Impact of relative permeability hysteresis on the numerical simulation of WAG injection

Spiteri, Elizabeth; Juanes, Ruben

doi:10.1016/j.petrol.2005.09.004

Cited by 129 publications

(40 citation statements)

References 26 publications

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“…Injection of water slugs alternating CO 2 injection (in the spirit of classical WAG for enhanced oil recovery [Spiteri and Juanes, 2006]) increases the effectiveness of the sequestration project. The injected water forces breakup of large connected CO 2 plumes, enhancing trapping and immobilization of the CO 2 .…”

Section: Discussionmentioning

confidence: 99%

“…All these quantities are illustrated in Figure 4. The Land trapping model has been validated by comparison with experiments [Land, 1968;Jerauld, 1997;Spiteri and Juanes, 2006] and pore-network simulations [Spiteri et al, 2005] for water wet rocks. The bounding drainage and imbibition curves from the experimental data (Figure 3) result in a Land trapping coefficient C % 1.…”

Section: Trapping and Relative Permeability Hysteresis Modelsmentioning

confidence: 99%

“…Several mathematical models exist to treat hysteretic capillary pressure curves, including the one proposed by Killough [1976]. From a practical point of view, however, capillary pressure effects are often negligible at the time of numerically simulating field-scale displacements, especially, as is the case here, when the characteristic capillary length is much smaller than the grid resolution [Aziz and Settari, 1979;Spiteri and Juanes, 2006]. We have indeed checked that our predictions are insensitive to the choice of the hysteretic or nonhysteretic capillary pressure curves.…”

Section: Trapping and Relative Permeability Hysteresis Modelsmentioning

confidence: 99%

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Impact of relative permeability hysteresis on geological CO₂ storage

Juanes

Spiteri

Orr

et al. 2006

Water Resources Research

775

465

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[1] Relative permeabilities are the key descriptors in classical formulations of multiphase flow in porous media. Experimental evidence and an analysis of pore-scale physics demonstrate conclusively that relative permeabilities are not single functions of fluid saturations and that they display strong hysteresis effects. In this paper, we evaluate the relevance of relative permeability hysteresis when modeling geological CO 2 sequestration processes. Here we concentrate on CO 2 injection in saline aquifers. In this setting the CO 2 is the nonwetting phase, and capillary trapping of the CO 2 is an essential mechanism after the injection phase during the lateral and upward migration of the CO 2 plume. We demonstrate the importance of accounting for CO 2 trapping in the relative permeability model for predicting the distribution and mobility of CO 2 in the formation. We conclude that modeling of relative permeability hysteresis is required to assess accurately the amount of CO 2 that is immobilized by capillary trapping and therefore is not available to leak. We also demonstrate how the mechanism of capillary trapping can be exploited (e.g., by controlling the injection rate or alternating water and CO 2 injection) to improve the overall effectiveness of the injection project.

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Section: Discussionmentioning

confidence: 99%

Section: Trapping and Relative Permeability Hysteresis Modelsmentioning

confidence: 99%

Section: Trapping and Relative Permeability Hysteresis Modelsmentioning

confidence: 99%

See 1 more Smart Citation

Impact of relative permeability hysteresis on geological CO₂ storage

Juanes

Spiteri

Orr

et al. 2006

Water Resources Research

775

465

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“…It implies that the saturation-averaged interpolation method is a common choice in more-recent models in place of other mathematical models, such as capillary models, statistical models, and network models. Several investigators (Fayers and Matthews 1984;Delshad and Pope 1989;Baker 1988;Oak 1990Oak , 1991Hustad and Holt 1992;Skjaeveland and Kleppe 1992;Balbinski et al 1999;Pejic and Maini 2003;Spiteri et al 2008;Ahmadloo et al 2009) have identified various limitations of classical three-phase relative permeability models such as Stone I (Stone 1970) and Stone II (Stone 1973), especially for nonwater-wet rocks and/or at low oil saturation. Although the majority of three-phase relative permeability models found in Table 1 are applicable only to water-wet conditions, many oil reservoirs are not strongly water-wet and their wettability may be altered in various ways (Treiber and Owens 1972;Morrow 1990).…”

