Solubility of n-Butane in Athabasca Bitumen and Saturated Densities and Viscosities at Temperatures Up to 200°C

Summary The steam- and/or solvent-based recovery processes are efficient methods for recovery of heavy and extraheavy oils. The performance of these techniques depends on the amount of solvent dissolved in the oil and the variation of oil viscosity with temperature. Thus, full understanding of the quantitative effects of the solvent on heavy-oil viscosity and phase behavior is crucial for feasibility studies, design, and prediction of field-scale processes. Phase-behavior study of bitumen diluted with heavy hydrocarbon solvents, such as butane and pentane, has gained less attention in recent years. These solvents, as good candidates for recently developed recovery methods such as expanding solvent steam-assisted gravity drainage (ES-SAGD), could provide promising oil-production rates. Thus, the aim of this research is the development of an understanding of the phase behavior of n-butane/Athabasca-bitumen mixtures. It includes both experimental and modeling studies of solubilities and saturated liquid densities and viscosities over wide ranges of temperatures (up to 200 °C) and pressures (up to 8 MPa). Experimental results indicate that the dissolved n-butane in bitumen leads to a significant oil-viscosity reduction, and the effect is more pronounced at lower temperatures and/or higher pressures. The modeling results show that the measured solubilities are adequately represented by the Peng-Robinson equation of state (EOS) with an average absolute relative deviation (AARD) of 9.7%. The saturated liquid densities are also correlated with both the EOS and the effective liquid-density approach with 0.86 and 0.55% AARDs, respectively. The viscosity data are reasonably matched with Pedersen corresponding state.

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High-Pressure Data and Modeling Results for Phase Behavior and Asphaltene Onsets of Gulf of Mexico Oil Mixed With Nitrogen

SPE Reservoir Evaluation & Engineering ◽

10.2118/166097-pa ◽

2014 ◽

Vol 17 (03) ◽

pp. 384-395 ◽

Cited By ~ 4

Author(s):

Odd Steve Hustad ◽

Na Jia ◽

Karen Schou Pedersen ◽

Afzal Memon ◽

Sukit Leekumjorn

Keyword(s):

High Pressure ◽

Gulf Of Mexico ◽

Phase Behavior ◽

Oil Recovery ◽

Positive Impact ◽

Viscosity Reduction ◽

Fluid Composition ◽

Viscosity Data ◽

Oil Viscosity ◽

Reservoir Fluid

Summary This paper presents fluid composition, high-pressure pressure/volume/temperature (PVT) measurements, and equation-of-state (EoS) modeling results for a recombined Tahiti oil, Gulf of Mexico (GoM), and for the oil mixed with nitrogen in various concentrations. The data include: Upper and lower asphaltene onset pressures and bubblepoint pressures for the reservoir fluid swelled with nitrogen. At the reservoir conditions of 94 MPa (13,634 psia) and 94°C (201.2°F), asphaltene precipitation is seen after the addition of 27 mol% of nitrogen. Viscosity data for the swelled fluids showing that the addition of nitrogen significantly reduces the oil viscosity. Slimtube runs indicating that the minimum miscibility pressure (MMP) of the oil with nitrogen is significantly higher than estimated from published correlations. The data were modeled with the volume-corrected Soave-Redlich-Kwong (SRK) EoS and the perturbed-chain statistical association fluid theory (PC-SAFT) EoS. Although both equations provide a good match of the PVT properties of the reservoir fluid, PC-SAFT is superior to the SRK EoS for simulating the upper asphaltene onset pressures and the liquid-phase compressibility of the reservoir fluid swelled with nitrogen. Nitrogen-gas flooding is expected to have a positive impact on oil recovery because of its favorable oil-viscosity-reduction and phase behavior effects.

