Oil industry suffers from flow assurance problems that occur both in upstream and downstream operations. One of the common flow assurance issues arises from precipitation and deposition of asphaltenes in various locations along the oil production path including near wellbore region in the reservoir, production tubing, flowlines and separation unit at the surface. Asphaltene particles precipitate out of oil continuum due to changes in temperature, pressure or composition. Such changes in operating conditions occur during different recovery processes (natural depletion, gas injection, chemical injection, etc.) as well as production and blending of different oils during transportation. There are different experimental methodologies documented in the literature that describe how to determine onset of asphaltene precipitation. In this paper, a comprehensive review is performed on all the available procedures to measure onset of asphaltene precipitation. The advantages and limitations associated with all these methods are also documented.

Asphaltene precipitation (AP) is recognized as a complicated occurrence that results in weakening reservoir characteristics and subsequent considerable decline in oil production rate. Asphaltene instability occurs due to variations in thermodynamic properties such pressure, temperature, and mixture composition. AP prediction is an important design factor in implementation of any enhanced oil recovery (EOR) process. In this study, experiments were conducted using some light oil samples to measure important phase behavior properties such as the bubble point pressure (BPP) and the amount of precipitated asphaltenes. A thermodynamics model was also developed to determine equilibrium compositions of the oil samples, considering AP. Then, potential application of a feed-forward artificial neural network (ANN) model, optimized by the imperialist competitive algorithm (ICA), was proposed to estimate BPP and the amount of AP. Comparison between the ICA-ANN predictions and the experimental data shows that the average absolute error between data originated from these two different approaches is less than 5%. In addition, it was found that temperature and pressure have the greatest impacts on AP during natural depletion. Employing laboratory PVT data, the thermodynamics framework resulted in construction of an asphaltene precipitation envelope. This study implies that utilization of an appropriate PVT model along with the ICA-ANN approach in the investigation of AP leads to more reliable predictions compared to the conventional ANN and also a scaling model. The outcomes of this study appear to be useful in the design stage of more-efficient EOR processes.

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Attempts have been made to reduce the energy requirements of steam assisted gravity drainage (SAGD) projects through coupled thermal and solvent processes (i.e., hybrid SAGD). The augmented process brings superior features to the SAGD process in terms of reduced energy requirement, enhanced produced oil quality, and also improved oil recoveries. The pore-level recovery mechanisms of the hybrid SAGD process have not been investigated yet. The main objective of this paper is to visually investigate and to document the pore-scale events during the hybrid SAGD process using glass micromodel type of porous media. Different additives (npentane and n-hexane) were added to steam prior to injecting into the models. Experiments were conducted in an inverted-bell vacuum chamber to reduce the excessive heat loss to the surroundings. The results indicate that the gravity drainage process takes place through a layer of pores composed of 1-5 pores in thickness, in the direction perpendicular to the nominal oil-gaseous mixture interface, in the mobilized region. The interplay between gravity and capillary forces results in the drainage of the mobilized oil. The visualization results demonstrated the coexistence of water-in-oil and solvent-in-water emulsification at the interface because of the local condensation of both steam and the vaporized solvent. The extent of emulsification depends directly on the temperature gradient between the gaseous mixture and the mobile oil phase. Asphaltene precipitation was also observed when the condensed solvent reached the bitumen interface. As the nature of the process involves partially miscible displacements, the extent of film-flow drainage of the mobilized oil was also significant. Other pore-scale phenomena include localized entrapment of steam and vaporized solvent followed by condensation, snap-off of liquid films, steam and solvent vapor condensation at the interface because of the temperature gradient and capillary instabilities.

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