5 Summary findings

The primary conclusions that can be drawn from the considerations made in this study are the following:

  • Conventional NGCC and USCPC-based power plants without CCS show respectively a high and medium operating flexibility, generally allowing thermal cycling operation, rapid load changes and start-ups, as well as good efficiency at partial load. On the other hand, IGCC’s show lower dispatch flexibility, due to the inertia of the process units to generate and prepare the fuel at the conditions required by the gas turbine.
  • For the reference plants with leading CCS technologies, there are additional constraints that may limit the flexible operation. However, depending on the specific characteristics of the power plant and their weekly demand curve, there are possible ways of overcoming these limitations, as reported in the following:
    • Thermal cycling of power plants with CCS: for NGCC and USCPC plants with frequent start-ups/shut-downs, to maintain the same thermal cycling capability as the conventional plants without capture, solvent storage shall be made, leading to an investment cost increase of about 8% and 2% of the reference case, respectively for NGCC and USCPC. For IGCC and Oxy-combustion USC PC plant types, there are no specific constraints to follow a weekly demand curve consisting of 100% load during the daytime and 50% load at evenings and weekends (‘two regimes operating curve’).
    • CO2 capture solvent storage: for NGCC and USC-PC power plants, solvent storage allows to decouple the operation of the absorption section from the regeneration and compression units, while continuously capturing the CO2 from the flue gases. This feature improves load following capabilities and overall economics of capture plants, because the electricity production is maximized when the market requires a higher electricity generation. Considering a ‘two regimes operating curve’ as described above, it has been estimated that the net electrical efficiency increases by about 5% to 6% with respect to the reference case, while the investment cost delta is about 20% and 7% higher, respectively for the NGCC and the USCPC plant. On the other hand, considering a ‘three regimes demand curve’ that includes also two hours per working day of peak demand, an electrical efficiency increase of about 12% (NGCC) and 22% (USCPC) is achieved by halting the regeneration during these two hours, while for the rest of the daytime the plant is operated as in the reference conditions; this leads to an investment cost delta of about 9% and 6%, respectively for the NGCC and the USCPC plant.
    • Constant CO2 flowrate in transport pipeline: cycling operation leads to an uneven captured CO2 flowrate and a consequent fluctuation of the operating conditions in the pipeline. To avoid this problem in a ‘two regimes operating curve’, CO2 buffer storage can be considered in the plant, leading to unchanged performance and cost increase from 2% to 3% of the reference case. However, depending on the overall length, this investment increase may be offset by the lower cost of the pipeline. For the NGCC and the USCPC alternatives, solvent storage can be also considered, leading to an electricity production increase from 3% to 5%, during peak hours, with respect to the reference case. On the other hand, the plant total investment cost is respectively 12% and 4% higher than the CO2 buffer storage option.
    • Hydrogen storage in IGGC plants with CCS: considering a ‘two regimes operating curve’, power production during peak demand period and investment cost are about 3% higher than the reference case, while also producing 75,400 Nm3/h of high purity hydrogen. Alternatively, without hydrogen production it is possible to produce the same amount of power, while reducing the investment cost by about 6%, due to the reduced size of the main process units. In both cases, from literature data it is expected that cost of hydrogen storage may vary from 10 M to 50 M, corresponding to a maximum of 3% of the overall plant cost. Hydrogen storage also allows operating the combined cycle at partial load or in island mode during low electricity demand period, while the syngas generation line is operated at full load; in this case the combined cycle of the IGCC can be operated as a conventional NGCC plant, following a weekly demand curve consisting of 100% load during the daytime and island mode operation at evenings and weekends.
    • Oxygen storage in IGGC and oxy-USCPC power plants with CCS: considering a ‘two regimes operating curve’, with adequate oxygen (and nitrogen) storage and running the ASU at partial load the electricity production during peak demand is about 5% and 8% higher than the reference case, respectively for Oxy-combustion and IGCC plant. The additional investment cost ranges from 2% to 3%. Alternatively, if lowersized ASU (about 80% of the reference case) is considered, the electricity production is 3% and 4% higher than the reference case, while the total investment cost is almost unchanged. On the other hand, considering a ‘three regimes demand curve’, an electrical efficiency increase of about 6% and 10% is achieved running the ASU at part load for two hours per working day of peak load operation, respectively for Oxy-combustion and IGCC plant. The investment cost is about 1.5% higher than the IGCC reference case, while it is almost the same for the oxy-combustion USCPC.
    • Operation without carbon capture and storage: provided that design is adequately made, power plants with CO2 pre or post- combustion capture can also be maintained in continuous operation without capturing the carbon dioxide. Depending on possible low CO2 emission allowances costs, this operating flexibility may improve the economics of the plants because of the resulting higher power production. With respect to the reference case, the investment cost increase is marginal for the IGCCs, while it is about 4% and 6% respectively for the USC-PC and the NGCC power plants.
  • Several promising energy storage technologies, characterized by different power and storage capacities and reaction times, are becoming a realistic option in response to the challenges of the liberalized market. These are: pumped hydropower, compressed air energy storage, battery energy devices, flywheels, superconducting magnetic energy storage (SMES), electrochemical capacitors.

In summary, it can be stated that power plants with leading CCS technologies will be able to respond to the requirements of the new liberalized electricity market. For IGCC and oxy-USPC plants, the oxygen storage is of primary importance, while for post-combustion capture plants the key factor is solvent storage, whose technical feasibility has been already confirmed by the main licensors of the technology. Furthermore, for IGCC plants the option of hydrogen storage may lead to additional advantages.

In broader and more general terms, it can be concluded that performances of flexible CCS plants during peak hours are often better than those of base load plants and in most cases the investment cost increase is not excessive. Therefore, flexible plants with leading CCS technologies have the potential for opening new business opportunities and improving the overall economics of the project.