The purpose of this study is to evaluate the degree of formation damage caused by asphaltene deposition in the pore throats in case of oilfield operation. Many wells in the Samara region oilfields are operated under high reservoir drawdown, with downhole pressure lower than the bubble point. Such wells' operating conditions lead to a change in oil composition (light components are extracted from oil while asphaltenes are precipitated and deposited) in the near wellbore, and the productivity of the wells declines due to asphaltene deposition. The study procedure presented in the paper included the following methods: high-pressure microscopy with grain size analysis (the visual method), the near infrared light scattering method and the gravimetric method to measure asphaltenes onset pressure in oil. Formation damage was measured by the filtration method. Asphaltene concentration in oil after filtration was measured by the photocolorimetric analysis. Microcomputed tomography of the core sample was provided to visualize formation damage. In addition, fluid flow in the pore space was simulated before and after asphaltene deposition using a dynamic simulator. In the paper, reservoir oil of one of the Russian oilfields was investigated. The main results of this paper are the following: asphaltene onset pressure in oil at the reservoir temperature (48 °C) was measured as equal to 6.8 MPa which is slightly higher than the bubble-point (6.5 MPa). Oil was flowed through the core sample of the field at three different specific backpressures (at constant flow rate) and formation damage was estimated. The studies have shown that decrease in permeability of the core is caused by asphaltene deposition in the pore space. In this case, a decrease in the amount of asphaltenes in oil emerging from the core sample is observed which was proved by the spectrophotometric analysis. Via microcomputed tomography, a 3D model of the rock matrix and the pore space of the initial and damaged core sample was constructed and a decrease in porosity after formation damage was estimated. Based on the obtained 3D model of the core, computer simulation of fluid flow (in a dynamic simulator) in the initial and damaged core was performed, and the flow parameters (velocity and streamlines) were calculated. The proposed methodology including a set of physical methods to study a core before and after formation damage combined with fluid flow simulation enables predicting potential complications under the field operation.

The purpose of the paper is to study the effect of temperature and hydrocarbon solvent addition on thixotropy of waxy crude oil. Oil is a complex multicomponent hydrocarbon system. There are many interactions between wax and asphaltene, wax and aromatics, asphaltene and resins in original oil. For example, the dispersion of asphaltenes is known to be influenced by resins. The resins are adsorbed onto the surface of the asphaltenes, whereby the asphaltenes are not aggregated. Wax is adsorbed by fine asphaltene particles and wax appearance temperature (WAT) observed at low temperature (formed wax crystals too small to be detected by measuring system). The authors of the paper have studied the separate effect of two solvents (kerosene and diesel fuel), wax concentration and impurities (kaolinite) on WAT to understand how all these factors affect WAT in wax-bearing solutions individually. Wax-bearing solutions in wax concentration range from 10 to 60% by weight were investigated by the visual and rheological methods under atmospheric pressure. It is shown that the diesel-based solutions have higher WAT than the kerosene-based solutions. Studies have shown that the increase in wax concentration in solution leads to an increase in WAT. The paper describes that the addition of impurities (kaolinite) to the solutions resulted in an increase in WAT. Besides, it is shown that WAT obtained by rheological method is higher on average of 1 °C than WAT obtained by visual method. The authors suggested that under constant other conditions (pressure, resin and asphaltenes content, etc.) an increase in wax content in oil and the content of impurities will lead to an increase in WAT. The scientific basis for this conclusion is that, in the future we can, adding or removing from solution hydrocarbon components, with certain assumptions, simulate the properties of oil. In particular, this will allow us to study separate interactions between the wax and asphaltene, wax and aromatics, and wax and naphtha compounds, and abstract away from other factors. The waxy crude oil production in the Samara region is complicated by impurities entrainment and non-Newtonian properties of oil. The investigations of waxy crude oil were provided with light scattering method (in near infrared region), microscopy under high pressure with the grain size analysis (visual) and a rheological method. We obtained the unique «viscosity superanomaly» discovered by Vinogradov and Malkin (Rheol Acta 5(3):188-193, 1966) at low temperatures and shear stress by rheological method under atmospheric pressure. The area of the hysteresis loop on the flow curve increases as the temperature decreases, which is caused by the formation of the lattice by wax. We have also shown that the use of solvent and the increase in temperature allow to reduce «viscosity superanomaly». Simultaneous use of light scattering and microscopy under high-pressure methods allows increasing in accuracy of measuring. For waxy crude oil, there will also be a difference between rheological and visual...

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Summary The objective of this research is a definition of wax-precipitation conditions in waxy oil (a kind of oil that intends to produce high-molecular-weight paraffins during production) at various thermobaric conditions taking place in oil wells, and also proposing a method for the determination of the potential wax-formation depth in a well. In most cases in Russia, many reservoirs are producing oil with high asphaltenes, resins, and wax content that causes the formation of organic deposits in downhole equipment. It reduces the workover period of wells and decreases their productivity. The oil-production system represents the sensitive hydrodynamic system, so any changes in well operational parameters, thermobaric conditions, and oil composition lead to wax and asphaltenes precipitation in oil. Natural surfactants (asphaltenes) stabilize water-in-oil emulsions and change rheological properties of the borehole flow. It demands additional energy consumption for raising reservoir fluid to the surface and for transporting it to gathering and oil-treatment systems. All laboratory experiments are conducted by use of conventional (standard) techniques. The grain-size-analysis microscopy was performed under high-pressure conditions. Also, a light-scattering method and viscometric analysis were performed, and functional wax-appearance temperature (WAT) vs. the pressure of live and degassed oil are carried out during experimental studies. The results of our experiments showed that, when the pressure drops below the bubblepoint pressure and the gas starts coming out from the oil, the WAT increases. A significant increase in the viscosity of a live-oil sample with a decrease in temperature and pressure in the range of downhole conditions that can become the reason of decline in the performance of an electrical submersible pump (ESP) is noted. The most technological methods directed on drop in the presented risks—among which are offered (1) the change of well-operation conditions allowing the regulation of the waxing of tubings and (2) the application of inhibitors that demonstrated high efficiency during the laboratory investigations—are mentioned. Mathematical analysis showed that the increase in well flow rate promotes a considerable decrease in potential wax-formation depth in an oil well. The proposed assessment technique of wax-precipitation depth that has been performed in this work can be useful for selecting the well-operation system. Among the studied inhibitors, the experiments showed that Inhibitor A has the highest efficiency in the slowing of the wax-formation process in the borehole conditions.