Summary Wax precipitation is often studied using the stock tank oil. However, precipitation may be very different in well tubing and production facilities due to the effects of pressure and composition. As an example, the cloudpoint temperature may decrease as much as 15 K from atmospheric pressure to the saturation pressure of 100 bar mostly due to the dissolution of light gases into the oil (i.e. due to composition changes). It is also often assumed that the addition of solvents such as C5 and C6 decreases the cloudpoint temperature. On the contrary, from our modeling results, we have found that the mixing of a crude with a solvent increases the cloudpoint temperature (i.e., enhances the wax precipitation). In this study, the cloudpoint temperature at live oil conditions and the amount of the precipitated wax at stock tank oil conditions are provided for three crudes. A modified multisolid wax precipitation model is used to study the effects of pressure and composition on wax precipitation. The modeling results reveal that an increase in methane and CO2 concentration decreases the cloudpoint temperature while an increase in C5 concentration increases the cloud point temperature. Introduction Wax formation is a major problem in well tubing and subsea pipelines. The current methods which include the interruption of production to scrub the deposited solid are very costly. A thermodynamic predictive model is important in solving the problem. Dorest studied the solid precipitated from binary normal alkane mixtures using calorimetry and microscopy. He found that the precipitation is unstable and segregates into two solid phases when the chain-length difference between the two alkanes exceeds a fixed value. He also found the segregated phases consist predominantly of pure components. Recently, Snyder et al. studied the kinetics of the segregation using spectroscopy, calorimetry and electron diffraction. They observed that the rate of the segregation is very sensitive to the chain-length difference. Hansen et al. observed phase transitions of the precipitated wax from the North Sea crudes. Based on these observations, Lira-Galeana, Firoozabadi, and Prausnitz developed a thermodynamic multisolid wax model. The calculated results from this model were in agreement with data of stock tank fluids from the North Sea given by W.B. Pedersen et al. The model of Lira-Galeana, et al. lumps all the various chemical species for a given carbon number and avoids the use of paraffins (P), naphthenes (N) and aromatics (A) by assigning average properties such as the melting point temperature, heat of fusion, and critical properties. However, K.S. Pedersen, et al. and Ronningsen et al. have shown that the wax precipitated from a petroleum fluid consists primarily of normal paraffins, iso-paraffins, and naphthenes. The aromatics do not precipitate as the wax. The use of PNA analysis avoids assigning average properties to the carbon numbers. We have recently observed that certain light oils and condensates with an API gravity of 45 may have a cloudpoint temperature as high as 333 K. Such a high cloudpoint temperature might be attributed to a very high concentration of paraffins and naphthenes. Accordingly, a predictive model should consider the PNA analysis to account for physical properties of various hydrocarbon species. Most of the literature data on wax precipitation are measured at stock tank oil (dead oil) conditions. Since the concentration of light components at high pressures has a significant effect on cloudpoint temperature, a proper predictive model and experimental data for reservoir fluids will be very useful in investigating the wax formation problems at well tubing, production facility, and pipeline conditions.

