Resident formation water vaporization in the near well zone may pose challenges for carbon dioxide (CO2) storage operations. If dry CO2 is injected into a reservoir, the brine in the very near well zone will evaporate into the CO2 stream, leaving behind precipitated salts. This paper introduces a simple thermodynamic scale prediction approach to quickly identify salts that could precipitate at an injection site and subsequently lead to loss of injectivity and escalate the cost of capture operations. With this method, operators can forecast likely flow assurance related injectivity issues prior to injection of CO2 and plan their injection schemes and mitigation strategies, if necessary.
To conduct this study, formation water compositions were obtained from the literature for various formations worldwide, and compiled into a spreadsheet. The work of Talman et al. (2019) was used as a baseline for precipitation calculations as it clearly identified salt precipitation at an active CO2 injection site – the Aquistore project in Saskatchewan, Canada – which has salinity greater than 300,000 mg/L. The analysis of the compiled data was divided into two parts.
- Part 1 focused on demonstration, previous and operational carbon sequestration projects worldwide.
- Part 2 focused on fields in the UK Southern North Sea. The existence of gas fields in the UK Southern North Sea near major regions of CO2 emission and the presence of this mature gas province with many fields close to cessation of production makes it a desirable candidate for CO2 storage. With some fields in this region suspected to be connected and communicating, attempt was made to infer possible connectivity/compartmentalization between fields by evaluating the available salinity of formation waters compiled from literature and annotating on the North Sea Transition Authority Offshore interactive map for further studies.
