# Effects of permeability, grid resolution, and carbonate reactions on CO2 distribution and sulphate scaling in seawater-flooded carbonates

## TL;DR

This study explores how CO2 distribution, temperature, and other factors affect scaling risks in oil reservoirs flooded with seawater.

## Contribution

The study introduces the role of CO2 partitioning from hydrocarbons into injected water in scaling predictions, which was previously overlooked.

## Key findings

- Calcite dissolution and magnesium-rich carbonate precipitation are interdependent and influenced by CO2 in residual oil.
- Temperature changes near injection wells impact solubility of minerals like anhydrite and gypsum.
- Managing CO2 distribution and reservoir conditions can reduce scaling risks while maintaining oil recovery.

## Abstract

During oilfield production, mineral scale deposition in production wells and surface facilities presents major difficulties, particularly when water breakthrough occurs. Hard sulphate scales, like barite, are frequently the result of incompatible interactions between the formation and injection waters. In contrast, carbonate scales are caused by variations in the temperature, pressure, pH, composition of the brine, and the amounts of CO2 in the aqueous and hydrocarbon phases. In waterflooded reservoirs where injection water composition can be controlled, this study investigates the effects of temperature, ionic concentration, pH, and CO2 availability on the risks of carbonate and sulphate scaling. Particularly, scaling hazards in carbonate-rich formations are greatly influenced by precipitation of magnesium-rich carbonate. The significance that CO2 partitioning from hydrocarbons into injected saltwater plays in scaling estimates has been ignored in earlier studies. To close this gap, this study investigates how temperature and reservoir pressure affect oil recovery and scale management, particularly in systems that dip below bubble point pressure. A commercial reservoir simulator, which couples aqueous and mineral geochemistry with three-phase fluid flow calculations, has been used in this study. Equilibrium reactions have been considered in three-dimensional (3D) models. Oilfield data have been used to identify the parameters of significance to consider in the calculations, such as ionic concentrations, hydrocarbon composition, mineral components etc. Key findings, importantly, the results identify that for the reservoir temperature of 100 °C considered and for the primary mineral assemblage, calcite dissolution and magnesium-rich carbonate precipitation are interdependent. They are affected by the abundance of CO2 in the residual oil phase, and this evolves over time, impacting the concentration of calcium and magnesium in the brines traversing the reservoir. Temperature changes around the injection wellbore also impact component and mineral solubilities, especially in terms of anhydrite and gypsum reactions. All these factors impact the calcium, magnesium, barium, strontium, sulphate and bicarbonate concentrations at the production well, and hence the scaling risk in the production system. In conclusion, managing reservoir conditions such as temperature, ionic concentrations, and CO2 distribution is important for reducing the likelihood of scale deposition while preserving oil recovery in carbonate-rich, water-flooded reservoirs.