iimentioning

confidence: 99%

Uncertainty in WAG Injection Modelling using Empirical methods and Three-Phase Pore-Network Modeling with Rock Heterogeneity Effect

Suramairy¹,

Abdul-Rahman²

2015

IJETT

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Abstract-The demand for fossil fuel for instance, oil and gas has been dramatic in recent decades. Therefore, many oil and gas companies are attempting to find out new technics for enhancing oil recovery for example, secondary and tertiary methods. Indeed, in recent years the interest in water alternating gas (WAG) has been increased as tertiary recovery method. Moreover, this method has been applied successfully in several fields around the world. In fact, the (WAG) injection method results in three-phase flow zones. Therefore, it is important to understand and well describing the multi-phase flow properties. This study investigated the uncertainty in multi-phase flow between pore-scale network modelling and empirical methods. Network models are being used as alternative for empirical methods to describe the multi-phase flow properties, since the former are physically-based tools which integrate the relevant pore-scale mechanisms while the latter often have little physical basis. The reservoir simulation has been employed to study the effect of rock heterogeneity on the absolute oil recovery obtained by empirical methods and pore network model during WAG injection in heterogeneous reservoirs. The results showed that rock heterogeneity could increase the three phase flow uncertainty between empirical methods and pore network modelling. Moreover; the investigation showed significant effect of rock heterogeneity (different relative permeability models) on overall WAG performance.

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“…In this case, the boundary drainage curve will be retracted till the next flow reversal point. In Killough's model it is assumed that all the calculated imbibition curves are reversible, the assumption which may not be supported by the reported experimental data (Egermann, Vizika et al 2000), (Suicmez, Piri et al 2006), (Larsen and Skauge 1998). In Killough's method, the interpolated imbibition relative permeability can be calculated using the following correlations based on the schematic model details in Fig.3 (Killough 1976)):…”

Section: Two-phase Hysteresis Modelsmentioning

confidence: 99%

Investigating the Effect of Hysteresis modelling on Numerical Simulation of Immiscible WAG Injection

et al. 2011

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Although, WAG has been studied and implemented widely for hydrocarbon recovery improvement, still there are some uncertainties regarding flow dynamics in the three-phase region. One of the most important uncertainty areas is modeling of three phase relative permeability in this region. Commercial simulators by using conventional three phase models cannot capture all the features and mechanisms behind the three phase flow. Hysteresis is one of the phenomenons, which is still remained controversial in three phase relative permeability models. Some of the current relative permeability models have accounted for this phenomenon and in others, hysteresis effect is lacking. Two phase models usually fail to predict the actual behavior of the hysteresis in three phase flow. Some of the three phase models also take in to account the features of hysteresis but not all of them. In the simulation process of water alternating gas, hysteresis modeling is a corner stone of the workflow. If this work step is not done properly, the results of the simulation study may not necessarily capture different aspects of the WAG injection scenario and the results could be mis-leading affecting the business decision.In this study, first an extensive parametric paper review and literature survey has been done on hysteretic two and three phase relative permeability models following by a comparative analysis. Parametric investigation is carried out and the advantages and disadvantages of the models are discussed. The model predictions versus selected experimental data are shown and the discrepancies are highlighted. The onset point to improve the model prediction is declared and finally to show the hysteresis effect on oil recovery a simulation case is done using a synthetic sector model.The discussion in this study show that by properly modeling the WAG process and taking into account the hysteresis phenomenon, the robustness of the results on incremental hydrocarbon recovery by WAG process can be significantly improved. It can be concluded that the simulation results using the commercial simulator can be mis-leading in term of the WAG injection performance if hysteresis modeling is not properly done and applied.

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Pore-Scale Modeling of Three-Phase WAG Injection: Prediction of Relative Permeabilities and Trapping for Different Displacement Cycles

Cited by 21 publications

References 49 publications

Three-Phase Pore-Network Modeling for Reservoirs With Arbitrary Wettability

Three-Phase Pore-Network Modeling for Reservoirs With Arbitrary Wettability

Uncertainty in WAG Injection Modelling using Empirical methods and Three-Phase Pore-Network Modeling with Rock Heterogeneity Effect

Investigating the Effect of Hysteresis modelling on Numerical Simulation of Immiscible WAG Injection

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