Due to COVID-19 precautions, the US Department of Energy (DOE) National Energy Technology Laboratory (NETL) CCUS Integrated Projects Review meeting was held as a virtual event over 17-19 August, instead of at its usual location in Pittsburgh. These events provide very informative updates on the DOE NETL funded CCUS projects. The online attendance was good, over 500 registered. The event was opened by Steve Winberg, Assistant Secretary for Fossil Energy, who gave an update on US energy R&D policy, including the memorable line "we might have seen toilet paper supplies getting scarce at times, but electricity supply stayed steady". He talked of the impressive CCUS project portfolio being based on good collaboration between industry, universities and national labs. Looking forwards, he anticipated more R&D into direct air capture (DAC), and hydrogen from coal and natural gas, wanting to "jump-start the hydrogen economy with CCUS".
Mark Ackiewicz, Director of the Division of CCUS R&D at DOE, gave an update on the CCUS programs. This included that 23 Mt of CO2 has now been injected by DOE projects, and there will be new funding opportunities for DAC and capture from industrial sources.
CarbonSAFE Phase 3 projects
Five contributors updated audiences across the US and beyond on plans for Phase 3 regional CO2 storage development.Each of these projects are representative of potential large-scale CCS and CCUS hubs capturing CO2 from significant point sources.They include:
- North Dakota (ND) CarbonSAFE Phase III: Site Characterization and Permitting (UNDEERC)
- Wyoming CarbonSAFE: Accelerating CCUS at Dry Fork Power Station (UofW)
- Illinois Storage Corridor (Univ. of Illinois)
- Establishing an Early CO2 Storage Complex in Kemper County, Mississippi
- San Juan Basin CarbonSAFE Phase III: Ensuring Safe Subsurface Storage of CO2 in Saline Reservoirs
In 2019 the original seven Regional Carbon Sequestration Partnerships were reorganised to form four new regional initiatives broadly divided into the north-east, south east, west and central north of the contiguous US.Some adjacent Canadian provinces are also included in the central north area.There are representative CarbonSAFE Phase 3 projects in all these areas.
Each Phase 3 project has a series of ambitious objectives including the design and implementation of commercial scale storage, in some case at two different sites, and linked to associated capture demonstration.In most cases CO2 capture will be installed at relatively new coal-fired power plants.At most sites between 5 and 6 Mt CO2/year will be captured and injected into deep saline formations; or in the case of Wyoming CarbonSAFE, North Dakota CarbonSAFE and in the San Juan Basin also connected to local pipeline networks for CO2 enhanced oil recovery.CO2 will also be captured from a bioethanol plant in Illinois.
Detailed storage site characterisation is planned at each site from drilling new wells and commissioning new 2D and 3D seismic.Information from the Phase 2 and 3 stages will also be used to prepare permit applications for Class VI wells, injection and closure plans.San Juan Basin CarbonSAFE is exceptional because there were no previous stages.In each case detailed design is also necessary for cost estimation and to take advantage of the 45Q tax credit incentives.
Stacked storage is a notable feature of four sites ND, Wyoming, Kemper Co. Mississippi, and San Juan NM.Stacked storage enables CO2 injection into two / three suitable formations within a geological succession at one locality.This approach increases storage capacity at one location with minimal pressure build up.
This exciting new phase is already underway with drilling anticipated as early as this September.With detailed characterisation of storage complexes, combined with new point sources, the gateway to potentially large-scale regional CCS hubs is now a reality.
Battelle gave an update on the Integrated Midcontinent Stacked Carbon Storage (IMSCS) Hub which is part of the CarbonSAFE Phase 2 and is looking at gathering CO2 from the eastern andcentral northwest area of the US and transporting it southwest for storage along a stacked storage corridor. The IMSCS Phase 2 objectives include demonstrating multiple 50 Mt storage sites for CO2 storage, demonstrate long-term seal integrity and minimise induced seismicity, develop strategies to manage and store CO2 from multiple sources, to scale the data collected to develop a regional commercial enterprise, to mitigate public outreach and regulatory barriers and to develop a commercial development plan. The project has evaluated three candidate storage sites and identified great stacked storage potential in alternating sequences of deep saline formations, oil-bearing reservoirs, shale and evaporate units. Recent work includes new feasibility data collection, updating of static earth models, updating of dynamic and geomechanical modelling, new 3D seismic analysis, core and log analysis updates and well testing updates. In terms of CO2 management and commercial development, the work identified 17 technically and economically feasible oilfields in the storage corridor. Estimates of the storage resource are 577.4 Mt of CO2 with the potential to produce 181.9 MMbbls of oil via EOR, with an estimated gross revenue for stacked storage and EOR at the 17 fields of US $30.9 billion.
Outreach efforts found interest among industry stakeholders and the risk assessment done showed that all components of a CCUS project are feasible.
Six speakers discussed the FEED study projects, covering post-combustion capture technologies implemented in the power sector, either treating the flue gas from a coal or natural gas power plant. As in previous years, chemical absorption and membranes-based systems were leading the list of large scale testing projects.
In regards to the solvent-based chemical absorption, five projects presented their last results. Three of them included testing on NGCC (Natural Gas Combined Cycle) power stations, while two will carry out the testing on coal-fired power plants:
- Bechtel National Inc. presented the last developments of their collaborative project. Their objective is to retrofit a NGCC (758 MWe power plant in Sherman, Texas) with a non-proprietary solvent. The testing will contribute to the new system reaching the TRL 9 and solving challenges linked to the steam extraction complexity.
