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.

The objective of this work is to acquire phase behaviour and physical property data of carbon dioxide/heavy oil systems pertaining ta enhanced oil recovery by CO2 huff-n-puff and steam stimulation. Phase behaviour and physical property measurements were carried out on Lindbergh heavy oil CO2 mixtures at 21 °C and 140 °C, and at pressures ranging up to about 15 MPa. Furthermore, the oil samples were analyzed using gas chromatographic simulated distillation. The experimental measurements were also carried out on three of the oil's fractions that can serve as "pseudo components" during equation of state correlations Of the experimental data. The solubility of CO2 was less in the heavier hydrocarbons than in the lighter fractions and the solubility also decreased with increasing temperature. The densities of the saturated mixtures did not change significantly as the saturation pressure was increased. The extent of viscosity reduction with increasing CO2 content was larger for the heavier hydrocarbon fractions than for the lighter ones. In addition, the viscosity was sometimes seen to increase with pressure in the liquid-liquid equilibrium region of the phase diagrams. Analysis of the residual oils indicated that in some cases a small amount of their light ends had been extracted by CO2 and/or some of the heavy ends had been depleted (presumably precipitated). Introduction Gas (more commonly CO2) injection into heavy oil reservoirs is becoming a viable enhanced oil recovery method(l-5). Mathematical studies of this process have been presented in the literature(6–10), as have been laboratory displacement data(11–13) and phase behaviour measurements(l4–19). The main mechanism in this process is the dissolution of the injected gas into the crude oil, thereby swelling it, reducing its viscosity, and making it more mobile. Usually the process is an immiscible one, in contrast to the more common miscible gas flooding of conventional oil reservoirs. The correlation of the phase behaviour data of conventional crude oils is usually carried out with one of the Van-der-Waals type of equations of state. Examples of these equations are those by Soave-Redlich-Kwong(20) and Peng-Robinson(21). Ideally, these equations require certain parameters to characterize each component in the mixtures under consideration. The common practice has been to represent the crude oil with a limited number (four to six, typically) of pseudo components. Several Authors(22–27) have proposed various schemes for selecting these pseudo components and evaluating their properties based on those of the crude oil. Most of the methods that have been developed for the characterization of crude oils were derived from data of light oil systems and these are usually directly applied to heavy oil data. This may not be an optimum approach since heavy oils have a much larger proportion of heavy ends, asphaltenes, and resins, and a much lower content of C5-C30 hydrocarbons than light oils. In addition, heavy oil reservoirs are usually shallower than light oil reservoirs and, consequently, have lower pressures and temperatures. Alternatively, enhanced oil recovery of heavy oil reservoirs is often carried out using thermal methods, such as steam or fire flooding, in which very high temperatures (> 200 °C) are encountered.

Phase behavior and physical property measurements were carried out on mixtures of SO2‐H2O; CO2‐H2O, 5, 10, and 20 weight percent NaCl brines; and ternary CO2‐SO2‐H2O mixtures. The temperature was kept constant at 45°C, while saturation pressures were varied up to about 15 MPa. Binary measurements demonstrated that, at the same temperature and pressure, the mutual solubilities of SO2 and H2O are higher than those of CO2 and H2O. A three‐phase region has been identified in the termary CO2‐SO2‐H2O phase diagram at 7.24 MPa, but no such region was found at higher pressures.

No abstract

High pressure experiments with three oils and propane as an asphaltene flocculant were performed. A capillary tube was used for the viscosity measurements. Viscosities of oil mixed with a gaseous solvent under miscible conditions were measured and compared with data on onset of asphaltene flocculation (OAF). For these oil-propane systems the OAF values were previously determined by a photometric method. Sharp increases in viscosity of the oil-solvent mixture, at increasing amounts of solvent (beyond the point of asphaltene flocculation), were detected. Viscosity increases caused by adding hydrocarbon solvent gases at high pressure were very significant in contrast to the expected decreasing trend in oil viscosities upon adding increasing amounts of a non-flocculating solvent with a lower viscosity. Upon asphaltene flocculation/ deposition, a minimum in mixture viscosity followed by a sharp increase was noted. This was interpreted as the onset of asphaltene deposition. The values of measured viscosity were compared with corresponding values obtained from diferent correlations. It was seen that these correlations resulted in values substantially lower than the real values, even at low solvent concentrations (lower than the OAF), confirming that the flocculation/ deposition mechanisms are much more complex than are generally perceived. Introduction The oil industry has faced the problem of asphaltene deposition for many years. Asphaltene deposition in the reservoir, well bores, well head equipment, pipelines and other downstream equipment can lead to serious problems and can increase the cost of producing oil. Asphaltene deposition increases whenever anything disrupts or destabilizes the asphaltene-resin micelles equilibrium. For example, the addition of low-molecular weight hydrocarbons-such as propane, n-pentane, petroleum naphtha or gasoline-will result in a flocculation of asphaltenes by solubilizing resins in the bulk oil phase. In this case the viscosity of the oil-solvent mixture would also heavily depend on asphaltene content. There are two different types of asphaltene deposition:Asphaltene deposition during primary recovery of oil, which is mainly due to the changes in pressure and temperature.Asphaltene deposition during miscible flooding involving rich hydrocarbon gases and carbon dioxide. For the latter, the most important problems are to determine:the viscosity of the oil-solvent mixture,the OAF (which is the minimum amount of solvent that would trigger the flocculation process, at the prevailing pressure) andthe onset of asphaltene deposition (OAD). The amount of asphaltene deposited is also of interest. In addition, presently, there is no reliable method to estimate the viscosity of oil-solvent mixtures for the purposes of calculating upwards flow within oil wells or, in the surface pipelines or, in flow through porous media; all the existing viscosity correlations are valid only when asphaltene flocculation does not occur. The objective of this paper is to fill this gap and to propose a method to determine the OAD. Determination of Onset of Asphaltene Flocculation for the Oil-Propane Systems As mentioned, accurate determination of onset of asphaltene flocculation (OAF) and onset of asphaltene deposition (OAD) are very important for the choice of methods for preventing/combating asphaltene deposition.