Asphaltenes are the n-pentane or n-heptane insoluble fractions of crude oil that remain in solution under reservoir temperature and pressure conditions. They are destabilized and start to precipitate when the pressure, temperature, and/or composition changes occur during primary production. The precipitated asphaltene particles will then grow in size, and may start to deposit onto the production string and/or flowlines, causing operational problems.

In this paper, our emphasis is to identify the first pressure and/or temperature conditions at which the asphaltene will start to precipitate for two reservoir oils. Four different laboratory techniques were independently used to define the onset of the asphaltene precipitation envelope. These methods are:

  1. gravimetric;

  2. acoustic resonance;

  3. light scattering; and

  4. filtration. The gravimetric method was found to be precise, and within the accuracy of the analytical methods. However, the method was time consuming. The acoustic resonance technique (ART) was fast and less subjective, but it did not define the lower asphaltene boundary. The interpretation of the onset pressure from the near-infrared (NIR) light-scattering technique (LST) was subjective to a degree. However, the NIR response defined the upper and lower boundaries of the asphaltene envelope and the bubblepoint pressure, as did the gravimetric technique. In a manner similar to those of the gravimetric technique and LST, the filtration technique can also define the upper and lower asphaltene phase boundaries, in addition to the bubblepoint pressure. The filtration technique is fast compared to the gravimetric technique, but takes more time than the ART and LST methods.


Asphaltenes remain in solution under reservoir temperature and pressure conditions. They start to precipitate when the stability of the colloidal dispersion is disturbed. This disturbance can be caused by changes in pressure, temperature, and/or composition of the oil.

Precipitation and deposition of asphaltenes have reportedly caused operational problems, ranging from plugging of tubulars and flowlines(1–3) to clogging of production separators(4). Leontaritis and Mansoori present a comprehensive description of field problems caused by asphaltene deposition(5). Figure 1 schematically presents the asphaltene-related problems that may occur in the field. Asphaltene precipitation problems can be categorized as follows:

  • Precipitation can be caused by the changes in temperature and/or pressure during primary depletion.

  • Precipitation can be caused by blending or commingling of two noncompatible reservoir fluid streams (i.e., subsea completions), acid stimulation and/or enhanced recovery injection gases (CO2, H2S, or rich gas).

The correct operating procedure to minimize the asphaltene problem is not well understood. We believe a better understanding of the fundamental processes leading to solids precipitation is a prerequisite to management and prevention of production problems.

Primarily, two theoretical approaches have been presented in the literature to compute phase separations of asphaltene during primary production. These approaches include association modeling(6, 7) and calculation of asphaltene solubility parameters with the Flory Huggins polymer phase separation technique.(8, 9) Asphaltene destabilization caused by solvent injection and consequent alteration of the rock surface wettability have also been reported in the literature, but are not discussed here.(10).

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