Modelling Halite Precipitation During CO2 Injection in a Heterogeneous Reservoir: A North Sea Field Case

Abstract Reservoir injectivity and storage efficiency may be put at risk during CO2 injection in a complex and compartmentalized saline formation with variable reservoir quality due to the salting-out effect. Consequently, a risk assessment of injectivity loss due to halite precipitation in the near-wellbore formation is required. This study investigates the influence of heterogeneity on reservoir dynamics under specific field conditions and the impact of salt deposition in a multi-layered fluvio-deltaic system. Numerical simulations were performed using a reactive transport compositional model. 2D radial models were developed to identify near-well injection effects (evaporation, deposition, imbibition and crossflow between the layers) and then calculate the extent of the dry-out zone, porosity changes and injectivity changes. The injection of dry CO2 at a constant rate of 0.77 Mt/yr for 360 days into a candidate aquifer with a salinity of 160 g/L was modelled. The well was completed in a target formation 80 m thick with three sandstone units separated by interbedded shales. The bottom layer has the highest reservoir quality, and the middle layer has the lowest. The results show that because there is no hydraulic communication between the layers due to the barriers to vertical flow, most of the CO2 flows preferentially into the highest permeability layer, despite it being the deepest. After 90 days of injection, dry-out radii of 1.2m, 1.1m, and 3m were observed for the top, middle and bottom layers, respectively, resulting in significant loss of effective porosity in the rock adjacent to the well, especially in the deepest layer. The wellbore pressure increases by 10,000kPa (100 bars) and reaches the fracture pressure within 70 days of injection due to complete blockage of the sandstone units. The profile of injectivity vs time shows that injectivity increases within the first few days of injection due to an increase in gas saturation around the well; however, subsequent halite precipitation more than reverses this advantage. Capillary-driven counterflow imbibition in the horizontal direction means that there is continuous re-saturation of the dry-out zone with brine that evaporates, adding to the amount of salt deposited, thus reducing the injectivity by an order of magnitude. Additional calculations show that there would have been crossflow of brine into the middle layer if the interbedded shale layers had been absent. This paper presents a methodology to evaluate the impact of geochemical processes, such as halite deposition, which is useful for assessing the risk of formation damage during CO2 injection projects. It may also provide information for improved reservoir pressure management and well-intervention operations, such as freshwater preflushes or water-wash scheduling to alleviate permeability loss and increase injectivity.