A laboratory study of CaCO3 scaling kinetics has been undertaken to obtain information useful for prediction of CaCO3 scale formation. The induction time for precipitation has been determined in a series of experiments where SR, T and the ionic composition of the water from which precipitation occurs, have been varied. The effect of sand from a North Sea oilfield reservoir on the rate of CaCO3 precipitation has also been investigated. Our data shows that sand enhances the rate and reduces the induction time for calcite precipitation. The formation of solid CaCO3 has a window of metastability, which can vary from SR - aca2+ ac°#- = 7.0, Ksp(CaCQ) 2.9 and 2.7 at 80, 100 and 120°C, respectively, with no sand in the water, and 4.8-4.9, 2.7 and 2.6 with sand present. An even more drastic effect was observed when calcite scale was added to the water. At 100-120°C the precipitation at SR - 1.6 was observed after a few seconds. This is reasonable since the calcite crystals suspended in the solution act as crystallization sites for the dissolved carbonate. It was also observed that Mg 2÷ and SO42 ions in the solution increased the induction time and retarded the CaCO3 crystallization. This implies that compounds that block active sites for calcite crystallization may inhibit CaCO3 precipitation. With Mg 2+ and SO42- ions in the solution aragonite was formed. At constant SR ,., 2+/,., 2+ the activity ratio aMg /ctCa was found to have a different effect on the induction time as the Ca 2+ concentration was varied. The induction time for precipitation increased linearly with the probability that a magnesium ion was next to a calcium ion at constant SR. This probability is 2+ proportional to the concentration product mMg 2+, mca .
Mineral precipitation or mineral scaling, during oil production is of considerable concern for the oil industry. Calcium carbonate is one of the most common of the various minerals precipitating from formation waters. Calcium carbonate can decrease the permeability in the near well area, adhere to the inside of the production tubing, and clog valves and other equipment. All of these will lead to a loss in production. Calcite scale is relatively easy to treat, since it is soluble in acids. The pressure drops as oil and water are produced from the reservoir. This pressure drop may lead to increasing supersaturation of CaCO3 and higher risk of calcite precipitation and the formation of scale. The supersaturation of CaCO3 can be calculated using thermodynamic models and oil and water analysis data. CaCO3 can, however, at rather high supersaturation, be in a metastable state in the solution. It will therefore not precipitate despite being thermodynamically unstable. When assessing whether CaCO3 scaling will be a problem, the kinetics of its formation ought to be taken into account. The induction time for precipitation is according to Mullin ~ defined as the time from supersaturation is created until critical nuclei for crystal growth are formed. However, if the induction time for a given supersaturation is longer than the retention time of the oil and water in the production tubing, scale might not form.
The aim of this study has been to find the induction time for a given supersaturation at various conditions that can contribute to scale formation. Temperature, pressure, the ionic composition of the water phase, sand in the water and the flow rate are important parameters. The change in pH of the solution has been used to measure the experimental induction time at 80, 100 and 120°C. Experiments have been run with and without sand suspended in the solution by stirring. The sand was from two oil reservoirs in the North Sea. The effect of Mg 2+ and SO42 ions on
