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IEA Greenhouse Gas R&D Programme



This report focuses on collecting industry experience on the drilling, completion, regularity and interventions of CO2 wells.  The aim for the report was to compare methodologies and techniques used for handling CO2 compared with those required for hydrocarbon extraction.  This has allowed for a comparison to be made to the research already conducted on CO2 well integrity and monitoring techniques. The study will investigate whether conditions experienced during CO2 handling operations were predicted from modelling and experimental work and the effectiveness of linked risk assessments.


The differences between hydrocarbon and CO2 operations are driven by acidification of drilling muds, the high expansion factor of CO2 (going from liquid to gas phase), the effect of CO2 on elastomeric seals and finally the cooling behaviour of CO2 (which under uncontrolled depressurisation could chill equipment to temperatures below minus 70°C).  Furthermore there is the potential to form CO2 hydrates if water is present.  Also, temperature and pressure cycling due to phase-wise injection (e.g. if CO2 is delivered by boat) can strain the well equipment.  Other wellbore integrity issues were also identified during a recent IEAGHG Modelling and Monitoring network meeting in July 2016.  These included: timing and frequency of integrity log requirements; an improved understanding of cement pathways and a different (non-Darcy) approach to modelling flow in open wellbores.  The choice of completion fluids could also be impacted by the presence of CO2 in the injection tubing and the potential of acidification of annular fluids should a tubing leak occur.


Key Messages


  • The ability to inject CO2 regularly needs to be addressed in the planning stages of storage projects to assess future well performance. For wells exposed to formations containing supercritical CO2 it is important to identify the procedures and equipment that have to be tailored for the specific characteristics of CO2 (as opposed to hydrocarbon gas, oil or water).


  • Industry experience with CO2 EOR wells (both for CO2 continuous injection as well as for CO2-WAG) shows that new CO2 injection wells can be suitably designed to allow well integrity to be maintained in the long-term. Concerns from cement degradation and corrosion can be suitably addressed in the design and construction of these wells. Industry experience also indicates that CO2 storage injection wells can also maintain wellbore integrity if designed, constructed, operated and monitored as per current state-of-the-art design specifications and regulatory requirements.


  • Risks from legacy wellbores can also be adequately addressed as long as sound engineering practices and compliance with current and more stringent regulatory requirements are complied with.


  • The handling and managing CO2 wellbore operations safely is well established from CO2 EOR projects. Initial industry concerns about CO2 injection, especially during the water-alternating-gas (WAG) process in terms of controlling the higher mobility gas; water-blocking, corrosion, production concerns, oil recovery, and loss of injectivity have been addressed with careful planning and design along with good management practices.


  • Although there are a number of common areas between CO2 EOR and CO2 storage wells, the differences can be grouped under five broad categories: (1) operational, (2) objectives and economics, including CO2 supply, demand and purity, (3) legal and regularity, (4) long-term monitoring requirements, and (5) industry’s experience. There are no specific technological barriers or challenges per se in converting or adapting a pure CO2 EOR operation into a concurrent or exclusive CO2 storage operation.


The costs associated with CO2 EOR and CO2 storage projects are site and situation-specific. In general, oil prices have by far the larger impact on the economic viability of a CO2 EOR project, with the second largest impact being the cost of CO2.

This report is free to download.