Abstract

Complex technical problems, including salt precipitation, can occur during the entire period of the operation and production of the oil from reservoirs in high-pressure/high-temperature (HPHT) condition. Inorganic salts deposition occurs during the mixtures of different waters, which are incompatible with each other. These combinations of waters mostly can be done during waterflooding into the reservoirs to pressure maintenance. For the effective development of oil reservoirs, which are associated with the deposition of inorganic salts in HPHT, the selection of inhibitors is required to prevent scaling accounts for the characteristics of the reservoirs. Effectiveness of the scale inhibitors concentration for specific well conditions is verified by laboratory tests, considering total dissolved salts and hydrochemical conditions of the formation. The amount of calcium carbonate (CaCO3)) precipitation in synthetic formation water was investigated in mixing with the injected water in the range of 100-200°C for temperature and 40-70 MPa for pressure. Also, calcium carbonate precipitation was considered in a well at 200°C and 70 MPa in a simulation model with an electrical submersible pump (ESP). The results of the experiments showed that the possibility of calcium carbonate deposition was increased by growing the amount of the formation water and temperature. Increasing the pressure had reverse effect on scale formation. In this investigation, a new inhibitory chemical composition was developed. This scale inhibitor is based on the aqueous solutions of different acids and isopropyl alcohol. The inhibitor was considered for compatibility with formation water and core samples; and it was compatible with them at reservoir condition. The new scale inhibitor had a greater inhibition efficiency and low permeability damage in comparison with the tested inhibitors. The used materials were effective for scale prevention at high-level. The synergistic inhibitory effect has been considered for mixtures of inhibitors.

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