Simulating salt precipitation during CO2 injection in brine aquifers

Abstract

Carbon capture and storage (CCS) is a potentially very useful way of reducing anthropogenic CO emissions whilst continuing to be able to use fossil fuels. In CCS, CO is prevented from entering the atmosphere by being captured from power plants and stored long-term, most commonly by being injected into rock formations deep underground. Saline aquifers have been strongly considered as target formations for CO storage due to their common occurrence, large storage volumes and suitable depths. However, injecting CO into a saline aquifer can remove liquid water from the site of injection, both by the water being displaced immiscibly by the advancing gas and by some water evaporating into the carbon dioxide-rich gas phase, which can cause formation dry out, leading to salt precipitating in the pores of the rock around the injection well. This salt precipitation can be enhanced by high capillary pressure gradients in the dry out zone of the formation, which provide a driving force for brine to flow back towards the site of injection in a process called counter-current imbibition, hence providing additional salt that can also precipitate. There is a concern that the loss in permeability and injectivity caused by this salt precipitation may be a limitation in the use of saline aquifers for carbon sequestration.

This work aims to simulate the build-up of salt precipitation in a saline formation when CO is injected, in order to investigate the effects that various parameters have on salt precipitation and, ultimately, whether storing CO in saline aquifers is a feasible method of CCS. To do this, finite difference methods and MATLAB's ordinary differential equation (ODE) solvers are used to form numerical models of both two and three phase flow within an aquifer. Pseudospectral methods are also used to find a similarity solution for three component and three phase flow. All models and solutions incorporate the effects of partial miscibility between phases and capillary pressure, both of which have been neglected in some previous studies on this subject.

It is concluded that there are several factors that affect the volume fraction of salt precipitation around the injection well of a saline formation caused by CO injection, , including the salinity of the brine, the storage depth and the relative permeabilities, but the value is largely controlled by a capillary number, Ca. This takes into account the effects of the thickness, permeability and air-entry pressure of the formation and the injection rate and dynamic viscosity of CO. As Ca decreases, the value of superlinearly increases. In one scenario studied, reducing the CO injection rate from 15 kg s to 0.9 kg s led to a tenfold increase in the volume fraction of precipitated salt.