Gas-Oil Relative Permeability and Residual Oil Saturation as Related to Displacement Instability and Dimensionless Numbers

Rostami, Behzad; Kharrat, Riyaz; Ghotbi, Cyrus; Tabatabaie, S. Hamed

doi:10.2516/ogst/2009038

Cited by 12 publications

(11 citation statements)

References 34 publications

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“…The data show also a wide range of endpoint CO 2 relative permeabilities from low to high values. The change in relative permeability with CO 2 phase and operational conditions can be related to their potential strong influence on the capillary number, viscous forces, capillary forces, flow regimes [82,89], and capillary end effect; thus, in turn, the CO 2 phase and operational conditions will have a strong impact on relative permeability data [76,87,90]. Bennion and Bachu [90], Liu [76], and Parvazdavani [87] observed an impact for the operational conditions on relative permeability.…”

Section: The Effect Of Fluid Pressure Temperature and Injection Ratmentioning

confidence: 99%

“…It should be noted that, for the 70 bar GCO 2 displacements, increasing temperature from 45 to 55 • C reduced the endpoint CO 2 relative permeability from 0.412 to 0.342; this reduction could be associated with the appearance of differential pressure oscillations, as shown in Figure 10. The increase in relative permeability as temperature increased could be associated with the increase in the CO 2 injection rate [82,89] due to expansion effect (see Section 3.1.2). Skauge [82] and Rostami [89] observed that the increase in the displacement velocity leads to a higher gas relative permeability and can slightly affect the oil relative permeability [82,89].…”

Section: The Effect Of Fluid Pressure Temperature and Injection Ratmentioning

confidence: 99%

“…The increase in relative permeability as temperature increased could be associated with the increase in the CO 2 injection rate [82,89] due to expansion effect (see Section 3.1.2). Skauge [82] and Rostami [89] observed that the increase in the displacement velocity leads to a higher gas relative permeability and can slightly affect the oil relative permeability [82,89]. The reduction in the residual saturation of the LCO 2 displacements can be associated with the reduction in differential pressures due to increasing temperature, as shown in Figures 9-12.…”

Section: The Effect Of Fluid Pressure Temperature and Injection Ratmentioning

confidence: 99%

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The Effect of CO2 Phase on Oil Displacement in a Sandstone Core Sample

Al-Zaidi

Fan

Edlmann

2018

Fluids

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CO 2 sequestration in saline aquifers and hydrocarbon reservoirs is a promising strategy to reduce CO 2 concentration in the atmosphere and/or enhance hydrocarbon production. Change in subsurface conditions of pressure and temperature and CO 2 state is likely to have a significant impact on capillary and viscous forces, which, in turn, will have a considerable influence on the injection, migration, displacement, and storage capacity and integrity of CO 2 processes. In this study, an experimental investigation has been performed to explore the impact of fluid pressure, temperature, and injection rate, as a function of CO 2 phase, on the dynamic pressure evolution and the oil recovery performance of CO 2 during oil displacement in a Berea sandstone core sample. The results reveal a considerable impact of the fluid pressure, temperature, and injection rate on the differential pressure profile, cumulative produced volumes, endpoint CO 2 relative permeability, and oil recovery; the trend and the size of the changes depend on the CO 2 phase as well as the pressure range for gaseous CO 2-oil displacement. The residual oil saturation was in the range of around 0.44-0.7; liquid CO 2 gave the lowest, and low-fluid-pressure gaseous CO 2 gave the highest. The endpoint CO 2 relative permeability was in the range of about 0.015-0.657; supercritical CO 2 gave the highest, and low-pressure gaseous CO 2 gave the lowest. As for increasing fluid pressure, the results indicate that viscous forces were dominant in subcritical CO 2 displacements, while capillary forces were dominant in supercritical CO 2 displacements. As temperature and CO 2 injection rates increase, the viscous forces become more dominant than capillary forces.

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Section: The Effect Of Fluid Pressure Temperature and Injection Ratmentioning

confidence: 99%

Section: The Effect Of Fluid Pressure Temperature and Injection Ratmentioning

confidence: 99%

Section: The Effect Of Fluid Pressure Temperature and Injection Ratmentioning

confidence: 99%

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The Effect of CO2 Phase on Oil Displacement in a Sandstone Core Sample

Al-Zaidi

Fan

Edlmann

2018

Fluids

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“…The results from Table reveal that in general the increase in fluid pressure, temperature, and injection rate lead to an increase in the KrCO2 max and a decline in the Swr. In case of increasing fluid pressure and temperature, the high increase in the KrCO2 can be attributed mainly to the high increase in the injection rate inside the core sample due to the high impact of gas expansion (Rostami et al, 2010;Skauge et al). This increase in volumetric CO2 injection rate might result in forcing the CO2 to flow through a wider range of the core sample pores.…”

