As the major fields which have been the mainstay of global oil production mature, there is a need to apply new technology and recovery techniques to extend field life and maximize economic recovery. As a result, there is growing interest in using CO2 for miscible flooding, where that is appropriate. Much of the current experience of CO2 EOR has been in the US Permian Basin, based on using CO2 sourced from high CO2 content subsurface sources. While significant CO2 EOR potential exists in many basins around the world, application of CO2 EOR is often limited by the availability of CO2 at an acceptable cost. This paper addresses the key issue of CO2 sourcing for CO2 EOR in new basins in which CO2 is the most suitable miscible fluid and the different subsurface conditions encountered with the need for subsurface/surface integration.
The full potential for CO2 EOR to increase recovery factors will only be realised if supply options can be developed for EOR projects in locations that do not have access to an existing CO2 infrastructure. Value chains linking industrial sources of CO2 to appropriate field targets are expected to be the key enabler. Robust technical and non-technical integration across the capture-transport-injection chain is required, to ensure that the potentially competing operational requirements for capture and EOR usage are reconciled, and that commercial and regulatory considerations are addressed. CO2 capture options and a methodology for developing CO2 supply options will be described and illustrated with experience from the development of CO2 value chains for CCS demonstration projects such as Peterhead, Quest and Boundary Dam.
CO2 EOR is recognized as having significant potential to increase recovery in many basins around the world. However, the absence of CO2 from either natural reservoirs or affordable anthropogenic CO2 has limited its development. This paper discusses CO2 EOR and different sources of CO2, the challenges associated with developing a CO2 value chain to supply EOR projects and Shell’s experience in the development of CO2 projects.
Global Potential for CO2 EOR
One source estimates the global potential for CO2 EOR is in the order of 1.3 trillion barrels of oil [Godec, 2012] with the majority in the United States, the Middle East/North Africa and the Former Soviet Union.
Onshore CO2 EOR is an established industry in North America with a long history in West Texas (where Shell was a pioneer) and is accepted as a standard industry development technique. The US DoE [Kuuskraa, 2011] has identified 67 Bstb oil economically recoverable with Next Generation CO2 EOR (assuming CO2 supplied at $40/tonne and a 20% return on investment before tax) out of a total of 137 Bstb of technically recoverable oil. This would require 18 Giga tonnes of anthropogenic CO2 captured from power plants and other industrial sources. Therefore, while significant CO2 EOR potential exists in many basins around the world, application of CO2 EOR is often limited by the availability of CO2 at an acceptable cost.
Sorop, Tiberiu Gabriel (Shell Global Solutions International) | Suijkerbuijk, Bart M.J.M. (Shell Global Solutions International) | Masalmeh, Shehadeh K (Shell Technology Oman) | Looijer, Mark T. (Shell Global Solutions International) | Parker, Andrew R (Shell Global Solutions International) | Dindoruk, Deniz M (Shell Exploration & Production Co) | Goodyear, Stephen Geoffrey (Shell E&P UK) | Al-Qarshubi, Ibrahim S.M. (Shell Global Solutions International)
Low Salinity Waterflooding (LSF) is an emerging IOR/EOR technology that can improve oil recovery efficiency by lowering the injection water salinity. Field scale incremental oil recoveries are estimated to be up to 6% STOIIP. Being a natural extension of conventional waterflooding (WF), LSF is easier to implement than other EOR methods. However, the processes of screening, designing and executing LSF projects require an increased operator competence and management focus compared to conventional waterflooding. This paper discusses the practical aspects of deploying LSF in fields, focusing on the maturation stages, while highlighting the key success factors.
LSF deployment starts with a portfolio screening against specific surface and subsurface screening criteria to prioritize opportunities. Next, the identified opportunities are run through reservoir conditions SCAL tests to quantify the LSF benefits, while de-risking the potential for any injectivity loss due to clay swelling or deflocculation. Standardized LSF SCAL protocols have been incorporated into the general WF guidelines, so that any suitable new WF project conducts LSF SCAL. For mature waterfloods, this SCAL program provides additional reservoir condition relative permeability data, enabling operating units to optimize well and reservoir management (WRM). The next steps in the process are production forecasting, facilities design, and project economics for the LSF opportunity. The multidisciplinary nature of LSF deployment requires integrated (sub)surface technology teams closely collaborating with R&D and asset teams. The standardization of the facilities design, including cost models, can significantly accelerate the deployment effort.
In Shell, LSF is currently at different stages of deployment around the world and across the whole spectrum of WF projects, from the rejuvenation of brown fields to green field developments (offshore and onshore). The LSF deployment effort is combined with the screening of other EOR technologies, to identify where LSF may be able to unlock additional value by creating the appropriate conditions for subsequent chemical flooding.
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.