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Measurement and Modeling of Solubility and Saturated-Liquid Density and Viscosity for Methane/Athabasca-Bitumen Mixtures

SPE Journal ◽

10.2118/174558-pa ◽

2016 ◽

Vol 21 (01) ◽

pp. 180-189 ◽

Cited By ~ 16

Author(s):

Hossein Nourozieh ◽

Mohammad Kariznovi ◽

Jalal Abedi

Keyword(s):

Phase Behavior ◽

Elevated Temperatures ◽

Equilibrium Concentration ◽

Solubility Data ◽

Viscosity Reduction ◽

Binary Interaction ◽

Liquid Density ◽

Athabasca Bitumen ◽

Wide Range ◽

Experimental Apparatus

Summary In the steam-based recovery processes, the coinjected gas can dissolve and diffuse into bitumen or heavy oil for viscosity reduction. The equilibrium concentration and solubility of methane are governed by the complex interaction with the bitumen. Thus, it is necessary to know the quantitative effects of gas dissolution on bitumen viscosity, density, and phase behavior at elevated temperatures in which steam-based processes are applied. Thus, this study aims at providing necessary experimental data for methane/Athabasca bitumen over a wide range of temperatures and pressures (up to 190°C and 10 MPa); that is, conditions that approach the temperatures at in-situ steam processes. Our previously designed phase-behavior experimental apparatus was used to measure the solubility of methane in Athabasca bitumen and its corresponding saturated-phase properties. Then, the measured solubility and density data were modeled with the Peng-Robinson equation of state (EOS) (Robinson and Peng 1978). The results indicate that the effect of temperature on the solubility profile of the methane/Athabasca-bitumen mixture is negligible at high temperatures and there is a distinct difference in the solubility data at 50°C compared with other isotherms (100, 150, and 190°C). Therefore, a reduction in viscosity at higher temperatures is much lower compared with a similar reduction at low temperature (50°C). There is a linear relationship between the methane-saturated viscosity and pressure for all temperatures in a semilog plot. The EOS modeling results also show that temperature-dependent binary-interaction parameters and volume-translation values should be considered to match density and solubility data.

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A Phase-Behavior Study for n-Hexane/Bitumen and n-Octane/Bitumen Mixtures

SPE Journal ◽

10.2118/186097-pa ◽

2017 ◽

Vol 23 (01) ◽

pp. 128-144 ◽

Cited By ~ 10

Author(s):

Jianyi Gao ◽

Ryosuke Okuno ◽

Huazhou Andy Li

Keyword(s):

Phase Behavior ◽

Potential Method ◽

Experimental Program ◽

Solvent Mixtures ◽

Asphaltene Precipitation ◽

Athabasca Bitumen ◽

Steam Assisted Gravity Drainage ◽

Behavior Study ◽

Boundary Measurements ◽

Rich Liquid

Summary Steam/solvent coinjection has been studied as a potential method to improve the efficiency of conventional steam-assisted gravity drainage (SAGD) for bitumen recovery. This research is part of an experimental program for phase behavior of Athabasca-bitumen/solvent mixtures. This paper presents a new set of experimental data for phase equilibrium, viscosity, density, and asphaltene precipitation for 11 mixtures of Athabasca bitumen with n-hexane and 10 mixtures of the same bitumen with n-octane. Phase-boundary measurements were conducted at temperatures up to 160°C and pressures up to 10 MPa. The bitumen sample used in this research was studied in our previous research, in which the same bitumen was not effectively diluted by n-butane because of the coexistence of a butane-rich liquid with a bitumen-rich liquid phase. In this research, the liquid/liquid separation of hydrocarbons was not observed for n-hexane/bitumen (HB) and n-octane/bitumen (OB) mixtures for the range of temperatures and pressures tested, even at solvent concentrations higher than 90 mol%. This observation indicates that the amount of solvent available near the edge of a steam chamber is expected to be entirely used for bitumen dilution beyond the chamber edge in coinjection of steam with heavier hydrocarbon solvents, such as n-hexane and n-octane. Experiments for asphaltene precipitation at atmospheric pressure showed a larger amount of precipitates with n-hexane than with n-octane at a given solvent concentration higher than 50 wt%. For solvent concentrations less than 50 wt%, no asphaltene precipitation was observed for both solvents with the bitumen sample tested in this research.