No abstract

No abstract

Summary. The optimal salinity of three different anionic microemulsions was found to increase as a function of increased hydrostatic pressure. This is equivalent to a phase transition from an upper [Winsor H(+) (VM +) microemulsion to a lower [Winsor II(-) (WII -)] microemulsion. Increased pressure induces a compressibility effect that is consistent with the observed phase transition. Increasing temperature also leads to increasing optimal salinity. Prediction of temperature effects is complicated by temperature-dependent interactions and entropic contributions caused by dispersion. Fluid models that account for temperature effects are needed; therefore, no attempt was made to develop a theoretical interpretation of this effect. The temperature range is 0 to 100deg.C, and the pressure was varied from 0.1 to 50 MPa. Introduction An evaluation of a chemical flooding process for deep reservoirs like those in the North Sea must consider the effect of high temperature and pressure on microemulsion properties. For practical reasons, laboratory screening tests use either stock-tank oil or a model oil at reservoir temperature and atmospheric pressure. Moving to Drill reservoir conditions is expected to change the chemical phase equilibrium significantly and thereby most likely to change the optimum surfactant composition. The reason for these changes is obvious if the oil has a large GOR, but we also believe that pressure has a direct influence on the microemulsion phase behavior. The phase behavior of surfactant/oil/water mixtures is the single most critical factor determining the success of a chemical flood. Many papers describe the sensitivity of microemulsion phase behavior to such compositional parameters as surfactant concentration, cosolvent concentration, WOR, ionic strength, and the ratio of divalent to monovalent ions. Also, the structures of the surfactant, cosolvent, and oil are important to determine the actual phase behavior. The effect of temperature has been reported for both anionic and nonionic surfactants. The changes in phase behavior are more pronounced for nonionic surfactants that exhibit a sharp phase-inversion temperature. Of the vast number of papers on surfactants, only a few consider pressure effects, and most of these cover studies of aqueous surfactant solutions. Micellar solutions of both anionic and nonionic surfactants show an increase in critical micelle concentration (CMC) and a decrease in aggregation number as a function of increased pressure. The effect of pressure on the phase behavior of microemulsions has been the subject of several reports. The results so far dispute that pressure has any effect on phase behavior. In most of these studies, the pressure was increased by the addition of gas, and it is difficult to separate the pressure effect from changes in composition. The interfacial tension (IFT) between oil and water is affected very little by pressure. In the presence of surfactants, however, low MT's can be achieved, and the phase behavior is critically dependent on the different intensive parameters, as described above. At these conditions, it is likely that pressure will affect both the IFT's and the phase behavior. O'Connell and Walker found microemulsion phase behavior to change markedly under pressure, in direct disagreement with Nelson, who detected no phase volume change. Because of the difference in compressibility between oil and water, however, the water/oil volume ratio changes during pressure measurements. If no changes in phase volumes are observed, there still is an increase in water solubilization and a corresponding decrease in oil solubilization owing to changes in WOR. The phase behavior is thus shifted toward a lower-phase microemulsion. It is not clear whether these corrections in WOR were included in the reported phase-volume data. The reports describing phase-behavior studies of both alkanes and crude oils pressurized with methane or other light alkanes concluded that with crude oils, the phase behavior shifts toward VM+. The shift is smaller than what would be predicted from the changes in alkane carbon number (ACN). Introducing methane lowers the average molecular weight and is expected to decrease the equivalent ACN. But because the density of the oil phase is increased under pressure, the presence of methane might reduce the effective shift in ACN. For alkanes pressurized with methane, the optimal salinity is found to increase with increasing gas concentrations, which correspond to a shift in phase behavior toward Wu. The above two results seem to contradict each other. Keep in mind, however, that crude oil contains aromatics and asphaltenes; therefore, comparison of alkanes with crude must be done with caution. In this paper, we focus on the effect of pressure on the phase behavior of microemulsions at constant oil composition. The experiments were restricted to three surfactant systems in n-alkane/ n-butanol/NaCl/water. The surfactants were selected from groups of surfactants that are interesting for chemical EOR at high temperature and moderately high salinities. The effect of pressure on these systems was compared with changes in phase behavior with temperature and ACN. The IFT was also measured as a function of pressure and compared with changes in solubilization of oil and water in the microemulsion middle phase. Materials For the phase-behavior studies, we used three systems containing different types of commercial surfactants: alkyl-benzene sulfonate, secondary alkane sulfonate (SAS), and alkylaryl ethoxylated sulfonate. The alkylbenzene sulfonate was a sodium n-dodecyl-benzene sulfonate (SDBS) from Akzo Chemie. The product was supplied as a concentrate at 35 wt % active matter. The organic impurities were less than 1 wt%, and the sodium sulfate residue was a maximum of 0.6 wt %. The SAS sulfonate, from Hoechst AG, is made from a continuous process by sulf-oxidation of C 13 through C 18 n-paraffins. The dis-tribution in molecular weight is reported to be 1 % less than C 13–58 % C 13 through C 15, - 39 % C 16 through C 17, and a maximum of 3 % C 17 1. The surfactant was delivered as a paste at 60 wt% active matter. The oil content was less than 0.5 wt%, and the sodium sulfate concentration was a maximum of 4 wt%. The molecular weight is 328 g/mol. The alkylaryl ethoxylated sulfonate is also a Hoechst product. This surfactant is a tributyl-phenolether-4-ethoxy-sulfonate (TBPE). The anionic active matter is 26 wt%, and the solid content is 40 wt%. The salt content is less than 5 wt%, and the rest of the solids (9 wt%) is the nonionic product. A cosolvent, n-butanol from Merck (purity 99.5 % +), was used for all three surfactant systems. SPERE P. 601^

No abstract