چكيده به لاتين
Economic production from oil and gas reservoirs faces challenges such as the formation of mineral deposits in wells and production lines. These deposits, such as calcium carbonate and barium sulfate, disrupt equipment performance and increase operational costs. Simulating mineral scale in gas wells requires understanding phase, kinetic, and geochemical processes. The primary challenge is the shift in equilibrium between gas, liquid, and solid phases due to temperature and pressure variations. Thermodynamic models like the Peng-Robinson equations are used for accurate phase equilibrium calculations; however, they come with uncertainties, particularly under critical conditions. Additionally, the growth rate of deposits depends on kinetic parameters, requiring precise experimental data. Geochemical interactions between water, gas, and minerals must also be accurately simulated, for which software like PHREEQC is employed, though it may not cover all reactions comprehensively.
Accurate simulation requires complete field data on temperature, pressure, and fluid composition, but these data are often incomplete or inconsistent. In this study, a model was developed using PHREEQC, PVT, and PIPESIM software, combining thermodynamic, hydrodynamic, and kinetic processes for more precise mineral scale predictions. This model can help improve well productivity, extend well life, and reduce costs associated with scale deposits.
In a case study of a gas condensate reservoir experiencing significant carbonate deposition in the wellbore, simulation results successfully matched the equilibrium saturation index behavior for two initial calcium concentrations (28 and 300 mg) in formation water with reference data from a published study. The maximum mass of scale formation in this simulation was estimated to be between 41 and 442 kg, which, compared to the reported values in the reference (38 to 405 kg), shows an approximate error of 8.3%. Furthermore, over a 200-day period, the maximum scale thickness was predicted to be 4.6 inches. The obtained results were compared with another simulation of the same well, showing similar predictions regarding the location of scale deposition.
