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EXPERIMENTAL AND NUMERICAL SIMULATION OF HOT WATER INJECTION TO DEEP CARBONATE RESERVOIR

Aysylu Askarova

Abstract

Currently, thermal methods of enhanced oil recovery (EOR) based on the use of steam-thermal effects, steam cyclic treatment of the bottom-hole zone, hot water injection, steam, and in-situ combustion are the most effective in the development of high-viscous oil fields. Steam injection becomes impossible for the fields that are located deeper than 1200-1300 m with a pressure higher than 10 MPa due to the phase state of water-steam, therefore, thermal treatment is carried out by hot water. The present study was conducted to evaluate the efficiency of EOR methods based on cyclic hot water injection to engage in the active development of high-viscosity oil reserves in a deep reservoir located in the south of the central part of Russia. Oil-bearing formation at depths of 1200?1500 m are represented by carbonate rock with an average porosity of 13?17% and very high initial oil saturation up to 90%. Technological equipment on the field allows to achieve a sufficiently high fluid temperature in the bottom-hole zone in the 250-300 °C temperature region. Since non-isothermal experiments do not allow the use of traditional methods of processing of laboratory experiments based on material balance for non-stationary processes, a unique experiment was conducted in the non-isothermal mode as part of this study. A specific feature of a laboratory experiment to determine the coefficient of oil displacement by hot water was to create a unique core holder cementing technology that could withstand temperatures in the range of 250?350 °C for a long period of time and made it possible to create a model of 50 mm cylindrical core samples for a real experiment close to reservoir conditions. During the construction of the hydrodynamic model, a representative fluid model was created in the format of the CMGWinProp commercial software package with adjustment for experimental data. 3D radial model of the laboratory equipment was constructed to carry out a numerical simulation with a reproduction of the full geometry of the experimental setup. The model used the values of porosity, permeability, initial oil/water saturation, as well as the properties of the recombined oil sample of the given field. A close correlation with experimental values were obtained within the simulation for the cumulative water and oil, including temperature profiles. The model reflects the dynamics of oil displacement at different rates of water injection. According to experimental and numerical simulations, thermal effects reduce viscosity with a consequent increase in oil recovery. Adapted fluid model, relative permeability and operational parameters are necessary for the subsequent transition to the sector model. The data obtained during the laboratory experiment served as the basis to create a numerical model of an experiment in a hydrodynamic simulator for subsequent scaling to a sector model. The efficiency of oil displacement at this site is confirmed by numerical simulation.

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DOI resolver: doi.org/10.5593/sgem2019/1.2/s06.108

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