Modelling Asphaltene Precipitation and Deposition in a Compositional Reservoir Simulator

Abstract

Abstract This paper describes asphaltene precipitation and deposition models implemented in a compositional reservoir simulator. The asphaltene precipitate is modelled as two solids: Solid 1 is thermodynamically reversible and is in equilibrium with the asphaltene component in the oil phase. Solid 2 is created from Solid 1 via a chemical reaction. Solid 2 can be used to represent the flocculation of smaller precipitated asphaltene particles into larger aggregates. This aggregation can be made fully reversible, fully irreversible or partially irreversible. Solid 1 flows as suspended particles in the oil phase, while Solid 2 may flow with the oil or deposit in the rock matrix. The deposition model incorporates surface deposition, pore-throat plugging and re-entrainment of deposited solid into the flowing liquid phase. Porosity and permeability impairment due to asphaltene deposition are also modelled. Model results are compared to laboratory core floods illustrating core damage due to asphaltene deposition. The model is also applied to studies of primary depletion, and core flood simulations of miscible gas injection for light oils. Introduction Asphaltene precipitation from reservoir fluids during oil production is a serious problem because it can result in plugging of the formation, wellbore and production facilities. Asphaltene precipitation can occur during primary depletion of highly undersaturated reservoirs or during hydrocarbon gas or CO2 injection for improved oil recovery.1–3 The injection of hydrocarbon gases or CO2 for IOR promotes asphaltene precipitation. Many field reports and laboratory studies on this aspect have been published.4–6 Precipitation can occur anywhere in the reservoir, although it manifests itself frequently at the production wellbore at solvent breakthrough. Asphaltene precipitation may also occur during solvent injection into heavy oil reservoirs as in the VAPEX process.7,8 The injection of solvent (e.g. propane) creates a solvent chamber where oil is mobilized and drained toward the producer. In addition to the mobilization process, the solvent may also induce asphaltene precipitation, which provides an in situ upgrading of the oil. Asphaltenes and other solids create production problems if they deposit onto the walls of the tubing or into the reservoir formation. Precipitated asphaltenes that have not aggregated into larger particles may flow with the reservoir fluids without any detrimental effects on production. Conversely, for "in-situ upgrading" to have any beneficial effect in heavy oil recovery, the precipitated asphaltenes must deposit onto the reservoir rock in sufficient quantity to lighten the character of the produced fluid, but not to such an extent that production is impaired. This paper briefly describes the processes involved in the initial precipitation of asphaltenes from the reservoir fluid, the flocculation of these precipitates into larger particles and the deposition of these particles in porous media. Models for these processes and their implementation in a compositional reservoir simulator are then given. Model results are compared to experimental data for three oil core flood experiments. Effects of the model parameters are illustrated for one-dimensional simulations of gas injection into oil-filled cores. Two-dimensional simulations illustrating asphaltene deposition due to pressure depletion are also presented. Asphaltene Precipitation and Deposition Although research on the state of asphaltenes in crude oils is ongoing, a widely held view is that asphaltenes exist as colloidal particles held in suspension with associated resin molecules, which act as surfactants to stabilize the colloidal suspension.9 These colloidal particles may exist as a separate phase dispersed in the crude oil, or they may be dissolved in the oil, forming a true single phase solution. In either case, the suspension is stable over geologic time.