*The following questions arose during a Webinar - BD3 CCS Facility: Technical Capabilities, in collaboration with the Climate Technology Centre & Network (CTCN), on the necessity of large scale CCS to meaningfully reduce global CO2 emissions, specifically about the Shand Study.
What drove the majority of the cost savings between Boundary Dam 3 (BD3) CCS Facility and the Shand CCS Feasibility Study (Shand Study)?
This comparison chart represents the cost savings that can occur by progressing from BD3 CCS Facility to the second generation of carbon capture and storage (CCS) and illustrates the specific areas where significant improvement can occur.
The Shand CCS Feasibility Study shows that there is:
a 92 per cent reduction to power plant capital costs (as highlighted in the chart, stemming from the case by case differences, in this case the turbine was able to be modified with “bolt-in” changes which saved significant capital costs, with a small penalty in efficiency); and,
capital cost reductions of 67 per cent per tonne of carbon dioxide (CO2) captured.
How much of the 67% cost reduction in the Shand CCS Feasibility Study is reproducible at another plant?
A good portion of the cost reductions would be reproducible since the factors of scale and construction efficiency are universal. Additionally, a portion of the costs for BD3 related to contingency plans that were required to reduce the unknown operating risk associated with the first in the world plant, to ensure that the power plant would continue to be a secure, reliable source of energy. Experience has shown which risks materialized and which didn’t as well as revealing alternative methods of achieving the same end result.
As well, location played a large part in driving capital expenditure for BD3 CCS Facility. Due to pre-existing conditions and infrastructure at Boundary Dam Power Facility, the capture plant had to located a fair distance from the power plant. This distance between the power facility and the capture facility resulted in significant capital expenditures for interconnections. The greater physical distance between the CCS facility and its host makes integration of the operation more complex and less effective. In contrast to the Boundary Dam site, the Shand site, with its single unit is immediately next to the power plant and has the space to accommodate a CCS facility at a lower capital cost. If physical distance between the CCS facility and the host can be contained, then the cost savings shown here are reproducible.
What drove a large portion of the costs to prep Unit 3 of the Boundary Dam coal-fired power plant for CCS facility integration ?
A large portion of the costs that came into the power island portion for the BD3 update were related to contingency plans. BD3 was the first fully integrated power plant in the world connected to a CCS plant. SaskPower, the owner of the plant needed to make sure that the power plant would continue to be a reliable power generator regardless of any issues connected with the CCS facility. This resulted in many one-time costs associated with what was perceived to be extra risks. Now that the plant has operated for four years, and there is regulatory clarity on the requirements for CCS, some of the contingencies built into that system are no longer necessary or required.
How appropriate is it to compare the operating BD3 CCS Facility to a proposed Shand CCS Facility and how would other facilities compare?
Comparing BD3 and Shand is appropriate as they are both located in the same environment. It is important to note that while the proposed Shand CCS Facility may be virtually reproducible for other coal units in Saskatchewan and elsewhere, simply duplicating a CCS facility is not an appropriate way to apply the technology. At the inception of determining where to develop a CCS facility, it is important to first examine the options on a case-by-case basis and consider; age, size and layout, and location to maximize opportunities for the full chain of capture, utilization and storage. Comparisons to other facilities that have different construction and physical environments would not necessarily yield comparable results.
How much of the 67% cost reduction is due to the nature of the Shand Plant?
Inside the capture facility it’s difficult to identify the individual factors that drove cost reductions as price was determined based on all of the changes made.The one item that is possible to highlight is the integration of the regeneration energy source between the capture plant and the power plant. The Steam cycle of the plant was modified with “bolt-in” changes only to the turbine, the feed heating plant was to be maintained with minimal modifications, and the system was to be optimized for the full capture case only.This resulted in slightly lower efficiency, but yielded significant capital cost savings. The overall impact of all of the factors resulted in a 67% capital cost reduction on a per-tonne of CO2 basis.
Load following at Shand is an interesting development.What percentage of turndown is expected to still achieve a high level of CO2 capture?
When the requirements were established for the feasibility study, the target for the flue gas turndown was set to be 75 per cent, as this aligns with the recent historical load dispatch of the unit. As shown in the Shand CCS Feasibility Study, the carbon capture percentage can be increased as it comes down in load, which increases the proportion of steam that must be extracted in order to regenerate the solvent.