Section: Three-phase Relative Permeability Modelsmentioning

confidence: 99%

Novel Three-Phase Compositional Relative Permeability and Three-Phase Hysteresis Models

et al. 2014

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Mobility-control methods have the potential to improve coupled enhanced oil recovery (EOR) and carbon dioxide (CO 2 ) storage technique (CO 2 -EOR). There is a need for improved three-phase relative permeability models with hysteresis, especially including the effects of cycle dependency so that more-accurate predictions of these methods can be made. We propose new three-phase relative permeability and three-phase hysteresis models applicable to different fluid configurations in a porous medium under different wettability conditions. The relative permeability model includes both the saturation history and compositional effects. Three-phase parameters are estimated on the basis of saturation-weighted interpolation of two-phase parameters. The hysteresis model is an extension of the Land trapping model (Land 1968) but with a dynamic Land coefficient introduced. The trapping model estimates a constantly increasing trapped saturation for intermediatewetting and nonwetting phases. The hysteresis model overcomes some of the limitations of existing three-phase hysteresis models for nonwater-wet rocks and mitigates the complexity associated with commonly applied models in numerical simulators. The relative permeability model is validated by use of multicyclic threephase water-alternating-gas experimental data for nonwater-wet rocks. Numerical simulations of a carbonate reservoir with and without hysteresis were used to assess the effect of the saturation direction and saturation path on gas entrapment and oil recovery. Background and Literature ReviewThe fluid configuration and flow in porous media delineate regions in saturation space where commonly used three-phase relative permeability models fail to replicate the physical behavior. There are empirical correlations routinely used on the basis of an assumed fluid configuration and pore occupancy that are difficult to generalize to other fluid configurations. The pore-filling sequences and, consequently, the phase dependency of the three-phase isoperms-i.e., contours of constant phase relative permeability in the saturation space-are partly characterized by the pore-size distribution, the spreading preference of the liquids on the pore-solid surfaces, and the spreading preferences of one fluid between the other fluids.Wettability state and interfacial tension (IFT) play crucial roles in the spreading behavior in porous media. Three-phase displacement processes and pore-scale mechanisms in physical etched micromodels revealed that fluid configurations can be categorized depending on the phase-spreading coefficient (C s ), defined as a balance of IFT (Adamson 1960;Øren and Pinczewski 1995):

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“…Many authors have discussed three-phase relative permeability effects during immiscible WAG displacement. Spiteri and Juanes (2006) investigated the accuracy of a number of three-phase relative permeability hysteretic models by comparing them with laboratory data from Oak (1990) and noted that most were not yet implemented in commercial reservoir-simulation software. Egermann et al (2000) proposed a new three-phase-flow model based on a theoretical analysis validated on a set of experimental approaches.…”

Section: Introductionmentioning

confidence: 99%

Interpretation of Immiscible WAG Repeat Pressure-Falloff Tests

Stenger

Kendi

Katheeri

et al. 2011

SPE Reservoir Evaluation &Amp; Engineering

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This paper reviewed the interpretation of repeat pressure-falloff (PFO) tests acquired in two vertical pattern injectors operating in a carbonate reservoir undergoing full-field development. Enhanced vertical-sweep conformance through phase mobility control in the presence of strong reservoir heterogeneity was the major expected benefit from an immiscible water-alternating-gas (WAG) displacement mechanism.PFO tests were carried out during the monophasic injection phase to determine well injectivity and reservoir properties, and were subsequently acquired at the end of each 3-month injection cycle. Analytical falloff-test interpretation relied on the use of the two zone radial composite model. Multiple falloff-test interpretations indicated that the two pattern vertical injectors behaved differently even though both had been fractured. The difference in behavior was linked to different perforated intervals and reservoir properties. Gas-and water-injection rates were showing differences between both pattern injectors as a consequence. Injected gas banks had a small inner radius and were almost undetectable at the end of the subsequent water cycle. Changes in the pressurederivative slope at the end of the subsequent water-injection cycle indicated most likely the creation of an effective mixing zone of injected gas and water in the reservoir.Numerical finite-volume simulation was required to account for potential injected-fluid segregation and the heterogeneous multilayered nature of the reservoir. Repeat saturation logs acquired in observation wells monitored the saturation distribution away from the injection wells. Fluid saturations derived from the simulation model were showing a good agreement with the analytical results in general, although the need to account for gas trapping was confirmed. Eight planned development WAG injectors were repositioned as a consequence of WAG 1 and WAG 2 pattern performance.* Largest discrepancy for gas confirmed that gas would tend to propagate quicker caused by its lower viscosity. Comparison for water was more favorable owing to a more stable displacement.

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Impact of relative permeability hysteresis on the numerical simulation of WAG injection

Cited by 129 publications

References 26 publications

Impact of relative permeability hysteresis on geological CO₂ storage

Impact of relative permeability hysteresis on geological CO₂ storage

Novel Three-Phase Compositional Relative Permeability and Three-Phase Hysteresis Models

Interpretation of Immiscible WAG Repeat Pressure-Falloff Tests

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Impact of relative permeability hysteresis on the numerical simulation of WAG injection

Cited by 129 publications

References 26 publications

Impact of relative permeability hysteresis on geological CO2 storage

Impact of relative permeability hysteresis on geological CO2 storage

Novel Three-Phase Compositional Relative Permeability and Three-Phase Hysteresis Models

Interpretation of Immiscible WAG Repeat Pressure-Falloff Tests

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Resources

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Impact of relative permeability hysteresis on geological CO₂ storage

Impact of relative permeability hysteresis on geological CO₂ storage