Determination of Two-Phase and Three-Phase Relative Permeabilities in Heavy Oil/Water/Gas Systems

Modaresghazani, J.; Moore, Robert; Mehta, S.A.; Fraassen, Kees Cornelius Van

doi:10.2118/174475-ms

Cited by 9 publications

(11 citation statements)

References 12 publications

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“…Fundamentally though, one must recognize that the displacement tests associated measurement of relative permeabilities are subjected to some degree of viscous fingering, which may contribute towards inaccurate or complicated interpretations of the effects of viscosity ratio on relative permeabilities. Therefore, relative permeabilities by some authors, [14,16,17] as reported from their displacement tests using oil of high viscosity, confirm that surface forces were Figure 5. Effect of viscosity ratio on two-phase gas/liquid-relative permeability with varying temperature [14,16].…”

Section: Viscosity Ratiosupporting

confidence: 61%

“…Therefore, relative permeabilities by some authors, [14,16,17] as reported from their displacement tests using oil of high viscosity, confirm that surface forces were Figure 5. Effect of viscosity ratio on two-phase gas/liquid-relative permeability with varying temperature [14,16].…”

Section: Viscosity Ratiosupporting

confidence: 61%

“…The variation in viscosity ratio from ambient temperature to 40 °C did not affect relative permeability, but the relative permeability shape changed at 80 °C. The result demonstrated the alteration of the gas-relative permeability curve with temperature; however, the change was small and it can be argued that the variation in gas-relative permeability was within the experimental error [16].…”

Section: Viscosity Ratiomentioning

confidence: 81%

“…However, if the fundamental assumption, i.e., the fluid distribution in porous media is a capillary force-dominated phenomenon, the relative permeabilities should not change with the change in viscosity of a fluid (gas and oil), and hence, with the viscosity ratio. Moreover, the results presented by several authors [14,16,17,70] on the effect of temperature on two-phase gas/liquid-relative permeabilities due to change in viscosity ratio affirm that the fundamental assumption (i.e., capillary forces are controlling factor for fluid distribution) may not be a valid one. Several other researchers [56,57,59,[61][62], however, are not in agreement with this view.…”

Section: Viscosity Ratiomentioning

confidence: 99%

“…Modaresghazani [16] studied the effect of varying temperature on gas/water steady-state-and unsteady-state-relative permeability using water as the displaced phase and nitrogen gas as the displacing phase. The viscosity ratio decreased with increasing temperature.…”

Section: Viscosity Ratiomentioning

confidence: 99%

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Can Effects of Temperature on Two-Phase Gas/Oil-Relative Permeabilities in Porous Media Be Ignored? A Critical Analysis

et al. 2020

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Thermal recovery processes for heavy oil exploitation involve three-phase flow at elevated temperatures. The mathematical modeling of such processes necessitates the account of changes in the rock–fluid system’s flow behavior as the temperature rises. To this end, numerous studies on effects of the temperature on relative permeabilities have been reported in the literature. Compared to studies on the temperature effects on oil/water-relative permeabilities, studies (and hence, data) on gas/oil-relative permeabilities are limited. However, the role of temperature on both gas/oil and oil/water-relative permeabilities has been a topic of much discussion, contradiction and debate. The jury is still out, without a consensus, with several contradictory hypotheses, even for the limited number of studies on gas/oil-relative permeabilities. This study presents a critical analysis of studies on gas/oil-relative permeabilities as reported in the literature, and puts forward an undeniable argument that the temperature does indeed impact gas/oil-relative permeabilities and the other fluid–fluid properties contributing to flow in the reservoir, particularly in a thermal recovery process. It further concludes that such thermal effects on relative permeabilities must be accounted for, properly and adequately, in reservoir simulation studies using numerical models. The paper presents a review of most cited studies since the 1940s and identifies the possible primary causes that contribute to contradictory results among them, such as differences in experimental methodologies, experimental difficulties in flow data acquisition, impact of flow instabilities during flooding, and the differences in the specific impact of temperature on different rock–fluid systems. We first examined the experimental techniques used in measurements of oil/gas-relative permeabilities and identified the challenges involved in obtaining reliable results. Then, the effect of temperature on other rock–fluid properties that may affect the relative permeability was examined. Finally, we assessed the effect of temperature on parameters that characterized the two-phase oil/gas-relative permeability data, including the irreducible water saturation, residual oil saturation and critical gas saturation. Through this critical review of the existing literature on the effect of temperature on gas/oil-relative permeabilities, we conclude that it is an important area that suffers profoundly from a lack of a comprehensive understanding of the degree and extent of how the temperature affects relative permeabilities in thermal recovery processes, and therefore, it is an area that needs further focused research to address various contradictory hypotheses and to describe the flow in the reservoir more reliably.

