Simulation of CO2-water-rock interaction processes-mineral scaling problems in saline formations

Abstract

Many problems may occur in the process of CO2 injection which usually lasts for many years. Injection efficiency depends on many factors, such as temperature (T), well bottomhole pressure (P), well heading pressure, injection rate, reservoir properties (porosity, permeability, wettability) and scales of some minerals. The scaling problem in the wellbore and near-well region in reservoir (usually a few meters away from the borehole), may have a large negative effect on the reservoir properties such as a decrease in porosity and permeability near the well borehole region. As a result, the amount of CO2 injected will be restricted. The purpose of this study is to predict mineral scales formation and distribution that happen in near-well reservoir using the simulation method. In this paper, TOUGH2 and TOUGHREACT software are used, and a 1D model has been set up. In this benchmark simulation of scaling problems, T and P are chosen to be at 100°C and 4MPa respectively. Simulation results show that pressure and gas saturation of the reservoir had been changed greatly after CO2 injection. Illite and calcite may be the main mineral scales in the near-well region. At different time after the injection of CO2, there are different changes of mineral types and mineral volume, illustrating that at the beginning of the injection period, the precipitated minerals are illite, oligoclase and calcite, with time, ankerite, smectite-Ca and dawsonite will precipitate. In order to control the scale problems and alleviate destruction of the reservoir and petroleum equipment, chelants (such as EDTA, DTPA) should be used. © Springer-Verlag Berlin Heidelberg 2013.