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.

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Several factors influence the IFT of oil and formation water. These factors are rooted in the complex composition of oil, presence of different salts in water, water salinity, temperature, and pressure of reservoir. In the first part of this paper, effect of salinity on IFT between brine and an Iranian live oil sample has been studied experimentally. It is observed that IFT increases almost linearly with brine concentration. Also, linear increasing behavior of IFT with respect to pressure is obviously seen. Then, using thermodynamic properties such as surface excess concentration, chemical potential, chemical activity, and activity coefficient, results were analyzed and observed effect of salinity and pressure were justified thermodynamically. In the second part, the effect of asphaltene on IFT reduction has been studied. In previous works, the investigators extracted resin and asphaltene and then examined their effects on IFT in the absence of other fractions of oil phase. We believe that all fractions play a role in this phenomenon so, in this paper, the effect of natural surfactants of oil phase on IFT has been investigated in presence of all fractions of oil. Hence, SARA test was performed on all samples. Then, IFT between oil samples and brine were measured using captive drop instrument at 25 °C and 3000 psia. Results showed that neither asphaltene content nor asphaltene/resin ratio is a good indicator for effect of asphaltene on IFT, whereas colloidal instability index could be a useful tool to predict asphaltene effect on IFT.

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Rock typing is an important tool in evaluation and performance prediction of reservoirs. Different techniques such as flow zone indicator (FZI), FZI * and Winland methods are used to categorize reservoir rocks into distinct rock types. Generally, these methods are applied to petrophysical data that are measured at a pressure other than reservoir pressure. Since the pressure changes the pore structure of rock, the effect of overburden pressure on rock typing should be considered. In this study, porosity and permeability of 113 core samples were measured at five different pressures. To investigate the effect of pressure on determination of rock types, FZI, FZI* and Winland methods were applied. Results indicated that although most of the samples remain in the same rock type when pressure changes, some of them show different trends. These are related to the mineralogy and changes in pore system of the samples due to pressure change. Additionally, the number of rock types increases with increasing pressure. Furthermore, the effect of overburden pressure on determination of rock types is more clearly observed in the Winland and FZI* methods. Also, results revealed that a more precise reservoir dynamic simulation can be obtained by considering the reservoir rock typing process at reservoir conditions.

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