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Section: Viscosity Ratiosupporting

confidence: 61%

Section: Viscosity Ratiosupporting

confidence: 61%

Section: Viscosity Ratiomentioning

confidence: 81%

Section: Viscosity Ratiomentioning

confidence: 99%

Section: Viscosity Ratiomentioning

confidence: 99%

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Can Effects of Temperature on Two-Phase Gas/Oil-Relative Permeabilities in Porous Media Be Ignored? A Critical Analysis

et al. 2020

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Effect of Temperature on Bitumen/Water Relative Permeability in Oil Sands

et al. 2020

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The steam-assisted gravity drainage (SAGD) process is among the most applicable thermal enhanced oil recovery (TEOR) methods in North American heavy oil reservoirs. In addition to improving oil mobility through viscosity reduction, the high-temperature condition that a TEOR method causes may significantly alter the fluid flow performance and behavior, as manifested by the relative permeability to fluids in the reservoir. Therefore, in a SAGD and cyclic steam stimulation (CSS), the relative permeabilities can change within the temperature-gradient region developed around the SAGD chamber or between two cycles of CSS processes. However, there is no unique two-phase relative permeability model, especially for bitumen systems to cover a wide range of temperatures. Therefore, the primary objective of this study is to history-match the results of the recent study done by Esmaeili et al. using a new methodology and to conduct limited steady-state relative permeability measurements at different temperatures to confirm the validity of displacement-based relative permeability curves and then to propose a reliable general relative permeability model as a function of temperature. Twelve history-matched bitumen/water relative permeability sets are obtained in a wide range of temperatures from 70 to 220 °C under a confining pressure higher than 1000 psi and the test pressure in the range of 350−400 psi. An in-house developed reservoir simulator was used to obtain relative permeability curves from isothermal displacement data using the history-matching approach. The results demonstrated that both production and pressure-drop data can be matched using the optimized values of parameters of the generalized Corey relative permeability model. Furthermore, a more reliable value for actual residual oil saturation was determined by applying our new methodology in history matching. A comparative analysis with the steady-state relative permeability data allowed us to determine the extent to which the unsteady-state relative permeability is affected by viscous fingering. A considerable shift in both oil and water relative permeability at higher temperatures is noticed. Furthermore, it is also noted that the endpoint relative permeability to oil and water is also altered significantly. The implicit relative permeability data obtained from this study are consistent with the results of the JBN method that were reported in our previous study. By making the parameters of the Corey relative permeability model dependent on temperature, a new model of temperature-dependent bitumen/water relative permeability in sand was developed. It is anticipated that this model can facilitate inclusion of temperature-dependent relative permeability in reservoir simulation studies.

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Dewatering Optimization of Coal Seam Gas Production Wells: A Review and Future Perspectives

et al. 2022

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Coal seam gas (CSG), as a type of unconventional gas resource, is playing an increasingly important role in energy generation and transition to renewables, as the world takes action to meet the climate change challenge. To produce CSG, the reservoir first needs to be dewatered, but unreasonable dewatering rates can lead to various unfavorable outcomes, such as a reduction in productivity, capillary trapping, borehole instability, excessive coal fines generation, and frequent production well workovers due to particle-induced damage to pumps. Determining the optimum dewatering strategy is currently in a very primitive stage of development, and CSG operators rely on empirical and instinctive approaches to deal with this problem. This paper conducts a comprehensive literature review to (i) explain why dewatering rate optimization remains a great challenge for the CSG industry, (ii) illustrate the complexity and nature of the issue through a conceptual model, and (iii) investigate four key factors that dominate the dewatering optimization design, borehole stability, stress-dependent permeability, gas–water two-phase flow, and generation of coal fines. A detailed summary of current dewatering optimization practices in CSG reservoirs is then presented, focusing on the employed theories, methodology, key learnings, and limitations of each practice. Finally, the remaining knowledge gaps are highlighted, and recommendations for further future work are provided.

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Determination of Two-Phase and Three-Phase Relative Permeabilities in Heavy Oil/Water/Gas Systems

Cited by 9 publications

References 12 publications

Can Effects of Temperature on Two-Phase Gas/Oil-Relative Permeabilities in Porous Media Be Ignored? A Critical Analysis

Can Effects of Temperature on Two-Phase Gas/Oil-Relative Permeabilities in Porous Media Be Ignored? A Critical Analysis

Effect of Temperature on Bitumen/Water Relative Permeability in Oil Sands

Dewatering Optimization of Coal Seam Gas Production Wells: A Review and Future Perspectives

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