Perturbation in the rock-water systems of petroleum reservoirs during CO2 enhanced recovery processes may cause precipitation of scale in production lines. Therefore, a prediction of the scale potential of a particular system is valuable in the design of the enhanced recovery treatments. On the basis of formation mineralogy, formation water chemistry, and estimated temperature and pressure conditions, scale build-up during a CO2 Huff ‘n’ Puff treatment in the Cretaceous Crooks Gap reservoir in Wyoming was predicted to be minimal. Carbonate mineral cements (mostly calcite) and plagioclase, both of which are sources of scale constituents, are present in the reservoir only in trace amounts. Also, the estimated pressures both in the formation and in the production lines were sufficient to keep most of the bicarbonate ions in solution. Finally, organic alkalinity was insufficient to buffer pH which otherwise might have stabilized carbonate minerals during the CO2 injection and cause them to precipitate within the reservoir.

Water chemistry was monitored during the production phase of the Huff ‘n’ Puff treatment to test the reliability of the predictions. Initial production showed an order of magnitude increase in the calcium concentration in the produced waters as well as a two-fold increase in the bicarbonate concentration. Calculations of mineral stabilities using the post-CO2-injection produced waters indicated a slight over-saturation with respect to calcite. However, further calculations done to determine the amount of scale precipitation needed to bring the system back to saturation demonstrate that the scaling potential was minimal. The concentrations of both constituents dropped back to pre-CO2-injection levels within thirty days after the production began, which further diminished the potential for scale problems.

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