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Nonlinear Double-Log Mixing Rule for Viscosity Calculation of Bitumen/Solvent Mixtures Applicable for Reservoir Simulation of Solvent-Based Recovery Processes

SPE Journal ◽

10.2118/203823-pa ◽

2020 ◽

Vol 25 (05) ◽

pp. 2648-2662

Author(s):

Hossein Nourozieh ◽

Ehsan Ranjbar ◽

Anjani Kumar ◽

Kevin Forrester ◽

Mohsen Sadeghi

Keyword(s):

Reservoir Simulation ◽

Heavy Oil ◽

Viscosity Reduction ◽

Viscosity Data ◽

Solvent Mixtures ◽

Mixing Rule ◽

Arrhenius Model ◽

Recovery Processes ◽

Mixture Phase ◽

Mixture Viscosity

Summary Various solvent-based recovery processes for bitumen and heavy-oil reservoirs have gained much interest in recent years. In these processes, viscosity reduction is attained not only because of thermal effects, but also by dilution of bitumen with a solvent. Accurate characterization of the oil/solvent-mixture viscosity is critical for accurate prediction of recovery and effectiveness of such processes. There are varieties of models designed to predict and correlate the mixture viscosities. Among them, the linear log mixing (Arrhenius) model is the most commonly used method in the oil industry. This model, originally proposed for light oils, often show poor performance (40 to 60% error) when applied to highly viscous fluids such as heavy oil and bitumen. The modified Arrhenius model, called the nonlinear log mixing model, gives slightly better predictions compared with the original Arrhenius model. However, the predictions still might not be acceptable because of large deviations from measured experimental data. Calculated mixture-phase viscosity has a significant effect on flow calculations in commercial reservoir simulators. Underestimation of mixture viscosities leads to overprediction of oil-production rates. Using such mixing models in reservoir simulation can lead to inaccuracy in mixture viscosities and hence large uncertainty in model results. In the present study, different correlations and mixing rules available in the literature are evaluated against the mixture-viscosity data for a variety of bitumen/solvent systems. A new form (nonlinear) of the double-log mixing rule is proposed, which shows a significant improvement over the existing models on predicting viscosities of bitumen/solvent mixtures, especially at high temperatures.

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Density and Viscosity of Athabasca Bitumen Samples at Temperatures Up to 200°C and Pressures Up to 10 MPa

SPE Reservoir Evaluation & Engineering ◽

10.2118/176026-pa ◽

2015 ◽

Vol 18 (03) ◽

pp. 375-386 ◽

Cited By ~ 25

Author(s):

Hossein Nourozieh ◽

Mohammad Kariznovi ◽

Jalal Abedi

Keyword(s):

Oil Recovery ◽

Viscosity Data ◽

Vapor Extraction ◽

Absolute Deviation ◽

Athabasca Bitumen ◽

Steam Assisted Gravity Drainage ◽

Recovery Processes ◽

Wide Range ◽

Maximum Absolute Deviation ◽

Temperature And Pressure

Summary This paper presents the measurements of bitumen thermophysical properties (density and viscosity) over a wide range of temperatures (ambient to 200°C) and pressures (atmospheric to 14 MPa). The measurements have been conducted on three Athabasca bitumen samples taken from different locations. A new method was proposed to correlate the density data as a function of temperature and pressure, with a maximum absolute deviation of 1.7 kg/m3. The viscosity data were also correlated with two correlations available in literature considering the effect of pressure and temperature on viscosity of bitumen, with an average absolute relative deviation of 9.2%. The measured data and correlations are applicable for the prediction and optimization of oil recovery in the solvent- and thermal-based bitumen-recovery processes such as expanding- solvent steam assisted gravity drainage (ES-SAGD) and heated vapor extraction (VAPEX).

