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The heavy oil rim of a large Saudi Arabian oilfield has been shown to be in vertical and lateral equilibrium, matching predictions of the gravity term from the Flory-Huggins-Zuo equation of state for asphaltenes in the form of 5.2 nm clusters of the Yen-Mullins model. The large (10x) vertical gradient of asphaltene concentration over a very large perimeter (>> 10 km) of the oilfield provided a stringent test of this equation of state fit. Two-dimensional gas chromatography (GC×GC) and stable isotope analysis δD and δ 13 C were used to determine consistency of the liquid phase components with equilibration and the effects of biodegradation or thermal maturity on the observed asphaltene gradient. These analyses confirm homogeneity of equilibrated liquid phase components of similar chemical character and equilibrated asphaltene isotopes. Biodegradation is minimal and there is no maturity variation among the samples. Thus, the large asphaltene gradient did not result from these secondary processes and is not remnant from how the reservoir charged with crude oil. The results are consistent with original findings that the oil column is equilibrated. Thermodynamic equilibration over such large distances (>10 km) requires convective currents and provides constraints on fluid dynamic processes in reservoirs. A simple 1-D three-component single-phase model is introduced to account for asphaltene accumulation by way of convective currents established from a diffusive gas front at the top of the oil column.

Reservoir fluid analysis can be used to better understand a hydrocarbon reservoir. Reservoir fluids are not always equilibrated in particular because of dynamic processes such as late gas charges occurring in the recent geologic past. It is of great importance to delineate how a late gas charge affects fluid distributions and when asphaltenes become unstable in oil. In this work, we modify the simplified moving boundary one-dimensional diffusive model of Zuo et al. (Energy 2016, 100, 199) for gas charges into oil reservoirs considering the Maxwell−Stefan diffusivity and thermodynamic nonideality. Live oil is simply treated as three pseudocomponents: gas, maltene, and asphaltene. The parameters of the three components in the Flory−Huggins regular solution model are calibrated by the Peng−Robinson equation of state. The modified diffusive model is then used to simulate gas charges into oil reservoirs. The simulation results have indicated that fluid density inversion is created by competing effects of asphaltene diffusion and expulsion owing to late gas charges. The density inversion induces gravity currents which cause asphaltene migration from near the top to the base of the oil column fairly rapidly in geological time. In addition, the same thermodynamic model as in the diffusive model is also used to generate vapor−liquid equilibrium (VLE), liquid−liquid equilibrium (LLE), and vapor−liquid−liquid equilibrium (VLLE) spinodal and binodal phase boundaries. Furthermore, the fluid compositional variation paths simulated by the modified diffusive model and the calculated phase boundaries are plotted in the same phase diagrams for comparison. The results show that asphaltenes can precipitate locally near the gas/oil contact (GOC) for fluids with high asphaltene content because rapid gas addition to an oil reservoir at the GOC easily makes fluids near the GOC metastable and/or unstable (high gas solution oil decreases its solvency capacity to dissolve asphaltenes). Moreover, with asphaltene-enriched advective flow, asphaltene buildup at the base (oil/water contact, OWC) can give rise to asphaltene phase instability and tar mat formation when the asphaltene content surpasses the maximum asphaltene solubility allowable in the oil. This is consistent with the frequent field observations of asphaltene deposition at the upstructure with shale breaks and the OWC. Additionally, the sensitivity of the thermodynamic model parameters to phase envelopes is analyzed. The sensitivity analysis indicates that decreasing gas and maltene solubility parameters, temperature, and maltene molar mass, and increasing asphaltene solubility parameters and asphaltene molar mass, result in increasing asphaltene phase instability.

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