Appendix 2 CO2 Capture Technology Selection and its Role in Moving CCS Forward

CO2 Capture Technology Selection and its role in moving CCS forward

Introduction

The successful validation of Carbon Capture and Storage (CCS) in Australia requires a strategy for 'proving-up' geologic storage resources. A key component of such a strategy will be the ability to source a timely and reliable supply of CO2 of the necessary quantity and quality.

The exact amount of CO2 required to prove-up CO2 storage in Queensland's most prospective location, the Surat Basin, is yet to be established. However the Global CCS Institute has defined a large-scale CCS project as one which captures and stores at least 850,000 tonnes of CO2 per year.

For a large-scale CCS project the choice of CO2 capture technology is of prime importance and proper consideration of steady state and dynamic operational and chemical capture compatibility with CO2 transport and storage will be critical to success. The only CO2 capture technology available at this time that meets all of these criteria is Integrated Gasification Combined Cycle (IGCC) with pre-combustion CO2 capture.

Relying on the capture technology alternatives of post-combustion capture (PCC) or oxy-fuel combustion to provide the necessary source of CO2 will significantly increase the level of risk to achieving a successful large-scale validation of CCS in Australia. This paper discusses some key questions regarding the status of these capture technologies.

What PCC projects are currently operating, or are at the detailed planning/implementation phase?

Using post-combustion CO2 capture (PCC) as a source of CO2 is a technically feasible concept however PCC is not in use at large-enough scale in any coal fired plant today. The largest post-combustion capture projects that are currently in test are limited to 25 MWe in size as contrasted with the approximate 150 MWe size as would be necessary to supply of the order of one million tonnes per year of CO2 for sequestration. Even the earliest of the planned large scale demonstrations (Table 1) will not begin operation in a time frame that can provide data and experience to reduce the risk of a PCC alternative to an equivalent level provided by the Wandoan Power Project.

Table 1 – Post Combustion Capture demonstration

What technology and scale-up issues/risks exist for deployment of PCC/oxy-fuel combustion as part of a large 'industrial' scale plant?

A major technology risk associated with PCC and oxy-fuel combustion at the scale required is the inability to achieve the necessary quality and reliability of CO2 produced. In contrast it is noted that predetermined and consistent CO2 quality is routinely achieved in industrial, chemical and refining applications of pre-combustion capture.

The quality of CO2 required for CCS will need to consider the following:

  • The potential for certain contaminants to cause environmental, health and/or safety problems as might be incurred from pipeline failure or leakage, plant release or venting operations.
  • The interaction of contaminants in the CO2 with one another.
  • The interaction of contaminants in the CO2 with the geological formation and the fluids in the formation. For example the impact various contaminants in the CO2 have upon the injectivity and fluid flow in a geological formation.
  • Pipeline transport requirements
  • The potential for various contaminants to cause corrosion and fouling.

If the required CO2 quality is not consistently met, the result could be very costly in terms of pipeline damage, plugging of injection wells and loss of reservoir capacity.

High reliability of CO2 supply is also important to proving capacity, injectivity and the veracity of models of the geologic fate and transport of injected CO2. High CO2 availability with pre-combustion carbon capture is already being achieved at the commercial Coffeyville and Eastman plants that operate at greater than 90% availability.

For PCC and oxy-fuel combustion scaling from small pilots to industrial scale and operation will result in unknown and unproven reliability and quality issues and risks. Scale-up challenges specific to amines required for most PCC processes will be due to:

  • Necessary '10 to 1' scale-up to provide the required quantity of CO2 exceeds the typical "3 to 1" comfort level.
  • Beyond the range of computational fluid dynamics (CFD) model validation techniques (e.g. skinny-to-fat scrubbers).
  • Mass transfer and contactor effectiveness.
  • Build-up and precipitation of contaminants over extended operation and potentially hazardous waste.
  • Long-term increase in boiler and air pre-heater in-leakage causing solvent degradation.
  • Corrosion mechanisms and materials of construction.
  • Design features to deal with upset conditions (water wall leaks, air pre-heater failure, etc.) causing contamination and loss of solvent inventory.
  • Heat and mass integration complexity and controls development.
  • Provisions for start-up/shutdown, load following and time to stable operations.
  • Contraction of fuel envelope.
  • Control of particulate and vapour emissions.