- University of Texas at Austin presented their advanced stripper and the piperazine (PZ)-based solvent to treat the NGCC flue gas (4% CO2 content). This system will be implemented together with a low water consumption strategy.
- EPRI presented their chemical absorption process based on the Fluor's proprietary EFG+ aqueous amine technology to be implemented in a NGCC (550 MWe power plant in Kern County, California). Moreover, they showed their strategy to reduce the water consumption, and the constructability challenges.
- University of Illinois presented the large pilot testing at a coal-fired power plant with the BASF OASE blue solvent and advanced configuration. They showed their approach to minimise solvent losses, steam consumption in the regenerator, CO2 compressor cost and power consumption.
- University of Kentucky Research Foundation presented the UKY-CAER heat integrated transformative CO2 capture process for pulverized power plants, where a second-generation solvent is used. Based on previous testing at bench and small pilot, the equipment will be smaller, and the operation costs will be lower.
Common to all the chemical absorption-based projects, the decrease on capture costs is one of the main objectives. Strategies to achieve a lower capture cost include the use of advanced solvents with lower energy consumption, and modified configurations (more information on emerging CO2 capture technologies and configurations can be found in IEAGHG 2019/09). The reduction of capture costs over the last years is noticeable, with some preliminary cost analysis showing approximately 40$/ton CO2 captured. Moreover, also noticeable in these projects is the implementation of water reduction strategies, aiming to demonstrate the viability of CO2 capture systems in water stressed regions (more information on water reduction strategies can be found in IEAGHG 2020/11).
In regards to the membrane-based systems, MTR presented their large testing of the new integrated planar membrane modules, aiming to reduce costs and increase packing density. This technology will be tested at TCM as part of another funded project.
In addition to cheaper advanced configurations, new policies such as the 45Q has been a supportive tool to build up the business case, together with the revenue from using the CO2 such as in EOR.
In summary, this session provided information about emerging CO2 capture systems, the scalability of post-combustion technologies, and the potential to reduce capture costs and water consumption simultaneously. These key issues confirm the technical feasibility of CO2 capture technologies and integrate learnings from experience, reducing costs and showing that some systems are ready to be implemented in the power and industrial sectors.
We are looking forward to the future edition next year. In the meantime, we will continue monitoring the results of these projects and we will keep track of latest developments during GHGT-15 (March, 2021).
Ernst Axelsen and Arne Kolle updated on the Technology Centre Mongstad (TCM) in Norway which is now operated by the Norwegian state (managed by Gassnova), Equinor and Shell. The next operating period of the centre is from 2020-2023 and the team have strong ambitions onwards to 2030, aiming to become a competence centre as well as a testing centre. Currently, work is ongoing to develop a new site for the testing of emerging technologies which will begin investigations in 2021. TCM has a strong pipeline of activities with a clear strategy towards 2025, spanning a wide range of technology testing and advisory services.
The Northern Lights project was introduced by Mike Carpenter and Audun Rosjorde (Gassnova), who noted that the FEED and FID studies have now been completed and the next step is awaiting the financial decision from the Norwegian government. The CCS value chain plans to be in operation in 2023-2024, with the construction phase spanning 2021-2024; it will take approximately 42 months to complete the capture plants, with storage and transport infrastructure planned to take 36 months. Injection into the saline aquifer is planned to begin in 2024. The final investment decision (FID) report (KS-2) was published on 24th June 2020, which focussed mostly on costs and uncertainties, as well as planned project governance.
Tim Dixon, General Manager of IEAGHG, gave an update on CCS and CCUS efforts worldwide and an update on the global COVID-19 situation and how this has affected our industry. There has been a drop in CO2 emissions as a result of the pandemic, which were 5% lower in Q1 of 2020 cf Q1 in 2019. The IEA forecast 8% lower for 2020 which is the largest ever reduction of emissions. Countries are putting into place recovery packages and many areas are including CCUS in these packages, for example the EU, showing that CCUS will be an important tool in helping both the economy as well as global greenhouse gas mitigation.
Corwyn Bruce (The International CCS Knowledge Centre) gave an update on CCS progress in Canada and began by noting that all coal fired power plants in Canada will require CCS by 2030. One project significantly progressing the technology is Boundary Dam 3 (BD3). Current CCUS efforts in Canada include BD3, Shell's Quest project and the Alberta Carbon Trunk Line. There is also EOR at the Weyburn project, direct air capture in British Columbia and cement feasibility studies in Alberta, along with increased interest in the oil and gas industry with many other smaller projects ongoing. The Weyburn-Midale CO2-EOR project is of note; this is the largest CCUS project in the world where injection commenced in October 2000. There is an estimated storage potential of 55 million tonnes in the Weyburn unit, and over 30 Mt of CO2 has been injected so far.
Overall, two aspects of the great work from the USA presented at this DOE NETL meeting were most striking this time. It was clear that the CarbonSAFE Phase 3 projects (and the new FEED studies) have succeeded in bringing in a whole range of new actors and industry stakeholders to actively consider CCUS. Also, it was great to hear references to the learnings from Petra Nova and Boundary Dam projects being used in the FEED projects. Presentations will be available at https://netl.doe.gov/2020CCUS-proceedings.
Other NETL review meetings: The NETL Carbon Storage review meeting will be held virtually on 8-11 September, Carbon Capture will be held 5-7 October and Carbon Utilization will be held 21-22 October. See https://netl.doe.gov/events for details.
James Craig, Monica Garcia, Sam Neades, and Tim Dixon