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

Wang, Zhuangzhuang; Li, Zhaomin; Lu, Teng

doi:10.3390/en12040761

Cited by 6 publications

(3 citation statements)

References 37 publications

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“…Although the diluting method would change the content of four components in oil and then affect the foamy oil formation and performance to a certain extent, this effect is small compared with the influence of oil viscosity. On the one hand, we know from our previous study that oil viscosity is the dominant factor affecting foamy oil, the effect of which is much larger than that of asphaltenes, and on the other hand, we can see from Table that the content change of four components in oil caused by the naphtha addition was relatively little. Therefore, the difference in foamy oil performance can be attributed mainly to the change of oil viscosity.…”

Section: Methodsmentioning

confidence: 79%

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: Methodsmentioning

confidence: 79%

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 results manifested that the bubble size in the foams makes a difference with the viscosity and surface tension. Foamy oil was studied by Wang et al, 17 who looked into the role of asphaltenes and oil viscosity. The results reveal that as the oil viscosity increases, the interfacial viscous modulus also rises dramatically, which means the interfacial film becomes more robust and rigid.…”

Section: Introductionmentioning

confidence: 99%

Effects of Pressure and Depressurization Rate of Dissolved CO₂ on the Foaming Characteristics of Crude Oil

et al. 2023

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With the CO 2 flooding technique implemented, much CO 2 gas is dissolved in the produced fluid. A large amount of CO 2 escapes from crude oil due to continual depressurization in the surface pipeline system, leading to massive foam. In this paper, the effects of dissolved-CO 2 pressure and depressurization rate on foaming characteristics were investigated by depressurization. To explore the mechanism in depth, CO 2 solubility and interfacial characteristics were considered. The results indicated that foamability increases as the pressure increases and increases initially and then decreases with an increase in the rate. Further experimental results showed that when the pressure increases from 1.5 to 3.0 MPa at 30 °C, equilibrium interfacial tension decreases only by 12.78%, while CO 2 solubility increases by 81.73%, indicating that CO 2 solubility plays a dominant role in foamability. Additionally, it is inferred that when the rate is lower than 18 L/min, it increases at which point the gas that is originally dissolved inside the crude oil transforms to free gas. When it is increased above 18 L/min, the decrease in the solubility and enhancement of disturbance appear. These may be reasons why foamability decreases. Meanwhile, foam stability, the decay degree of foam height over time, was measured immediately after the foam height reached maximum. It was found that foam stability decreases when the pressure increases and increases initially and then decreases when the rate elevates. Further experimental results indicated that when the pressure increases from 1.5 to 3.0 MPa at 30 °C, the bulk viscosity and interfacial dilational modulus decrease by 23.45 and 38.58%, respectively. It is suggested that the role of interfacial viscoelasticity in foam stability is superior to that of viscosity. Additionally, it was inferred the increased rate below 18 L/min makes bubble size smaller, while the weaker structure of the foam film and higher surface energy make foam stability worse with the rate increased above 18 L/min.

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“…In previous studies, the sandbag model was most commonly used to test the Huff-n-Puff process. ,,− Ahadi used a sandbag model with a porosity of 32.3% to investigate the recovery capacity of CH 4 /C 3 H 8 mixed solvents in the CSI process. The results showed that there was an optimal ratio when C 3 H 8 was added to CH 4 , and the ultimate recovery factor did not increase significantly after the concentration was exceeded.…”

Section: Introductionmentioning

confidence: 99%

Molecular Insight into the Extraction Behaviors of Confined Heavy Oil in the Nanopore by CO₂/C₃H₈in Huff-n-Puff Process

Liu

Zhang

et al. 2022

Energy Fuels

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The residual oil present in localized low-permeability pores in heavy oil reservoirs is a limiting factor in oil recovery. In this study, molecular simulations were used to comprehensively describe the flow mechanisms and potential performance when using CO 2 and C 3 H 8 as solvents to assist the extraction of oil in quartz nanopores. We showed that CO 2 and C 3 H 8 effectively reduced residual oil in pores during the soaking stage. The adsorption of CO 2 on the SiO 2 surface broke the heavy oil away from it, significantly reducing interaction between the surface and the oil and allowing it to flow out. C 3 H 8 broke heavy oil down into individual molecules or small clusters, aiding the oil to flow out of the pore. With insufficient soaking, the reflux phenomenon of oil during the depletion stage caused a high residual oil amount for both the CO 2 and C 3 H 8 simulations. With sufficient soaking within the CO 2 simulation, the CO 2 desorbed from the surface and escaped from the oil, generating a gas phase within the pore that provided a driving force to push the oil out. Sufficient soaking within the C 3 H 8 simulation did not significantly change the amount of residual oil during the depletion stage. The adhesion of residual oil on the pore surface prevented the oil from flowing out of the pore with C 3 H 8 . The synergistic behavior of the CO 2 /C 3 H 8 mixture was explored to better understand the advantages of combining different solvent extraction mechanisms. A combination of 70% CO 2 + 30% C 3 H 8 effectively extracted heavy oil during the soaking stage and had the best recovery in the depletion stage. This study revealed the mechanism of flow interaction between solvents and heavy oil under confined conditions at the molecular level. Furthermore, this study provides helpful information to guide the enhancement of heavy oil recovery.

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

Cited by 6 publications

References 37 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

Effects of Pressure and Depressurization Rate of Dissolved CO₂ on the Foaming Characteristics of Crude Oil

Molecular Insight into the Extraction Behaviors of Confined Heavy Oil in the Nanopore by CO₂/C₃H₈in Huff-n-Puff Process

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

Cited by 6 publications

References 37 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

Effects of Pressure and Depressurization Rate of Dissolved CO2 on the Foaming Characteristics of Crude Oil

Molecular Insight into the Extraction Behaviors of Confined Heavy Oil in the Nanopore by CO2/C3H8in Huff-n-Puff Process

Contact Info

Product

Resources

About

Effects of Pressure and Depressurization Rate of Dissolved CO₂ on the Foaming Characteristics of Crude Oil

Molecular Insight into the Extraction Behaviors of Confined Heavy Oil in the Nanopore by CO₂/C₃H₈in Huff-n-Puff Process