A new mathematical model and experimental validation on foamy-oil flow in developing heavy oil reservoirs

Liu, Pengcheng; Mu, Zhenbao; Li, Wenhui; Wu, Yongbin; Li, Xiuluan

doi:10.1038/s41598-017-08882-2

Cited by 9 publications

(5 citation statements)

References 58 publications

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“…Lots of studies have been conducted to investigate the effect of external factors on foamy oil flow such as temperature and the pressure depletion rate. 26 However, little research is available on the effect of heavy oil itself. The objective of this research is to investigate the effect of oil viscosity and the solution gas–oil ratio on foamy oil flow based on sandpack experiments.…”

Section: Introductionmentioning

confidence: 99%

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Effects of Oil Viscosity and the Solution Gas–Oil Ratio on Foamy Oil Flow in Solution Gas Drive

Wang

Ma²,

Sun

2022

ACS Omega

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The anomalously high recovery of solution gas drive in some heavy oil reservoirs has been associated with foamy oil. The effects of external factors such as temperature, permeability, and the pressure depletion rate on foamy oil flow have been studied sufficiently, but few studies are available on the effect of heavy oil itself. In order to investigate the effect of oil viscosity and the solution gas–oil ratio on foamy oil, 11 tests of solution gas drive through a sandpack were carried out in this work. The results show that a typical foamy oil solution gas drive exists in three stages, which are the oil phase expansion stage, the foamy oil flow stage, and the oil–gas two-phase flow stage. As the oil viscosity decreases, the foamy oil flow stage shortens, resulting in reduced recovery of this stage significantly. In the experiment with an oil viscosity of 200 mPa·s, foamy oil flow was not observed. A lower limit of oil viscosity should exist for steady flow of foamy oil, which is considered to be approximately 600 mPa·s according to the experimental results. As the solution gas–oil ratio increases, the oil recovery first increases and then decreases. Foamy oil flow could be observed clearly when the solution gas–oil ratio was between 10 and 26 Sm 3 /m 3 , which indicates that there is an optimal range of solution gas–oil ratios for foamy oil solution gas drive. The test with a solution gas–oil ratio of 35 Sm 3 /m 3 showed that oil–gas two-phase flow followed the oil phase expansion stage as a result of the production of a quantity of gas, which illustrates that excess solution gas is unbeneficial to foamy oil flow on the contrary. The investigation revealed that oil viscosity and the solution gas–oil ratio are essential for foamy oil flow, which provides theoretical support for foamy oil production.

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Section: Introductionmentioning

confidence: 99%

“…Lots of studies have been conducted to investigate the effect of external factors on foamy oil flow such as temperature and the pressure depletion rate . However, little research is available on the effect of heavy oil itself.…”

Section: Introductionmentioning

confidence: 99%

Effects of Oil Viscosity and the Solution Gas–Oil Ratio on Foamy Oil Flow in Solution Gas Drive

Wang

Ma²,

Sun

2022

ACS Omega

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“…The observed performance from many heavy oil reservoirs in Canada, China, and Venezuela, such as the Orinoco Oil Belt, Lindbergh, and Tuha Fields, has been significantly better than that from conventional heavy oil reservoirs during primary production processes (Abusahmin et al 2017;Guan et al 2008;Maini 1999;Sun et al 2017aSun et al , 2019aZhou et al 2016). One of the possible reasons for this difference is the in situ foamy oil occurrence (the solution gas is trapped in the oil phase as dispersed bubbles) (Du et al 2016;Liu et al 2017;Sun et al 2014Sun et al , 2018aZhang et al 2015;Zhou et al 2017). However, the gas bubbles eventually become a continuous free gas due to low reservoir pressure.…”

Section: Introductionmentioning

confidence: 99%

Phase behavior of heavy oil–solvent mixture systems under reservoir conditions

et al. 2020

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A novel experimental procedure was proposed to investigate the phase behavior of a solvent mixture (SM) (64 mol% CH4, 8 mol% CO2, and 28 mol% C3H8) with heavy oil. Then, a theoretical methodology was employed to estimate the phase behavior of the heavy oil–solvent mixture (HO–SM) systems with various mole fractions of SM. The experimental results show that as the mole fraction of SM increases, the saturation pressures and swelling factors of the HO–SM systems considerably increase, and the viscosities and densities of the HO–SM systems decrease. The heavy oil is upgraded in situ via asphaltene precipitation and SM dissolution. Therefore, the solvent-enriched oil phase at the top layer of reservoirs can easily be produced from the reservoir. The aforementioned results indicate that the SM has promising application potential for enhanced heavy oil recovery via solvent-based processes. The theoretical methodology can accurately predict the saturation pressures, swelling factors, and densities of HO–SM systems with various mole fractions of SM, with average error percentages of 1.77% for saturation pressures, 0.07% for swelling factors, and 0.07% for densities.

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“…It is believed that the effect of temperature on foamy oil mainly results from the change in oil viscosity. The high viscosity of heavy oil is considered to be a key condition for the formation of foamy oil [29,30]. In heavy oil, a large viscous force can stably disperse micro-bubbles liberated from oil and reduce the possibility of coalescing.…”

Section: Introductionmentioning

confidence: 99%

Experimental Study and Mechanism Analysis of the Effect of Oil Viscosity and Asphaltene on Foamy Oil

Wang

2019

Energies

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Foamy oil is considered an important reason for the anomalous performance in depletion development for some heavy oil reservoirs, but its influence factors remain to be fully investigated. In order to determine the effect of oil viscosity and asphaltene on foamy oil, ten oil samples including two types (deasphalted oil and asphaltenic oil) and five viscosities were used in the work. On this basis, depletion experiments were conducted in a sandpack and microscopic visualization model. Then, viscoelastic moduli of the oil–gas interface were measured to analyze the mechanisms of viscosity and asphaltene of foamy oil from the perspective of interfacial viscoelasticity. Results show that, with the decrease of the oil viscosity, the foamy oil performance in depletion development worsened, including a rapider decline in average pressure, earlier appearance of gas channeling, shorter period of foamy oil, and lower contribution of foamy oil to recovery. Asphaltene had an influence on foamy oil only in the viscosity range between 870 mPa∙s and 2270 mPa∙s for this study. The effect of viscosity and asphaltene on foamy oil can be explained by the viscoelasticity of bubble film. With the increase of oil viscosity, the interfacial viscous modulus increases significantly, indicating the bubble film becomes stronger and more rigid. Asphaltene, like armor on the bubble film, can improve the viscoelastic modulus, especially at lower viscosity. This can inhibit the coalescence of micro-bubbles and increase the possibility of splitting. This work identifies the effects of oil viscosity and asphaltene on foamy oil systematically and provides theoretical support for foamy oil production.

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A new mathematical model and experimental validation on foamy-oil flow in developing heavy oil reservoirs

Cited by 9 publications

References 58 publications

Effects of Oil Viscosity and the Solution Gas–Oil Ratio on Foamy Oil Flow in Solution Gas Drive

Effects of Oil Viscosity and the Solution Gas–Oil Ratio on Foamy Oil Flow in Solution Gas Drive

Phase behavior of heavy oil–solvent mixture systems under reservoir conditions

Experimental Study and Mechanism Analysis of the Effect of Oil Viscosity and Asphaltene on Foamy Oil

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