The nature of asphaltenes and their role in the production and processing of crude oils has been the topic of numerous studies. This is due to the fact that the economics of oil production can be seriously affected by the asphaltene deposition problem. This paper presents a novel method to visualize in situ asphaltene precipitation from heavy oils with light hydrocarbon gases, e.g. methane. propane, ethane/propane mixtures, and carbon dioxide at reservoir pressures and temperatures. Experimental results are reported for the effects of temperature (up to 100 °C), pressure (up to 20 MPa) and composition on the formation of asphaltene precipitates from heavy crude oils. A series of titration experiments were conducted with several n-alkanes to determine the amount of asphaltenes precipitated. Both the amount and nature of the precipitate varied with the solvent used. Propane was the most prolific of all the solvents used in precipitating asphaltenes from the heavy oils. A thermodynamic model proposed by Hirshberg et al. was used to correlate the experimental data. Introduction Miscible and immiscible flooding of crude oil reservoirs by light hydrocarbon gases, carbon dioxide and other injection gases has become a popular method for enhanced oil recovery(1). The flooding process, however, causes a number of changes in the flow and phase behaviour of the reservoir fluids and can significantly alter rock properties. Such changes include the precipitation of asphaltenes(2) and wettability reversal which can alter recovery efficiencies. The existence of asphaltenes in crude oils and their deposition inside reservoirs and wellbores can cause severe problems and affect the efficiency and cost of petroleum production. The important parameters that affect asphaltene precipitation during gas injection are the compositions of the crude oil and the solvent gas, and the pressure and temperature of the reservoir(3–5). Precipitation of asphaltenes is a complex process and it is generally followed by flocculation which produces an insoluble material in the heavy oi1(6). Asphaltenes are believed to be stabilized in solution by resins and aromatics and the asphaltene/resin ratio plays a key role in their precipitation. This ratio is more important than the absolute asphaltene content in determining which crudes will be subject to precipitation. Problems arising from asphaltene deposition have been reported in the literarure(7,8) for many field projects. Some examples of these are the Ventura field in California(9), Hassi Messaoud field in Algeria(l0) and heavy oil fields in Venezuela(l1). Deposition of asphaltenes in the wellbore can be a serious production problem and may require frequent solvent washings and scrapings to maintain oil production(10). Significant damage can be caused during well acidizing because the acid can cause the asphaltenes to precipitate and form rigid films. Other problems associated with asphaltene precipitation are the seizure of downhole safety valves submersible pumps, hinderance in wireline operations and production restrictions. These problems are discussed in derail by Leontaritist(7). Presently asphaltenes are removed either by mechanical cleaning, chemical cleaning, or by manipulating reservoir conditions (for example, pressure, production rates, etc,)(10,12). The approach taken by the oil industry has been a remedial one.

An efficient modelling technique based on the representation of the precipitated asphaltene as a pure dense phase is presented. The success of the approach is based on the division of the heaviest component in the oil into a nonprecipitating and a precipitating component.The characterization of these components is discussed. This model was able to make quantitative predictions of experimental data from the literature as well as additional data from industry. This was achieved with only a small number of adjustable parameters (two or three). The mechanistic aspect of the model with regards to colloidal nature of asphaltene/resin micelles is also discussed. An algorithm for three-phase flash calculations with asphaltene precipitation is described.