How well established are the cost and performance characteristics of PCC/oxy-fuel combustion for retrofit deployment at industrial scale e.g. >100 MW?

Retrofitting a large industrial scale PCC plant or oxy-fuel combustion to an existing coal-fired power plant is a project of similar scale and more complexity than building a new plant.

Extensive project development studies including pre-feasibility study (PFS), definitive feasibility study (DFS) and front end engineering design (FEED) to properly define cost and schedule will be necessary before seeking project financial close.

Retrofit cost, performance and impact will be specific to each site, plant and its characteristics, and the capture technology selected. For example:

  • Site layout and available space
  • Base plant boiler type and heat rate
  • Coal type(s) and envelope
  • Load profile (turndown, cycling, etc.) and operability
  • Plant control system capability
  • Boiler in-leakage and need for refurbishment
  • CO2 end-use and required quantity, quality and availability
  • Induced Draft/Forced Draft fan capacity
  • Steam supply integration: turbine configuration, extraction location and impact on steam turbine performance
  • Can steam turbine operate at reduced load?
  • Water supply and water balance
  • Replacement power and CO2 characteristics
  • Existing emissions performance and upgrade requirements (SOx, NOx, PM)
  • Local permitting requirements (venting, flue gas reheat, etc.)

Costs for retrofitting PCC will be highly dependent on the site, plant and layout. Labor productivity for a 'brownfield' installation will be significantly lower compared with that on 'greenfield' installations. As an example, EPRI1 and DOE2 have estimated capital expenditure (CAPEX) ($/KW) for retrofitting PCC at favorable sites to be comparable to the cost of building a new plant without CCS. It should also be recognised that estimates of levellised cost of electricity for a PCC retrofit that will be operational only during the term of a testing campaign would be extremely high and heavily weighted by capital recovery.

How long is it likely to take to engineer, procure and construct a project based upon PCC/oxy-fuel combustion for retrofit deployment at industrial scale e.g. >100 MW?

For a retrofit project that is going to produce in the order of one million tonnes CO2 per annum, the development, construction and commissioning timeframe will be similar to that of a new build project.

Extensive project development studies including pre-feasibility, feasibility and engineering design phases will be necessary to properly define cost and schedule prior to seeking project financial close.

It is estimated that it would take at least five years from commencement of project development to completion of construction.

What are the major limitations of a project based upon PCC/oxy-fuel combustion for retrofit deployment at industrial scale e.g. >100 MW?

While slipstream demonstrations provide valuable data on stand-alone capture process capability, they do not provide validation of cost and performance data of CCS on new, purpose built plants that incorporate CO2 capture for their entire fuel or flue gas.

As compared to retrofit PCC or oxy-fuel combustion, a new build fully integrated plant is required for the successful validation of CCS in Australia. Such a plant will prove the effectiveness of design, materials' choices and control strategies that guarantee operational flexibility while maintaining process flow balances between major power and process components, control of dynamic and chemical interactions and the longer term impact of build-up of secondary and tertiary compounds within solvent regeneration and recycle loops. Successful large-scale and commercially relevant demonstrations are critical to prove that geologic sequestration of CO2 is a safe and environmentally acceptable solution for low carbon coal power.

Summary

PCC and oxy-fuel combustion technology experience for coal-fired plants is currently limited to pilot and proposed sub-commercial demonstrations. No demonstrations have been completed at industrial scale nor in a fully integrated plant configuration.

A substantial investment program will be required to progressively scale up various PCC and oxy-fuel technologies and de-risk them so that they can be evaluated for suitability for commercial deployment. It is likely that a number of projects will need to be undertaken at different scales including a mix of slipstream retrofit and integrated full capture new build projects.

Relying at this time on capture technology of this limited maturity will significantly increase the risks to a successful validation of CCS in Australia.

1 An Engineering and Economic Assessment of Post-Combustion CO2 Capture for 1100°F Ultra-Supercritical Pulverized Coal Power Plant Applications: Phase II Task 3 Final Report. EPRI, Palo Alto, CA: 2010. 1017515

2 Ciferno, J. P. Carbon Dioxide Capture from Existing Coal-Fired Power Plants. U.S. Department of Energy; National Energy Technology Laboratory: Pittsburgh, PA, December, 2006; DOE/NETL - 401/120106