CO2 can be an effective EOR agent and is the dominant anthropogenic greenhouse gas driving global warming. Capturing CO2 from industrial sources in EOR projects can maximize hydrocarbon recovery and help provide a possible bridge to a lower carbon emissions future, by adding value through EOR production and field life extension, and providing long term secure storage post-EOR operations.
Shell is working to implement new generation CO2 projects, including offshore applications. Based on recent offshore project design experience, this paper describes the challenges in moving CO2 EOR from onshore to offshore and the solutions developed, in the key areas of safety, facilities, wells, subsurface and piloting. The overriding design principle in any project is HSE. Offshore operations brings a new set of challenges over inventory, pressure, confined spaces and evacuation, with conventional emergency procedures requiring modification because of the different physical characteristics of CO2 releases compared to hydrocarbon gas. Surface facilities need to be simple to minimise CAPEX, weight and space while maintaining flexibility, since there is less scope to incrementally evolve the surface facilities as is the case onshore. Balancing the tension between these objectives requires very close surface and subsurface integration to find optimal and cost-effective solutions.
This is illustrated with three key decision areas: gas treatment options for back produced CO2 and hydrocarbon gas, artificial lift and facilities capacity.
A novel integrated CO2 gas lift system is described. This simplifies facilities and reduces CAPEX and OPEX, while at the same time providing a high degree of flexibility and risk management over the EOR life cycle in terms of subsurface uncertainty and reducing the issues around molecular weight variation in the recycled gas and the degree of turndown required in the facilities in the early years of EOR operations.
CO2 is the dominant anthropogenic greenhouse gas that is believed to be driving global warming and climate change. Carbon capture and storage (CCS) is a technology that may contribute to reduction in CO2 emissions. However, CO2 capture from flue gas sources with current technology is CAPEX and energy intensive, so that the cost of CO2 abatement with CCS is high.
At the same time CO2 is an effective miscible flooding agent for EOR. Capturing CO2 from industrial sources for use in EOR projects can maximize hydrocarbon recovery and help provide a possible bridge to a lower carbon emissions future. Firstly, by adding value through additional oil recovery and field life extension, which can offset part of the cost of CO2 capture, and secondly, by providing long term secure storage after EOR operations have been completed.
Moving from onshore to offshore
Existing CO2 EOR projects are all onshore, with the majority of projects supplied with CO2 from natural subsurface sources. A minority of projects is based on captured CO2 from anthropogenic sources, with the largest being the Weyburn CO2 EOR and storage project, using CO2 captured from a coal gasification plant . Operating offshore CO2 injection has so far been restricted to storage of CO2 produced from gas processing plants, with the Sleipner  and Snøhvit  projects each injecting around one million tpa of CO2. Maximising value from disposal of CO2, (whether this is from low cost sources such as gas processing plants or more expensive flue gas capture) requires suitable EOR target fields, and in regions such as Europe and the Far East, large scale operations require moving CO2 EOR offshore into the major hydrocarbon basins.
Russell, Kenneth A. (Schlumberger) | Cockburn, Colin (Schlumberger) | McLure, Ruairidh (Schlumberger) | Crawford, Adrian (Shell U.K. Ltd.) | Davison, Mark (Advanced Geotechnology Inc.) | Jolley, Steve J. (Shell U.K. Ltd.) | Kazi, Mudasser (Shell U.K. Ltd.) | Koster, Martin (Shell U.K. Ltd.) | McGrath, Barry (KCA Deutag)
This paper describes an example of drilling-hazard mitigation.Itdemonstrates how a completely fresh approach, involving geomechanical analysis,planning of a new revised well trajectory, and real-time well monitoring, canreduce nonproductive time and cost and mitigate against unplanned terminalevents.
Recent drilling operations in a mature field in the North Sea were severelydisrupted by wellbore deterioration, stuck pipe, and lost-circulationincidents. A complex geological sequence of tilted fault blocks and partiallydepleted reservoir sands made well-trajectory and wellbore-stability planningdifficult. After two unsuccessful sidetrack attempts, an integratedoperator/contractor team performed a detailed audit of the drilling problemsand built a geomechanical Earth model to evaluate drilling hazards and developstrategies to mitigate any further wellbore instability. Well objectives werere-evaluated, and a new approach to the drilling process was developed. The keywas simplification of the well path. The operational solution featuredmanagement of drilling hazards through a real-time risk-mitigation process.Additional engineers at the wellsite managed drilling parameters; continuouslymonitored cavings, cuttings, and drill fluids; and analyzed drilling mechanicsand logging-while-drilling (LWD) log data for indications of impendingproblems. A Web-based real-time data-transfer system was used to deliver datato the onshore drilling and subsurface teams. These methods, combined withadvanced communication techniques, enabled tight control of drilling parametersand trajectory and enhanced collaborative understanding within themultidisciplinary team. The third sidetrack was completed without incident,within time, and under budget.