Viscosity and phase behaviour of petroleum fluids with high asphaltene contents

Werner, Arite; Béhar, F.; Hemptinne, J.-C. de; Béhar, E.

doi:10.1016/s0378-3812(98)00245-3

Cited by 30 publications

(13 citation statements)

References 10 publications

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“…This led to a sharp increase in the viscosity from 0.29 to 4.5-61.2 mPa s, depending upon the proportion of the intermediates. 28 This is in line with the results obtained in the study (blending the heavy oil with condensate leads to a decrease in the oil viscosity). Asphaltenes may increase the viscosity because of their tendency to interact, coagulate, and form ensem-bles that are suspended in a large matrix of resins, aromatics, and saturates.…”

Section: Viscosity Reduction Of Heavysupporting

confidence: 91%

A Study of the Effect of Gas Condensate on the Viscosity and Storage Stability of Omani Heavy Crude Oil

et al. 2006

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Heavy crude oil (density of 0.9571 g/cm3 at 288 K and kinematic viscosity of 7160 mm2/s at 303 K) and natural gas condensate (density of 0.7848 g/cm3 at 288 K and kinematic viscosity of 0.764 mm2/s at 303 K) were sampled from Omani oil fields. The oil was mixed with condensate (5−50 vol %), and the mixture viscosities were measured at the temperature range of 293−348 K. A drastic decrease in kinematic viscosity was achieved. An addition of about 12 vol % of condensate gave a viscosity of 265 mm2/s at 303 K. This made it easier to transport the heavy oil mixtures. The experimental data for the kinematic viscosity [ν (mm2/s)] as a function of the gas-condensate fraction (φ) and temperature [T (K)] could be described by an equation: ln(ln(ν)) = (k 1 + k 2·T) + (k 3 + k 4·T)·φ, with a high accuracy. Blends of the heavy oil and the gas condensate were stored to evaluate their stability. Results showed less than 0.05 wt % sludge formation after 2 months.

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Section: Viscosity Reduction Of Heavysupporting

confidence: 91%

A Study of the Effect of Gas Condensate on the Viscosity and Storage Stability of Omani Heavy Crude Oil

et al. 2006

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“…Speight [36] and Branco et al [37] suggested precipitation of asphaltene as a function of carbon number of alkanes and reported that as the alkane carbon number increases, the precipitated amount of asphaltene decreases. Burke et al [38] and Werner et al [39] stated that CO 2 injection plays major role for asphaltene precipitation. Figure 6c shows the simulated ultimate oil recovery with corresponding field pressure response as function of mol% of CO 2 .…”

Section: Simulation: Effect Of Asphaltene Precipitation By Miscible Cmentioning

confidence: 99%

Enhanced Oil Recovery (EOR) by Miscible CO2 and Water Flooding of Asphaltenic and Non-Asphaltenic Oils

Chukwudeme

Hamouda

2009

Energies

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An EOR study has been performed applying miscible CO 2 flooding and compared with that for water flooding. Three different oils are used, reference oil (n-decane), model oil (n-C10, SA, toluene and 0.35 wt % asphaltene) and crude oil (10 wt % asphaltene) obtained from the Middle East. Stearic acid (SA) is added representing a natural surfactant in oil. For the non-asphaltenic oil, miscible CO 2 flooding is shown to be more favourable than that by water. However, it is interesting to see that for first years after the start of the injection (< 3 years) it is shown that there is almost no difference between the recovered oils by water and CO 2 , after which (> 3 years) oil recovery by gas injection showed a significant increase. This may be due to the enhanced performance at the increased reservoir pressure during the first period. Maximum oil recovery is shown by miscible CO 2 flooding of asphaltenic oil at combined temperatures and pressures of 50 °C/90 bar and 70 °C/120 bar (no significant difference between the two cases, about 1%) compared to 80 °C/140 bar. This may support the positive influence of the high combined temperatures and pressures for the miscible CO 2 flooding; however beyond a certain limit the oil recovery declined due to increased asphaltene deposition. Another interesting finding in this work is that for single phase oil, an almost linear relationship is observed between the pressure drop and the asphaltene deposition regardless of the flowing fluid pressure. OPEN ACCESSEnergies 2009, 2 715

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“…First of all, a compositional model for predicting the viscosity of petroleum fluids as a function of temperature and pressure is presented by Werner et al (1998). It is based on the original model, termed the Self-Reference Model, developed by Kanti et al (1989).…”

Section: The Transport Properties Prediction (Trapp) Program Of Ely Amentioning

confidence: 99%

Phase Behavior, Solid Organic Precipitation, and Mobility Characterization Studies in Support of Enhanced Heavy Oil Recovery on the Alaska North Slope

Patil¹,

Dandekar²,

Khataniar³

2008

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The medium-heavy oil (viscous oil) resources in the Alaska North Slope are estimated at 20 to 25 billion barrels. These oils are viscous, flow sluggishly in the formations, and are difficult to recover. Recovery of this viscous oil requires carefully designed enhanced oil recovery processes. Success of these recovery processes is critically dependent on accurate knowledge of the phase behavior and fluid properties, especially viscosity, of these oils under variety of pressure and temperature conditions. This project focused on predicting phase behavior and viscosity of viscous oils using equations of state and semi-empirical correlations.An experimental study was conducted to quantify the phase behavior and physical properties of viscous oils from the Alaska North Slope oil field. The oil samples were compositionally characterized by the simulated distillation technique. Constant composition expansion and differential liberation tests were conducted on viscous oil samples. Experiment results for phase behavior and reservoir fluid properties were used to tune the Peng-Robinson equation of state and predict the phase behavior accurately. A comprehensive literature search was carried out to compile available compositional viscosity models and their modifications, for application to heavy or viscous oils. With the help of meticulously amassed new medium-heavy oil viscosity data from experiments, a comparative study was conducted to evaluate the potential of various models. The widely used corresponding state viscosity model predictions deteriorate when applied to heavy oil systems. Hence, a semi-empirical approach (the Lindeloff model) was adopted for modeling the viscosity behavior. Based on the analysis, appropriate adjustments have been suggested: the major one is the division of the pressure-viscosity profile into three distinct regions. New modifications have improved the overall fit, including the saturated viscosities at low pressures. However, with the limited amount of geographically diverse data, it is not possible to develop a comprehensive predictive model. Based on the comprehensive phase behavior analysis of Alaska North Slope crude oil, a reservoir simulation study was carried out to evaluate the performance of a gas injection enhanced oil recovery technique for the West Sak reservoir. It was found that a definite increase in viscous oil production can be obtained by selecting the proper injectant gas and by optimizing reservoir operating parameters. A comparative analysis is provided, which helps in the decision-making process.iv

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Viscosity and phase behaviour of petroleum fluids with high asphaltene contents

Cited by 30 publications

References 10 publications

A Study of the Effect of Gas Condensate on the Viscosity and Storage Stability of Omani Heavy Crude Oil

A Study of the Effect of Gas Condensate on the Viscosity and Storage Stability of Omani Heavy Crude Oil

Enhanced Oil Recovery (EOR) by Miscible CO2 and Water Flooding of Asphaltenic and Non-Asphaltenic Oils

Phase Behavior, Solid Organic Precipitation, and Mobility Characterization Studies in Support of Enhanced Heavy Oil Recovery on the Alaska North Slope

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