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Viscosity Measurement and Modeling for Mixtures of Athabasca Bitumen/n-Pentane at Temperatures Up to 200°C

SPE Journal ◽

10.2118/170252-pa ◽

2014 ◽

Vol 20 (02) ◽

pp. 226-238 ◽

Cited By ~ 12

Author(s):

Hossein Nourozieh ◽

Mohammad Kariznovi ◽

Jalal Abedi

Keyword(s):

Heavy Oil ◽

Volume Fraction ◽

Weight Fraction ◽

Viscosity Reduction ◽

Athabasca Bitumen ◽

Recovery Processes ◽

Correlation Models ◽

In Situ Recovery ◽

Recovery Methods

Summary The phase-behavior and thermophysical properties of bitumen/solvent systems are of crucial importance for heavy-oil and bitumen in-situ recovery methods. The viscosity reduction as a result of solvent dissolution and/or steam heating is the main recovery mechanism in the solvent-based bitumen-recovery processes. In this paper, the viscosity of bitumen, pentane, and their mixtures at different pentane weight fractions (0.05, 0.1, 0.2, 0.3, 0.4, and 0.5) are accurately measured. The measurements are conducted under conditions applicable for both in-situ recovery methods and the pipeline transportation of heavy oil. The experiments are taken with Athabasca bitumen at temperatures varying from ambient up to 200°C and at pressures up to 10 MPa. The data for the mixtures are evaluated with predictive schemes as well as with correlation models representing certain mixing rules proposed in the literature. The influences of pressure, temperature, and solvent weight fraction on the viscosity of mixtures are considered in the models and evaluated from the experimental data. The results indicated that the power-law model and the Cragoe model (Cragoe 1933) represent the data better than other models that use a volume-fraction basis.

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Investigation of amplification process of heavy oil viscosity reduction device based on jet cavitation using lab experimental and numerical simulation method

Energy Sources Part A Recovery Utilization and Environmental Effects ◽

10.1080/15567036.2021.1940388 ◽

2021 ◽

pp. 1-21

Author(s):

Xuedong Liu ◽

Wei Jiang ◽

Shuqi Cui ◽

Wenming Liu ◽

Yutong Gu ◽

...

Keyword(s):

Numerical Simulation ◽

Heavy Oil ◽

Simulation Method ◽

Viscosity Reduction ◽

Oil Viscosity ◽

Numerical Simulation Method ◽

Amplification Process

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Prediction of Dead Oil Viscosity: Machine Learning vs. Classical Correlations

Energies ◽

10.3390/en14040930 ◽

2021 ◽

Vol 14 (4) ◽

pp. 930

Author(s):

Fahimeh Hadavimoghaddam ◽

Mehdi Ostadhassan ◽

Ehsan Heidaryan ◽

Mohammad Ali Sadri ◽

Inna Chapanova ◽

...

Keyword(s):

Machine Learning ◽

Viscosity Data ◽

Oil Viscosity ◽

Pvt Data ◽

Proposed Model ◽

Wide Range ◽

Engineering Problems ◽

Functional Forms ◽

Insight Into

Dead oil viscosity is a critical parameter to solve numerous reservoir engineering problems and one of the most unreliable properties to predict with classical black oil correlations. Determination of dead oil viscosity by experiments is expensive and time-consuming, which means developing an accurate and quick prediction model is required. This paper implements six machine learning models: random forest (RF), lightgbm, XGBoost, multilayer perceptron (MLP) neural network, stochastic real-valued (SRV) and SuperLearner to predict dead oil viscosity. More than 2000 pressure–volume–temperature (PVT) data were used for developing and testing these models. A huge range of viscosity data were used, from light intermediate to heavy oil. In this study, we give insight into the performance of different functional forms that have been used in the literature to formulate dead oil viscosity. The results show that the functional form f(γAPI,T), has the best performance, and additional correlating parameters might be unnecessary. Furthermore, SuperLearner outperformed other machine learning (ML) algorithms as well as common correlations that are based on the metric analysis. The SuperLearner model can potentially replace the empirical models for viscosity predictions on a wide range of viscosities (any oil type). Ultimately, the proposed model is capable of simulating the true physical trend of the dead oil viscosity with variations of oil API gravity, temperature and shear rate.

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