Offshore CCS Parallel Session – April 2016 Manchester Biannual

This blog was written by Clea Kolster who is a PhD student at Imperial College London and received funding to attend the Manchester Biannual Meeting from the UKCCSRC ECR Meeting Fund

The offshore CCS session that took place on the second day of the UKCCSRC biannual in Manchester in April 2016 triggered discussion on a range of issues that come about from deploying CCS in the UK and notably storing CO2 offshore. The latter was split into three talks and topics ranged from understanding the actual storage capacity in the whole of the UK and the risks involved in CO2 storage (Hazel Clyne), to the implications and challenges related to transporting CO2 via pipelines with potential impurities (Kumar Patchigolla) and finally the implications of a flexible transport network on CO2 storage, particularly with respect to the effect that variable store site properties have on plausible CO2 flow injection (Eva Sanchez Fernandez).

Hazel Clyne (Pale Blue Dot Energy) – Storage, Storage, Everywhere
Pale Blue Dot Energy is a management consultancy firm that has been commissioned to lead the Energy Technology Institute’s project, on behalf of DECC, to assess and identify the next phase of offshore and deep underground sites for CO2 storage as part of the DECC CO2 Storage Appraisal Materials. In her talk, Hazel described the drivers behind the project and workflow of this yearlong project that was released in the form of a summary report on April 27th.

As part of the project over 580 potential CO2 storage sites in the UK Continental Shelf (UKCS) were reviewed and through a selection process limited the in depth study to five storage sites: Hamilton, Viking A, Bunter, Captain and Forties 5. Criteria for the selection process that was translated into a score for each site included: having a diversity of sites, having ample 3D seismic coverage of the given site, assessing the potential for enhanced oil recovery of the site (if the latter is a depleted oil field), the reservoir injectivity at the site, and the type of budget required to develop the site.

Hazel also described some of the remaining challenges for each of the five sites selected. The Hamilton and Viking A fields being depleted gas fields are challenged with CO2 phase management in the field since CO2 would be initially injected in gas phase and then with field maturity CO2 would eventually be injected in dense phase. The Bunter field is challenged with assuring long term injectivity, while the Captain and Forties 5 saline aquifer fields are challenged with a potentially low CO2 storage efficiency due to the CO2 plume movement with brine. The report will provide more information on the maturity of these five fields and the operational and capital costs involved in developing them. This study assesses that, although some infrastructure is available around certain sites, the reuse of such is unlikely leaving well facilities costs high. In addition, Hazel points out that these 5 sites only account for about 2% of the storage potential for CO2 in the UKCS.

Kumar Patchigolla (Cranfield University) – CO2 pipeline transport issues
During this presentation Dr. Patchigolla presents Cranfield University’s work on the development of corrosion testing in the context of CO2 transport pipelines as part of the MATTRAN project. This corrosion testing is undergone for bare alloys that would be used for such pipelines and conducted over a range of expected CO2 purities under realistic pipeline conditions. Carbon dioxide would typically be at dense phase conditions and is tested in the presence of SO2 and water. Gaseous CO2 is transformed into dense phase by reaching the supercritical region; above 90 bar and 40C. Dr. Patchigolla describes the experimental kit used to conduct such tests (seen in the presentation slides) limiting the SO2 content to 500ppm. Hence the main parameters impacting pipelines are concluded to be: temperature, pressure, presence of SO2, presence of water, flow regime and flow velocity. The experiments are accelerated in order to conclude on these effects on pipeline corrosion in manageable amounts of time and show that increased hours of exposure leads to higher rates of corrosion in all circumstances. This is more or less severe depending on the type of alloy used.

Eva Sanchez Fernandes (Heriot-Watt University) – Development of Flexible CCS Offshore (FleCCSnet)
Dr. Fernandez describes her work on investigating the link between storage properties and CO2 injection flow and variations in order to highlight some of the key uncertainties and risks involved in a lack of understanding of store properties. Understanding these uncertainties are then key to be able to design a flexible pipeline network for CCS. The storage properties used to conduct the flow analysis of CO2 include:

  • Depth and capacity
  • Subsurface temperature and pressure conditions
  • Geothermal gradient
  • Lithostatic and fracture gradient
  • Permeability
  • Porosity

In this work Dr. Fernandez uses Aspen plus to model the storage site and considers 3 scenarios for stores: open gas field (no pressure change with time), saline formation and a depleted gas field (constant pressure change with time). Some of the assumptions made for this study includes using a maximum pipeline diameter whilst minimizing the number of wells because the cost of drilling more wells is higher than the risk of having a phase change with larger diameter wells. One of the main conclusions from this study is that it is more simple and more viable to adjust the flow of CO2 into the store site depending on its characteristics (with permeability having the largest effect on CO2 injection) rather than risking reduced storage efficiency due to flow variability. This methodology is found to be a very useful way of screening various storage sites as a function of some of their key characteristics.