Abstract
Carbon capture and storage (CCS) has been identified as a part of the solution to the climate crisis, but to play a major role, a massive scale-up is required. This will inevitably lead to a need for drilling wells into existing CO2 storage formations, and with that comes the risk of well control incidents where the influx from the formation into the well is dominated by CO2. A major concern regarding such incidents is the potential formation of hydrates caused by Joule-Thomson cooling when the CO2 loaded drilling fluid is forced through flow restrictions while being circulated out of the wellbore or when flowing through topside valves.
Software tools incorporating mathematical models for hydraulics and flow in the well play an important role in risk assessment related to drilling operations. To evaluate the risk of hydrate formation and subsequent plugging of valves and flow restrictions, a tool that sufficiently well captures the relevant thermodynamics and flow physics may be of crucial importance. By combining existing hydraulic flow models for drilling and well control operations developed for petroleum wells with new sub-models describing Joule-Thomson cooling and hydrate formation risk in the presence of CO2, such a tool can be built. To achieve accurate models, laboratory experiments of hydrate formation in drilling muds loaded with CO2 are required.
In order to enable a software tool for evaluating and handling risks related to hydrate formation during CO2 well control incidents, researchers and industry actors here work together to close knowledge gaps and provide the understanding of the physics involved that is required. We present experimental methods and lab results on hydrate formation in drilling fluids loaded with CO2 along with considerations on modelling aspects. This includes thermodynamical sub-models, integrated hydraulic models and the development of a software tool for use in operations planning and execution. Finally, the impact from such a tool for contributing to reducing the risk for hydrate formation related to drilling of CO2 infill wells is discussed.
Software tools incorporating mathematical models for hydraulics and flow in the well play an important role in risk assessment related to drilling operations. To evaluate the risk of hydrate formation and subsequent plugging of valves and flow restrictions, a tool that sufficiently well captures the relevant thermodynamics and flow physics may be of crucial importance. By combining existing hydraulic flow models for drilling and well control operations developed for petroleum wells with new sub-models describing Joule-Thomson cooling and hydrate formation risk in the presence of CO2, such a tool can be built. To achieve accurate models, laboratory experiments of hydrate formation in drilling muds loaded with CO2 are required.
In order to enable a software tool for evaluating and handling risks related to hydrate formation during CO2 well control incidents, researchers and industry actors here work together to close knowledge gaps and provide the understanding of the physics involved that is required. We present experimental methods and lab results on hydrate formation in drilling fluids loaded with CO2 along with considerations on modelling aspects. This includes thermodynamical sub-models, integrated hydraulic models and the development of a software tool for use in operations planning and execution. Finally, the impact from such a tool for contributing to reducing the risk for hydrate formation related to drilling of CO2 infill wells is discussed.