The Effect of Methane on Asphaltene Precipitation

Asphaltenes are the heaviest, most polar, and most aromatic fraction of crude oil and can form a separate phase from the crude oil due to changes in pressure, temperature, or oil composition [1]. Asphaltene precipitation is usually undesirable because it can lead to formation damage and fouling of pipelines and production facilities. However, it is a key step in some processes such as deasphalting. In either case, it is necessary to identify the conditions at which asphaltenes begin to precipitate and in some cases the amount of precipitation. Two well-known situations where asphaltene precipitation can occur during the production and processing of crude oils are: 1) diluting a heavy oil with an incompatible solvent (e.g. an n-alkane); 2) depressurizing a light conventional oil. In situ heavy and live conventional oils both contain dissolved gases, particularly methane, which have a significant negative impact on the oil's ability to solubilize asphaltenes [2, 3].

One approach to modeling asphaltene precipitation is the modified regular solution (MRS) liquid-liquid equilibrium model. The MRS model has been used previously to model asphaltene precipitation from heavy oils and bitumen diluted with n-alkanes at different temperature and pressures [4]. The oils are characterized into SARA fractions (saturates, aromatics, resins, and pentane insoluble asphaltenes which are termed C₅-asphaltenes). The inputs parameters for the model are the mole fraction, molar volume and solubility parameter for each SARA fraction and each solvent. The current version of the regular solution model is not yet able to predict asphaltene solubility in the presence of dissolved gases because it lacks accurate solubility parameters of these dissolved gases. The objective of this project is to quantify and model the effect of methane on asphaltene solubility and, in particular, to determine the solubility parameter of the dissolved methane.

The solubility parameters for a solvent can be determined by fitting a Modified Regular Solution model (MRS) to the asphaltene yield curves from heavy oil diluted with the solvent of interest. A yield curve is a plot of the yield (mass of precipitated divided by mass of feed oil) versus the mass fraction of solvent in the mixture. However, the methane solubility in a bitumen is too low to trigger asphaltene precipitation. Instead, the methane solubility parameter was determined from asphaltene yield curves for mixtures of bitumen, n-pentane, and methane. The properties of the bitumen and n-pentane required for the MRS model have already been established [5]. The density of the dissolved methane was determined using an effective density correlation. Therefore, the only unknown property was the solubility parameter the dissolved methane.

The solvent content at which a heavy asphaltene-rich liquid phase formed (onset) and the asphaltene precipitation yield were determined for mixtures of bitumen, n-pentane, and methane at temperatures from 20 to 130 °C and pressures from 10 to 60 MPa. The onsets were visually detected in a High-Pressure Microscope [6] from titrations of bitumen with a mixture of methane and n-pentane. Asphaltene yields were measured in a blind cell PVT apparatus following established procedures [7].

The measured onsets were lower than onsets in pure n-pentane at similar conditions, confirming that asphaltenes are less soluble in methane than in n-pentane. The C₅-asphaltene yields were the same at all conditions, suggesting that all of the C₅-asphaltenes partitioned into the heavy phase at all of the experimental conditions. The data collected to date were modeled and fitted with a methane solubility parameter of approximately 8.5 MPa^0.5. This value is much lower than solubility parameter of n-pentane (14.4 MPa^0.5) and is consistent with the significantly poorer solubility of asphaltenes in methane. The effect of temperature and pressure on the methane solubility parameter will be discussed. The impact of methane content on the onset of asphaltene precipitation will be illustrated.

References

[1] A. K. Tharanivasan, H. W. Yarranton, and S. D. Taylor, “Application of a regular solution-based model to asphaltene precipitation from live oils,” Energy and Fuels, vol. 25, no. 2, pp. 528–538, 2011.

[2] S. A. M. Dehghani, M. V. Sefti, and G. A. Mansoori, “Simulation of natural depletion and miscible gas injection effects on asphaltene stability in petroleum reservoir fluids,” Pet. Sci. Technol., vol. 25, no. 11, pp. 1435–1446, 2007.

[3] P. Zanganeh, H. Dashti, and S. Ayatollahi, “Comparing the effects of CH4, CO2, and N2 injection on asphaltene precipitation and deposition at reservoir condition: A visual and modeling study,” Fuel, vol. 217, no. January, pp. 633–641, 2018.

[4] K. Akbarzadeh, H. Alboudwarej, W. Y. Svrcek, and H. W. Yarranton, “A generalized regular solution model for asphaltene precipitation from n-alkane diluted heavy oils and bitumens,” Fluid Phase Equilib., vol. 232, no. 1–2, pp. 159–170, 2005.

[5] F. Ramos-Pallares and H. W. Yarranton, “Extending the modified regular solution model to predict component partitioning to the asphaltene-rich phase,” Energy and Fuels, 2020.

[6] P. Agrawal, F. F. Schoeggl, M. A. Satyro, S. D. Taylor, and H. W. Yarranton, “Measurement and modeling of the phase behavior of solvent diluted bitumens,” Fluid Phase Equilib., vol. 334, pp. 51–64, 2012.

[7] K. A. Johnston, F. F. Schoeggl, M. A. Satyro, S. D. Taylor, and H. W. Yarranton, “Phase behavior of bitumen and n-pentane,” Fluid Phase Equilib., vol. 442, pp. 1–19, 2017.