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This paper examines the effects of in situ formation of a non-aqueous foam on flow of oil-gas mixtures in porous media. A laboratory technique to investigate the role of foamy-oil behaviour in solution gas drive is described and experimental verification of the in situ formation of non-aqueous foams under solution gas drive condition is presented. The experimental results show that the in situ formation of non-aqueous foam retards the formation of a continuous gas phase and dramatically increases the apparent trapped gas saturation. This provides the natural pressure maintenance mechanism and leads to recovery of a much higher fraction of the Original oil in place under solution gas drive. Introduction Several heavy-oil reservoirs in Alberta and Saskatchewan, show "foamy-oil" behaviour in wellhead samples produced under solution gas drive. The oil is produced in the form of an oil-continuous foam which has the appearance of chocolate mousse and contains a high volume fraction of gas. This foam can be quite stale and may persist for several hours in open-vessels. The field production data from these reservoirs suggests that the production mechanisms are complex and may be quite different from those encountered in conventional solutions-gas driven reservoirs. Several of these reservoirs show anomalously high production. Both the rate of production and the total recovery under solution Gas drive are much higher than what would be expected from measured oil parameters. History matching primary production For these wells often requires unrealistic adjustment of measured parameters, such as increasing the absolute permeability by an order of magnitude. In a recent publication, Longhead and Satroklaroglu(1) have described the unusual primary production behaviour of Celtic Field reporting that the rate of production in some wells is more than ten times the calculated pseudo-steady state oil flow rate under radial flow conditions. To obtain a satisfactory history match of the primary production behaviour, they had to assume very unusual reservoir properties. These included not only an artificially high absolute permeability but also a trapped gas saturation of 35% and an unusual oil relative permeability curve. These high productivity wells produce from unconsolidated sands, and a large volume of sand is produced with the oil. Generally any attempt to stop sand production results in drastically reduced production. Another part of this puzzle is that several of these wells, which are prolific in primary production, show very poor response to steam stimulation. Several possible causes of this anomalous production behaviour have been suggested and are being investigated. These include formation of worm holes around the well which increase the effective well radius(2). Sand dilation due to removal of substantial volumes of sand with the oil, resulting in increased absolute permeability appears to be another mechanism(1). The enhancement of oil mobility by nucleation of a large number of microbubbles has been suggested as another possibility(3, 4). Another possible cause of the anomalous behaviour is the in situ formation of an oil-continuous foam. It is likely that several of these mechanisms might be involved in varying degrees in different reservoirs.

Critical micelle concentrations (CMC) were obtained from tensiometric studies on several binary surfactant mixtures (anionic-anionic, cationic-cationic, anionic-nonionic, and cationic-nonionic) in water at different mole fractions (0-1). The composition of mixed micelles and the interaction parameter β, evaluated from the CMC data for different systems using Rubingh's theory, are discussed. Marked interaction is observed for ionic-nonionic systems, whereas it is weak in the case of similarly charged surfactants. The influence of counterion valence in the formation of mixed micelles was investigated, and results suggest that in similarly charged surfactant mixtures, the degree of counterion binding does have a major role in deciding the extent of interactions. Salt addition reveals a weakening of interactions in ionic-nonionic systems, and this is attributed to head group charge neutralization and dehydration of the ethylene oxide units of the nonionic surfactants. Cloud point and viscosity data on these systems support the observation.Paper no. S1110 in JSD 2, 213-221 (April 1999). KEY WORDS:Cloud point, mixed micelles, sphere-to-rod transitions, synergism.Adsorption characteristics of surfactants from solution onto different interfaces and the propensity of surfactants to form micelles and mesomorphic phases are useful in almost all practical applications such as foaming, dispersing, solubilizing, wetting, emulsifying and cleansing action (1,2). Owing to their improved action over single pure surfactants, mixed systems like surfactant/surfactant (3,4) or polymer/surfactant (5) are often used in formulations of finished products. It is therefore important to investigate the nature of interactions and factors affecting them in aqueous media so as to understand how these control the product performance. The tendency of different surfactants to form mixed micelles is governed by their attractive (synergistic) or repulsive (antagonistic) interactions and is often explained from the β parameter estimated using Rubingh ' s regular solution theory (6). Extensive studies have been carried out on various mixed surfactant systems like anionic-anionic (7-9), cationic-cationic (10-12), anionic-nonionic (13-15), cationic-nonionic (16,17), cationicanionic (18,19), and nonionic-nonionic (20). Considerable interaction has been reported for ionic-nonionic systems, whereas weak or negligible interaction has been observed for similarly charged surfactants. Interaction between anionic-cationic surfactants is generally very strong but such systems often lead to precipitation/coacervation as a result of the coulombic interactions between oppositely charged species. We report in this paper tensiometric studies on eight mixed systems where results are explained in terms of the β parameter. Critical micelle concentration (CMC) data for some anionic-anionic and cationic-cationic systems from the literature (11,12) are analyzed to compute a β parameter so as to investigate the role of counterion valence in the nature and strength of inte...