This results in a unit operating range with net power output varying between 100 per cent and 62 per cent. Over this load range the capture rate would vary between 90 per cent and 97 per cent respectively, by taking advantage of the capacity of the capture facility in turn down conditions.
In the late 2000's CCS ready facilities were mandated. Would mandating lead to lower costs to retrofit?
There is likely some provision that will save costs due to CCS readiness but this has yet to be clearly defined. ‘CCS Ready’ could cover a broad range of descriptions including:
Proximal footprint space availability on the ground to place the CCS plant,
Flue gas path designed to have the ability to extract and reinsert the flue gas once there was C02 removal, and;
The steam turbine designed to be able to serve the regeneration needs of the solvent.
Additional plant utilities built into the original design, potentially including water treatment, waste handling, power supplies, maintenance supports, instrument air etc.
Clearly, the more interfaces that are pre-planned to be ‘Capture Ready,’ the lower the retrofit costs will be. There is no known international standard for capture readiness.
Costs of a proposed CCS facility at Shand are quoted as being 67 per cent less per tonne of CO2 captured. Approximately how much of the total costs would the CCS facility be at Shand (the CCS Facility at BD3 was approximately $900M of $1.5B with a capture capacity of 1Mtpa)?
The full costs included in the Shand CCS Feasibility Report to retrofit Shand with CCS is just under $1B CDN, of which the CCS Facility would be $670M, with a capture capacity of 2Mtpa . For a breakdown of the direct costs and the owner’s costs and what each line item is based on, see chapter 8 of the Shand CCS Feasibility Study.
Does the $45/tonne of captured CO2 include the cost of transportation? (IEA studies consider $10-20/tons for transportation costs)
The cost metric only included to the outlet flange of the plant, therefore $45 per tonne of CO2 does not include any pipeline infrastructure beyond the plant wall as this is beyond the scope of the study. Ultimately the cost of transportation is driven by the location of the plant.
Was the possibility of Oxy Combustion considered for Shand (eliminate NOx)?
When SaskPower was first looking at the possibilities of a CCS project in 2006, the corporation considered a brand-new build of a 2nd power unit at the Shand facility, an oxy-fired lignite-boiler using the same fuel source. That plan progressed until 2007 when the costs no longer made economic sense. SaskPower then looked at Boundary Dam 3 as a retrofit to seek a more cost competitive option.
It was mentioned that reducing the consumption of coal increases the cost. Shutting down BD4 & BD5 will result in less coal consumption. Was the shutdown factored into the fuel costs for Shand?
It is important to maintain the scale of a coal mining operation because not maintaining this scale will increase costs on a per unit basis. There are variables based on the fuel source, the coal stripping ratio, labour costs, how much of the resource is left, etc. that are specific to each mine. In general, reducing the amount of coal supplied from a mine will increase the cost on a per ton of delivered fuel. Specific costs for SaskPower cannot be provided.
What impact would shutting Shand down do to SaskPower's BD3 & BD6?
The Knowledge Centre is not in a position to provide commentary on specific operations of SaskPower. Please contact SaskPower directly for responses to this question.
Does this study show a positive return for SaskPower?
There is a public version of this report and a confidential portion that is being conducted specifically for SaskPower and MHI that is not available for comment. In the public report it has been made known that large reductions in capital costs are achievable.
Why continue with the degradable amine solution for CO2 capture where second membrane shows advantages even for a coal power station?
Membranes are a promising technology yet are still in early development. This study was based on deployable large-scale CCS as a commercial endeavour. Right now, there aren’t any membranes ready to be deployed on a 300 megawatt coal-fired power plant. Membranes are a potential technology for the future, the Shand CCS Feasibility Study is based on ready to go technology, hence the choice was post-combustion amine capture.
The SO2 removal and CO2 capture processes are integrated in the Cansolv process at BD3. For the CCS Facility at Shand, it is proposed to have separate SO2 removal and CO2 capture. In future plants, would separate SO2 removal and CO2 capture processes usually be preferred?
The BD3 CO2 capture process is indeed integrated with the SO2 removal process - in an amine-based process that results in the generation of sulfuric acid which can be sold as a valuable by-product. For Shand, the SO2 system is separate and is based on a wet limestone flue-gas desulfurization (FGD).
In many locations in the world, existing facilities would already be equipped with an SO2 abatement system. As a result, separate processes are likely as the decision and the capital expenditure associated with it would have been already taken place prior to considering CCS.
