Three-phase microemulsion relative permeabilities: Experimental and theoretical consideration

Kvanvik, B.A.; Skauge, Arne; Matre, B.; Kolltveit, K.

doi:10.1016/0920-4105(92)90012-p

Cited by 4 publications

(7 citation statements)

References 15 publications

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“…The two high‐permeability cores behaved essentially the same, but the low‐permeability one showed some appreciable differences for gas relative permeability in the direction of increasing gas saturation. In their brine/oil/microemulsion flow experiments on Berea sandstone, Kvanvik et al [] reported a significant effect of absolute permeability on three‐phase oil relative permeability. No systematic trend, however, was observed for the brine and microemulsion phases.…”

Section: Effects Of Rock Characteristicsmentioning

confidence: 99%

“…They pointed out that relative permeability of each phase appeared not to be a function of its own saturation alone. Kvanvik et al [] extended the work of Skauge and Matre [] by conducting several more unsteady‐state experiments and then interpreted new data together with previously reported results. It was observed that three‐phase excess water relative permeabilities were generally higher in the direction of increasing water saturation than in the opposite direction.…”

Section: Effects Of Interfacial Tensionmentioning

confidence: 99%

“…This may be attributed to an incorrect judgment about the wettability of the system. Using an identical rock‐fluid system, Kvanvik et al [] later performed Amott tests [ Amott , ] and observed that both the excess brine and microemulsion phases demonstrated intermediate‐wetting behavior, whereas excess oil was the nonwetting phase compared to the other phases.…”

Section: Effects Of Saturation Historymentioning

confidence: 99%

“…Using a brine/oil/microemulsion fluid system and Berea sandstone, Kvanvik et al [] conducted three‐phase experiments by injecting the third phase to displace the second phase in the presence of residual saturation of the first phase. Amott tests [ Amott , ] demonstrated intermediate‐wetting behavior for excess brine and microemulsion and nonwetting behavior for excess oil.…”

Section: Effects Of Saturation Historymentioning

confidence: 99%

“…Accurate assessment of wetting characteristics of a rock‐fluid system is an important aspect that requires consideration before conducting flow experiments. Delshad et al [], Skauge and Matre [], Eikje et al [], and Kvanvik et al [] measured three‐phase brine‐oil‐microemulsion relative permeabilities in Berea sandstone. Fluid systems of Eikje et al and Kvanvik et al were respectively close to and the same as that of Skauge and Matre.…”

Section: Effects Of Wettabilitymentioning

confidence: 99%

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Three-phase flow in porous media: A review of experimental studies on relative permeability

Alizadeh

Piri

2014

Rev. Geophys.

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We present a detailed, synthesized review of experimental studies on three-phase relative permeability published since 1980. We provide comprehensive, yet highly focused, analysis of critical aspects of the field and their evolution over the last three decades. In particular, we review the effects of saturation history, wettability, spreading, and layer drainage on the measured flow properties. We also list all the processes, rock types, fluid systems, and measurement techniques in order to provide a clear map for future studies. Behavior of the measured three-phase relative permeabilities with respect to fluid saturations, saturation histories, wettability of rock samples, spreading characteristics, interfacial tensions, and other pertinent properties are carefully discussed. Studies that use a diverse set of experimental techniques and data analysis to deduce relative permeability are included. The experimental techniques that should be utilized to reduce uncertainty are also explored. We interpret the measured properties and outcomes of different studies and compare them to substantiate distinct trends at various saturation ranges and provide ideas for new studies. This is intended to distill a clear image of where the field stands and to allow composition of possible paths for future investigations. The areas of critical relevance that have not been investigated or require further studies are highlighted.

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Section: Effects Of Rock Characteristicsmentioning

confidence: 99%

Section: Effects Of Interfacial Tensionmentioning

confidence: 99%

Section: Effects Of Saturation Historymentioning

confidence: 99%

Section: Effects Of Saturation Historymentioning

confidence: 99%

Section: Effects Of Wettabilitymentioning

confidence: 99%

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Three-phase flow in porous media: A review of experimental studies on relative permeability

Alizadeh

Piri

2014

Rev. Geophys.

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Analytical solutions for surfactant‐enhanced remediation of nonaqueous phase liquids

LaForce

Johns

2005

Water Resources Research

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[1] Benchmark compositional solutions are presented for the remediation of aquifers contaminated with nonaqueous phase liquids (NAPLs) by injection of surfactant-water mixtures. The method of characteristics (MOC) is used to find one-dimensional analytical solutions to the Riemann problem where three partially miscible phases are flowing in a Winsor type III microemulsion. In partially miscible flow, two or three phases form when the components (constituents) are mixed in some but not all proportions. Three relative permeability models are examined, and MOC solutions are found. Fine-grid numerical simulations match the MOC results. The composition routes and contaminant recoveries can differ significantly depending on the relative permeability model used. The results for each model are optimized to determine the minimum surfactant volume required for complete contaminant recovery. Unlike two-phase partially miscible flow, the presence of three flowing phases makes it impossible to reach miscibility between the injected and resident fluids, regardless of surfactant concentration.Citation: LaForce, T., and R. T. Johns (2005), Analytical solutions for surfactant-enhanced remediation of nonaqueous phase liquids, Water Resour. Res., 41, W10420,

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Cyclic Hysteresis in Three-Phase Relative Permeability Applicable to WAG Injection: Water-Wet and Mixed-Wet Systems under Low Gas/Oil IFT

Fatemi

Sohrabi

2012

SPE Annual Technical Conference and Exhibition

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One major problem in the prediction of the performance of Water Alternating Gas (WAG) process is the uncertainty associated with the changes in three-phase relative permeability (kr) values of oil, gas and water in different cycles, which is known as cyclic hysteresis. In this work we have investigated the effect of cyclic injection on three phase kr by performing a series of coreflood experiments under both water-wet and mixed-wet conditions. WAG experiments started with water injection (I) followed by gas injection (D) and this cyclic injection of water and gas was repeated (IDIDID). Three-phase relative permeabilities were obtained analytically from the coreflood data using an extension of Buckley-Leveret formula to three-phase flow. The results show the importance of properly accounting for irreversible kr hysteresis loops (especially for gas and oil) in the processes involving cyclic injection under three-phase flow conditions. Gas relative permeability (krg) dropped in successive cycles under both water-wet and mixed-wet conditions krg hysteresis was larger in the water-wet system compared to the mixed-wet case. The results also reveal cyclic hysteresis for oil relative permeability (kro), which tends to increase in successive gas injection periods. The improvement in kro was larger in the water-wet system. In both water-wet and mixed-wet systems, the largest krw hysteresis happens for the transition from two-phase (oil/water system) to three-phase system (from 1st water injection into 1st gas injection) and the subsequent WAG cycles does not show much hysteresis for krw in our experiments. The paper also offers insights into and explanations for the observed cyclic hysteresis behaviour based on our understanding of the pore-scale and core-scale displacement mechanisms involved in WAG injection. The results highlight some serious shortcomings of the existing reservoir simulators for reliable simulation of oil recovery processes involving three-phase flow and flow reversal.

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Three-phase microemulsion relative permeabilities: Experimental and theoretical consideration

Cited by 4 publications

References 15 publications

Three-phase flow in porous media: A review of experimental studies on relative permeability

Three-phase flow in porous media: A review of experimental studies on relative permeability

Analytical solutions for surfactant‐enhanced remediation of nonaqueous phase liquids

Cyclic Hysteresis in Three-Phase Relative Permeability Applicable to WAG Injection: Water-Wet and Mixed-Wet Systems under Low Gas/Oil IFT

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