Abstract
When dry supercritical CO2 is injected into a saline aquifer for storage, formation brine is displaced away from the wellbore. However, not all the brine is displaced. Residual brine is trapped behind the CO2 flooding front, and formation water may re-enter the near wellbore area under shut-in conditions. The water in this brine will evaporate, causing precipitation of salts. A numerical model is used to evaluate the risk of loss of injectivity in a North Sea candidate Carbon, Capture and Storage (CCS) aquifer.
The objectives of the study presented in this paper are to use a radial model of the near well zone in the candidate aquifer to:
Evaluate the risk of water evaporation due to CO2 injection under the field-specific conditions.
Evaluate the risk for the reduction of porosity, permeability, and injectivity under a continuous injection scheme and a discontinuous injection scheme.
Evaluate the threshold injection rate for salt precipitation to occur.
Identify what is the worst halite scenario that can be predicted by modelling in this field case.
In this case study, for all salinities evaluated, there is always some halite precipitated in the dry-out zone. However,
For most of the sensitivities, there is insignificant injection damage arising.
For a salinity of 1.2 M, the only sensitivities that led to observable loss of injectivity were when the injection flow rates were very low.
Significant damage would require high salinity formation water (near saturation) or the combination of capillary and gravity forces to replenish brine in the dry-out zone very close to the well, such that replenishment flux would match evaporative flux.
Maintaining a high injection flow rate reduces halite precipitation risk when viscous forces dominate.
This paper presents a methodology for evaluating the risk of halite precipitation during CO2 injection in aquifers and then uses that methodology to evaluate the risk for a specific North Sea CO2 storage project, identifying in this case minimal risk.