Section: Effect Of Fluid Pressure Temperature and Injection Rate Onmentioning

confidence: 99%

Gaseous CO2 behaviour during water displacement in a sandstone core sample

Al-Zaidi

Edlmann

Fan

2019

International Journal of Greenhouse Gas Control

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CO2 injection into subsurface formations involves the flow of CO2 through a porous medium that also contains water. The injection, displacement, migration, storage capacity and security of CO2 is controlled mainly by the interfacial interactions and capillary, viscous, and buoyancy forces which are directly influenced by changes in subsurface conditions of pressure and temperature; the impact of bouncy forces is assumed negligible during this study. In this study, gaseous CO2 is injected into a water-saturated sandstone core sample to explore the impact of fluid pressure (40-70 bar), temperature (29-45 °C), and CO2 injection rate (0.1-2 ml/min) on the dynamic pressure evolution and displacement efficiency. This study highlights the impact of capillary or viscous forces on the two-phase flow characteristics and shows the conditions where capillary or viscous forces become more influential. The results reveal a moderate to considerable impact of the parameters investigated on the differential pressure profile, endpoint CO2 relative permeability (KrCO2 max), and irreducible water saturation (Swr). Overall, the increase in fluid pressure, temperature, and CO2 injection rate cause an increase in the maximum and final differential pressures, an increase in the KrCO2 max , a reduction in the Swr. Swr was in the range of around 0.38-0.45 while KrCO2 max was less than 0.25. The data show a significant influence for the capillary forces on the pressure and production behaviour. The capillary forces produce high oscillations in the pressure and production data while the increase in viscous forces impedes the appearance of these oscillations. The appearance and frequency of the oscillations depend on the fluid pressure, temperature, and CO2 injection rate but to different extents.

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“…Although academics have made many researches on this question, a simple and effective method, which can directly measure the relative permeability of low-tension system, has not been found yet (Bai et al 2014c(Bai et al , 2015aBennion and Thomas 1991). Experiments also can determine the endpoint value of oil-water relative permeability to estimate the relative permeability curve (Bai et al 2014d(Bai et al , 2015bSpiteri et al 2008;Rostami et al 2010).…”

Section: Introductionmentioning

confidence: 99%

A new approach to obtaining relative permeability curves during chemical flooding process in a low-permeable reservoir

et al. 2015

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It is always difficult to obtain the relative permeability curve for a low-permeable reservoir using chemical flooding, as there are so many problems associated with the current measurement methods, especially when interfacial tension r, wettability cosh and pore-throat radius ratio m are considered as the main factors that influence the shape of the relative permeability curve, and thereby the oil recovery. This paper presents a new concept of modified capillary numbers (N CM ), associated with these three factors. First, laboratory experiments were carried out to get relationship between N CM and the residual oil saturation S OR under different conditions. Second, oilwater relative permeability curves for a target oil layer using the steady-state flow method were determined. Using these two steps, a relative permeability curve under different conditions of interfacial tension r, wettability cosh and pore-throat radius ratio m has been drawn. Based on the calculated relative permeability curves, the oil displacement efficiency and flow capacity were determined. Subsequently, the relationships between the relative permeability curve, oil displacement efficiency, flow capacity and the factors for a low-permeable reservoir were established using chemical flooding.Keywords Low permeable Á Chemical flooding Á Relative permeability Á Modified capillary number Á Pore-throat radius ratio Á Wettability Á Interfacial tension List of symbols hWetting angle (°) coshAverage contact angle cosine, the parameters of the wettability (-) N CM Modified capillary numbers (-) mPore-throat radius ratio (-) S OR Residual oil saturation (%) rInterfacial tension (mN/m) V wsp Water absorption oil discharge quantity in the Amott wettability index measurement experiment (ml) V wt Volume of oil by water displacement (ml) I W I W = V wsp /(V wsp ? V wt ) shows that the degree of water-wet (-) V osp Oil absorption water discharge quantity (ml) V ot Volume of water by oil displacement (ml) I O I O = V osp /(V osp ? V ot ) shows the degree of oil-wet (-) Amott wettability index I A

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Gas-Oil Relative Permeability and Residual Oil Saturation as Related to Displacement Instability and Dimensionless Numbers

Cited by 12 publications

References 34 publications

The Effect of CO2 Phase on Oil Displacement in a Sandstone Core Sample

The Effect of CO2 Phase on Oil Displacement in a Sandstone Core Sample

Gaseous CO2 behaviour during water displacement in a sandstone core sample

A new approach to obtaining relative permeability curves during chemical flooding process in a low-permeable reservoir

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