For the Shand CCS Feasibility Study, MHI was specifically chosen for both their experience in wet limestone FGDs; as well as a way for the Knowledge Centre to expand our knowledge base by previewing and learning about the separate SO2 removal and CO2 capture processes.
The KAPSARC Report (produced by the King Abdullah Petroleum Studies and Research Center, located in Riyadh, Saudi Arabia), titled "Enhanced Oil Recovery and CO2 Storage Potential Outside North America: An Economic Assessment," reports a net CO2 use of 0.3 tonnes per barrel of additional oil. It also reports that factor increasing to 0.6 t/bbl when the EOR becomes storage-focussed. How do these figure compare with the EOR situation in Saskatchewan?
These numbers seem reasonable. The Petroleum Technology Research Centre (PTRC), confirms that: “For each tonne of CO2, Cenovus (the operator of the Weyburn field up until 2018) estimated in 2012 that they were receiving an additional 2.8 to 3 barrels of oil (so .33 tonnes per barrel). Now that the production curve is starting to decline at Weyburn (down to 25000 tonnes per day, from 30K) that figure may be closer to about .45 tonnes per barrel.”
Is there information about the cost of electricity showing the cost of Natural Gas Combined Cycle (NGCC) at full load, then at a decreasing load as renewables contribute? It would be interesting to know the average cost for electricity based on the two systems.
The cost of electricity is generally calculated based on full output with a known capacity factor. Calculating the cost of electricity at reduced output is difficult, as the cost of capital and a portion of the operating costs are fixed and independent of dispatch, while fuel and some consumables, as well as a portion of the maintenance costs, would be variable based on the load of the facility.
The calculation of the net heat rate of the NGCC and the CCS equipped coal plant was fundamental to our generation of these curves in the Shand CCS Feasibility Study. This allowed for the determination of the amount of fuel required. One can imagine that due to the increasing amount of CO2 capture for the CCS equipped coal plant at lower loads, the heat rate of the coal CCS plant deteriorates more at reduced loads than the NGCC plant.
Petra Nova has their own power and utility for their carbon capture unit - for Shand this would not required as there is only one turbine, but is this being considered for BD6 or other facilities with multiple turbines? Wouldn’t this enable the capture facility to continue to operate when the turbine is out of service for maintenance.
Each case of course needs to be taken on its own merit. The understanding is that the Petra Nova capture facility uses a new purpose-built natural gas turbine unit combined with a heat recovery steam generator to provide the energy required for the amine regeneration. There are many factors that go into a business case. However, this scheme is not without its challenges as it results in having to operate an additional energy system that is potentially as large as the associated coal plant, requiring two different fuel sources to run the facility.
For the Shand CCS Feasibility Study, it was identified that the best case for CCS would be realized with an integrated steam source from the coal fired unit. The lack of reasonably available natural gas pipeline sources was an influencing factor. As was the main benefits of coal and its stable price, large amount of on-site storage, and isolation from natural gas supply disruptions.
Could fellow members of the Clean Technology Centre Network (CTCN) go through the new ISO 27919-1 CO2 capture performance evaluation standard established on BD3 and/or Shand ? ISO TC265 CCS, WG1 Capture would be helpful.
Both of SaskPower’s BD3 and Shand systems are proprietary. The performance of these systems is generally governed by confidentiality provisions of the technology license or by non-disclosure agreements as part of engineering evaluation studies, and are not able to be shared.
What is the next step for the Shand project beyond the feasibility study?
The Shand CCS Feasibility Study project includes a confidential report for the project contributors, SaskPower and MHI, which is being completed.
Chapter 11 of the feasibility study includes a timeline and considerations for a further Front End Engineering Design (FEED) study that could progress to a Final Investment Decision (FID) in a proposed timeline of 18 months. Further actions in terms of progressing the project are at the discretion of SaskPower.
What are the Timelines to Develop a CCS project?
CCS facilities require several technical milestones to ensure appropriate deployment. Each of the steps is based on levels of risk and varying levels of acceptance and approval internal to individual organizations.
The best time to engage our hands-on experience-based expertise is first thing, in advance of feasibility studies. There have been instances where companies have embarked down the CCS path on their own, only to discover late in the game that they were not as well equipped to see it through as they had expected.
Our technical team has decades of CCS experience that cannot be replicated easily or in a short period of time. To date, many CCS projects that have been studied end up not proceeding, most often due to a lack of economics. We can help you avoid this scenario to increase the likelihood of a successful CCS facility.