Study Assesses Effects of Carbon Dioxide on Drilling-Fluid Performance in CCS Wells

Abstract

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 217711, “CCS Well-Control Impact of CO2 on Drilling-Fluid Performance,” by Jan O. Skogestad, SPE, Blandine Feneuil, SPE, and Elie N’Gouamba, SPE, SINTEF, et al. The paper has not been peer reviewed. _ Drilling carbon-dioxide (CO2) storage wells is a task expected to involve handling an influx of CO2 into the drilling fluid. In the study described in the complete paper, experimental characterization of density, rheology, phase envelope, hydrate formation, and drilling-fluid stability are performed on drilling fluids mixed with CO2 for relevant pressures and temperatures. Based on these experiments and verified thermodynamic model descriptions, local models for properties of drilling-fluid/CO2 mixtures were developed and integrated into an existing drilling software suite. Requirements for Enhanced Well-Control Software Well-control-evaluation software based on sophisticated and verified models of the drilling-fluid/gas interaction in the wellbore plays an important role in planning drilling operations. The software also can be used to evaluate the strategy for circulating out a kick and regaining control of the well. When drilling infill wells into CO2 storage sites, this software must be able to process kicks originating from both CO2 and natural gas influx. To achieve this ability, knowledge gaps related to the interaction of CO2 and drilling fluid must be closed. Hydraulic-flow models need to be enhanced with local models that capture the unique properties of CO2 and how it affects drilling-fluid performance. Starting from carefully devised experimental campaigns, the authors developed local models for drilling-fluid/CO2 interaction that were integrated into an existing hydraulic flow model. A well-control-evaluation product for use during planning and execution of infill drilling operations into CO2 storage reservoirs may then be built using the upgraded models. Experimental methods, equipment, and setup are detailed in the complete paper. Experimental Results Bubblepoints. Bubblepoint experiments in the base oil have been performed with CO2 weight content from 4 to 50% of the total weight of the mixture and at room temperature and 50 and 100°C. All measurements have been repeated at least once. At room temperature, CO2 can be dissolved in oil at mass fractions of up to approximately 50%. The bubblepoint increases when the temperature increases (i.e., the solubility decreases). As with base oil, the solubility of oil-based drilling fluid (OBDF) decreases with temperature. The bubblepoint at room temperature with 25% of CO2 by weight of the mixture is approximately 60 bar, roughly the bubblepoint of pure CO2. Therefore, the maximal solubility of CO2 in OBDF is probably below 25%. To compare the measured solubility in base oil and in OBDF, the CO2 content relative to the base oil has been calculated using the OBDF composition provided by the manufacturer.