Measurement and Modeling of Asphaltene Precipitation from Crude Oil Blends

Abstract

A previously developed regular solution model was adapted to predict the onset and amount of asphaltene precipitation from crude oil blends diluted with pure n-alkanes or a mixture of toluene and n-heptane. Tests were conducted on nine different crude oils, a gas oil, and their blends. Oils and blends were characterized in terms of SARA (saturates, aromatics, resins, and asphaltenes) fractions. The mass fraction of each SARA fraction in the blends was confirmed as a weight average of the respective fraction in constituent oils. Asphaltenes were subdivided into fractions based on the gamma function to account for the distribution of aggregates resulting from self-association. To model the asphaltene onset and yield, liquid−liquid equilibrium was assumed between a heavy (asphaltenic) and a light (nonasphaltenic) phase. The distribution of asphaltenes in unblended crude oils was determined by fitting its asphaltene yield data when diluted with n-heptane. The fitting parameter in the model was the average aggregation number of asphaltenes in the source oils. Two approaches were tested to calculate the distribution of asphaltenes in crude oil blends. In the first approach, asphaltenes were assumed to interact, and the final molar mass distribution was determined from gamma function using the average aggregation number of constituent oils. In the second approach, no interaction was assumed, and the final distribution was calculated as a sum of the individual distributions. It was found that the best predictions of the onset and yield data were obtained by using the second approach. The mass fraction of n-heptane required to initiate precipitation was predicted with an average absolute deviation of 0.53% or less in all cases.

Asphaltene Precipitation from Crude Oils in the Presence of Emulsified Water

“…The Athabasca bitumen and topped light crude oil are henceforth referred to as samples 1 and 2, respectively. Saturates, aromatics, resins, and asphaltenes (SARA) analysis was performed on each sample using a modified American Society for Testing and Materials (ASTM) method 11 (Table 1). The water content of samples 1 and 2 was determined by Karl Fischer titration and found to be 0.5 and 0.4 wt %, respectively.…”

Interpretation of DFA Color Gradients in Oil Columns Using the Flory-Huggins Solubility Model

“…The probability density function, p(x), is expressed as where M avg is the average molar mass of asphaltenes and α can be determined by fitting experimental data of asphaltene distributions. For asphaltenes and bitumens, Tharanivasan et al (2009) found α = 3.5. We also used this value in this paper.…”

“…However, there still exist uncertainties in the characterization of asphaltenes. On the other hand, the Flory-Huggins regular solution model has been largely and successfully employed to model asphaltene precipitation (flow assurance) issues (Akbarzadeh et al 2004;Alboudwarej et al 2003;Wang and Buckley 2001;Mohammadi and Richon 2007;Tharanivasan et al 2009). Nevertheless, the PC-SAFT EOS and the Flory-Huggins type of solubility model have not been extended to modeling asphaltene distributions in oil columns.…”

Aggregation thermodynamics for asphaltene precipitation

“…For examples, asphaltene precipitation may occur and plug up wellbores or transfer pipelines due to temperature and pressure differences between underground reservoir and surface atmosphere . Techniques for enhanced oil recovery, that is, gas or CO 2 injection, and blending of petroleum from different wells may also cause asphaltene precipitation due to the liquid phase composition change. Besides the adverse effects during upstream production and midstream transportation, asphaltene precipitation may also lead to fouling in downstream unit operations and catalysts poisoning in fluidized cracker .…”