8 Conclusions

The purpose of this study was to address the following main critical aspects for the development of PCC-projects as retrofits to existing plants:

  • The model will provide an independent validation of impacts on plant performance and inputs for retrofit PCC projects. It documents a methodology for power station owners to evaluate the risks and revenue impacts for their plant operation.
  • The independent validation of the plant performance can contribute to a reduction of the currently required risk premiums to finance the execution of a large scale PCC-projects as it identifies a methodology to independently validate the performance of first-of-a-kind retrofits to a coal power plant.

The methodology adopted in this study achieves the project goal of independently validating the impact on an existing power plant’s performance of the retrofit of a PCC-plant into that power plant. The results from this study are in line with expectations of both the technology vendor and the power station owner.

Regarding the accuracy of a carbon capture technology developer’s (IP) claim about their solvent regeneration energy, it is not possible to verify this unless both the physical and chemical properties of the solvent are known. Solvent physical properties are required to accurately simulate performance of a chemical absorption system whilst the chemical properties determine the energy required for regeneration. This information for public disclosure is only available for MEA (mono ethanol amine) without additives. It is therefore important to minimize the technology vendor’s “black box” as much as possible from the remaining plant to allow a high level of transparency between specific technology (solvent) driven performance relative to intelligent process integration of heat and mass flows on overall plant performance whilst ensuring the confidentiality of the technology vendor’s intellectual property. This allows the successful benchmarking of individual process components against theoretical achievable limits from a chemical and thermodynamic point of view.

The selection of suitable software tools is critical to achieving the project goals, since there is no software package currently available that is able to integrate all required technology components. As a consequence off-line integration forms a large and important part of the process to integrate the individual technology elements that is required to evaluate an overall plant performance impact. The tools chosen are flexible enough to not only be used for the defined cases for a PCC retrofit plant evaluated in this study but can also be applied to green field sites and other fossil fuelled technologies.

The selected cases evaluated in this study are targeted to identify and compare sensitivities of energy penalties of different technical solutions with a specific and pre-selected PCC-technology, and several approaches to reduce the energy penalty associated with the PCC retrofit have been assessed in the course of this work. The thermodynamic modelling methodology employed in the study enabled exploration of technical merits of each approach, which are as follows:

  1. Case 1 design that does not include either heat integration with CO2 compression, or low temperature heat utilization for coal drying. As a result, Case 1 performance, as compared to other retrofit cases, is estimated to have the lowest net efficiency of 24.68% and the highest CO 2 emissions intensity of 0.917 kg CO2 per kWh net. The energy penalty EOP for Case 1 is the highest amongst the cases considered.
  2. In Case 2, low temperature flue gas heat is utilized for coal drying, which results in an approximately 1.3% improvement in the net unit efficiency (as compared to Case 1) to 25.97%. CO2 emissions intensity in Case 2 is about 8% lower as compared to Case 1. However, reduction in unit net output in Case 2 is 0.6 MWe higher as compared to Case 1 (Case 1 EOP of 419.89 kWh/t CO2 vs. 274.7 kWh/t CO2 in Case 2). In Case 2, as a result of firing coal with lower moisture content, heat flux in the boiler furnace is estimated to increase with corresponding reduction of the heat transfer in the boiler back pass. This reduces water flow rate to the superheat and reheat de-superheaters, increases the feed water flow into the boiler and results in a corresponding increase in the steam extraction from the HP and Intermediate Pressure sections of the steam turbine. As a consequence of the above, the steam gross generation by the steam turbine decreases, but the steam cycle efficiency increases due to reduction of the steam condenser duty.
  3. In the Case 3 design, coal drying is supplemented by steam cycle heat recovery from the CO2 compression system. In addition, a steam expander is employed to reduce steam pressure for the PCC plant. These measures resulted in the highest unit net efficiency of 26.36% (1.68% higher than in Case 1), and the lowest efficiency penalty of 2.46% as compared to the Base Case plant. Accordingly, the CO2 emissions intensity of 0.836 kg CO2 / kWh net is the lowest amongst all the study cases. The reduction in unit net output of about 69 MW is almost 6 MW lower as compared to Case 1 (Case 1 EOP of 419.89 kWh/t CO2 vs. 233.6 kWh/t CO2 in Case 3).
  4. In the Case 4 design, low temperature flue gas heat is utilized to generate low pressure steam for the PCC plant to supplement steam extraction from the steam turbine. The flue gas LP steam generator in Case 4 is configured to extract almost the same amount of heat energy from the boiler flue gas as the flue gas coolers in Cases 2 and 3. The flue gas LP steam generator produces 28 kg/s of low pressure steam, which represents about 42% of total PCC plant steam demand in Case 4. The notable benefit of this approach is the lowest among all the cases reduction in net unit net power output of 53.1 MW, 21.8 MW lower as compared to Case 1 (Case 1 EOP of 419.89 kWh/ t CO2 vs. 284.36 kWh/t CO2 in Case 4). Unit net efficiency of 25.88% in Case 4, while 1.2% higher than in Case 1, is somewhat lower as compared to Case 3 that employs coal drying with plant optimisation.
  5. Case 5 performance is similar to Case 3. No PCC plant performance deterioration is expected at the specified ambient temperature, when air cooled heat exchangers are utilized instead of cooling towers. However, there is a likelihood of poorer PCC plant performance at higher ambient temperatures, and additional analysis for the site’s maximum ambient temperature is recommended. It is noted that the performance is very similar between Case 3 & 5 due to the low dry bulb temperature of 13.4°C at which all design cases are evaluated. An obvious advantage for case 5 is that there will be a much reduced cooling water requirement.

Cases 3 and 5 (with coal drying, PCC and optimisation) show the electricity output penalty for carbon capture is the lowest of all the cases. However, these have the second highest net power plant output of all the cases.

Case 4 (with PCC and optimisation without coal drying) has the highest net power plant output. It has a higher electricity output penalty than Case 3 and 5.

Cases 3 and 5 have a net plant efficiency of almost 0.5 percentage points higher than Case 4.

Cases 3 and 5 also have the lowest CO2 emissions intensity.

These findings suggest that an additional cost benefit analysis needs to be undertaken to establish, which design approach is most beneficial and/or of net advantage in reducing the overall cost of CO2 capture in subcritical coal-fired power plants firing high moisture coals.