Technical Market Support » Future Technologies
Numerous options are available for control of CO2 emissions including fuel changing, energy conservation, renewable energy technologies and CO2 sequestering. This study was carried out to provide data on the option of CO2 removal and sequestering in an Australian context.
The technological options for the recovery and disposal/utilisation of CO2 from coal-fired power stations have been extensively evaluated by the IEA Greenhouse Gas R&D Program, of which Australia is a member. This project has sought to translate these overseas studies to Australian black coal- fired power plants. A technical and economic evaluation has been conducted into options for recovering and sequestering CO2 emissions from black coal-fired power stations based on technology as applied in Australia at present. The results from this study have been compared with the impact of introducing Integrated Gasification Combined Cycle (IGCC) technology.
Two black coal-fired power plants, operating at coastal and inland locations, were selected as the basis for the technical and economic analyses. Each power station was considered to be equipped with 525 MWe installed capacity units, giving a net output of 500MWe. A preliminary technology assessment indicated that the best option for recovering CO2 would be the retrofitting of a commercially available amine-based absorption process. In this study the extent of CO2 removal from the flue gases was varied from 30% to 90%. Since the amine-based CO2 removal process is very sensitive to SOX and NOX present in flue gas, the study also assessed the impact of reducing their concentrations by as much as 98.5% using commercially available retrofittable de-SOX and de-NOX technologies. The CO2 recovered from the coastal station was ultimately disposed of in the ocean at a depth of 500 metres, 100 km offshore. For the inland station, the CO2 recovered was disposed of in a disused gas field at a depth of 2500 metres.
To understand the impact of introducing IGCC technologies, the above coal-fired plants were replaced by equivalent dry coal feed (Shell type) IGCC power plants, using the same feed coals. CO2 removal processes were then fitted to the IGCC plants and their overall performance compared with those of pulverised fuel-fired plants at 90% CO2 recovery rate. The CO2, recovered from both coastal and inland IGCC plants, was ultimately disposed of in the same manner as for the pulverised fuel-fired power stations.
In performing a parametric sensitivity analysis within this study, twenty-six configurations of power plant were assessed. The cost and efficiency penalties associated with CO2 removal and disposal were calculated and compared for both pulverised fuel-fired and IGCC power plants. The increases in the generating cost of electricity (cents/kWh) that would inevitably occur due to such CO2 mitigation measures were calculated for each case.
Overall the study has shown that retrofitting existing Australian black coal-fired power plants with CO2 removal systems is technically feasible, with the Econamine FG type amine process being the best option currently available.
The table below shows results from the five key case studies where 90% of the CO2 in the flue gases was recovered, compressed and sent to disposal. Plant PF(A) refers to a pulverised fuel-fired plant at a coastal location where the recovered CO2 is sequestered via deep ocean disposal, while PF(B) refers to a similar plant at an inland location where the recovered CO2 is sequestered in a disused gas field.
|Case ||Plant ||SOx |
|Capital Cost |
|Net Power |
|Additional Cost of |
CO2 Recovery &
| || || || ||CO2 Recovery ||CO2 Disposal || || ||$/tonne CO2 Disposed ||Cents/kWh Exported |
|1 ||PF(A) ||No ||Ocean ||350 ||187 ||333 ||23.3 ||57 ||6.7 |
|5 ||PF(B) ||No ||Gas Field ||353 ||170 ||323 ||22.3 ||62 ||7.9 |
|14 ||PF(A) ||60% ||Ocean ||391 ||187 ||332 ||23.3 ||52 ||6.1 |
|17 ||PF(B) ||60% ||Gas Field ||393 ||170 ||322 ||22.2 ||56 ||7.1 |
|19 ||IGCC ||Note 1 ||Ocean ||389 ||138 ||304 ||25.5 ||52 ||5.8 |
Note (1) The IGCC system removes sulphur from the fuel gas as H2S and COS compounds through the Selexol process prior to combustion in turbines
Of the two CO2 disposal options considered in this study, the disposal in a disused gas field would probably present less technical uncertainties at present and greater certainty of sequestering CO2 on a long term basis.