Abstract
Productivity losses of up to 90% had been observed in large offshore oil wells within less than a year of operation. Extensive investigation into possible formation damage and/or pore plugging, due to migration of formation fines (clay particles), had been conducted. Scaling was not considered because no formation brine had been produced. It was however observed that shallow acidizing procedures could restore the original productivity. Modeling studies were initiated with the aim of resolving this possible discrepancy, using the little known phenomenon that the water solubility in the oil is pressure dependent.
Several brine samples from an aquifer below the oil bearing strata were studied. It was assumed that the composition of aquifer brine is representative of the residual brine saturation in the oil bearing formation. Then it was concluded that the scaling tendency1) of these brine samples had to be 1 (saturation equilibrium) under downhole conditions. Furthermore, modeling of the oil/brine equilibrium indicated that at a given temperature, the water content in the oil was shown to be a function of pressure – the higher the pressure, the lower the water content in the oil. As the oil was being produced, and a pressure gradient was established between the formation and the wellbore, the oil became richer in water at the expense of the brine. The brine in turn became more concentrated, hence oversaturated in minerals, whereupon scale deposition started.
It was shown that relatively small amounts of formation brine can through scale precipitation significantly reduce oil flow through the formation around the wellbore.
