3 Pre-combustion capture

Pre-combustion capture process is the typical technology considered for the application in IGCC power plants.

The addition of the CO2 capture in IGCC plants affects its design only marginally. With reference to the syngas treatment and conditioning line, a complete new section is required to make the CO shift reaction and increase the CO2 and hydrogen content of the fuel, which is sent to the AGR after cooling.

With respect to the traditional AGR configuration for the removal of H2S only, the addition of CO2 capture has the following main impacts on the unit design:

  • Addition of one or multiple CO2 absorber columns, supported by different ancillary equipments like solvent circulation pump, solvent chiller, flashing system etc.
  • Increase of electrical consumption (of about 7-8 times), due to the higher solvent circulation rate for the CO2 absorption and to the required higher refrigeration duty;
  • Reduction of the heat input (about 25-35%) in to the solvent regeneration section;
  • Improvement of performance in terms of H2S removal: H2S present in the feed gas is almost totally removed.

Finally, the CO2 compression section shall be added downstream the AGR unit.

Gasifiers and IGCC have very different operating characteristics with respect to pulverised coal-fired boilers and natural gas combined cycle power plants, as well as very different behaviours versus the variable electricity demand. As in the case without CO2 capture, a large flexible operation of IGCC plants with CCS is not achievable.

3.1 Impact of pre-combustion capture on power plant capabilities

3.1.1 Start-up and cycling capability

As described in section C, the IGCC in its base configuration is not generally suitable for a flexible operation and the plant is typically designed for operation at base load, due to the significant inertia related to the syngas generation sections (Gasification, ASU and syngas treatment).

It is expected that the modifications described in the AGR unit do not impact on the overall plant operation in terms of flexibility. The ramp rates and start-up times of AGR, in fact, are not affected by the equipment added for the CO2 capture, as the new column and the flash separators do not add particular constraints.

As per the AGR unit, also the CO2 compression does not introduce specific constraints on plant flexibility, both during start-up and during normal operation, because the inertia of the gasification, ASU and process units are significantly higher than the CO2 compression.

In order to increase the plant flexibility, some modifications similar to those described for the plant without CO2 capture can be introduced with a significant impact on the overall investment cost of the plant.

For example, storage options could provide opportunities for flexible operation of IGCC plants. Liquid oxygen or nitrogen storage might be useful to decouple ASU from the rest of the plant. Moreover, interim storages of raw or decarbonised syngas (or hydrogen) can allow the gasifier to run at constant load while the combined cycle provides flexibility.

Also, to improve IGCC flexibility and cycling capabilities, the possibility to co-produce different products can be considered. In fact, in the IGCC with CO2 capture syngas is converted mainly into hydrogen by means of shift reaction of CO and water into hydrogen and CO2 and subsequent CO2 removal. These intermediate products, such as hydrogen rich gas or shifted syngas, can be used, instead of being fed to the gas turbine for electricity generation, for the production of chemicals or carbon based fuels. In this case, the overall flexibility of the plant may increase as there is the possibility to switch from one product to another, depending on the market demand fluctuations.

In IGCC with CO2 capture, the possibility to couple the electricity generation plant with chemical plants is higher than plants without CO2 capture, due to the presence of such intermediate products that are suitable for the production of a wide range of chemicals.

It has to be noted that, depending on the intermediate product and its final use, the overall CO2 capture rate can vary significantly.

3.2 Hydrogen co-production and storage

IGCC can be designed to co-produce electricity and hydrogen in order to provide a greater operating flexibility with respect to the conventional IGCC.

IGCC scheme remains practically unchanged up to the AGR section. Syngas at AGR outlet, with a hydrogen molar content of approximately 85% is then split into two streams: one is sent to the gas turbine for electricity generation in a combined cycle, while the other is fed to the hydrogen production unit.

The hydrogen production line is capable of operating as much as possible independently from the power line, allowing the gasification, syngas treatment, CO2 capture, transport and storage equipment to operate at base load, while the power plant operates flexibly in response to the electricity demand.

This can be made possible by storing either the decarbonised hydrogen-rich gas or high purity hydrogen.

In the first alternative, part of the hydrogen rich gas from the CO2 removal is fed to the storage during low electricity demand periods (nightly hours and weekends), and is subsequently used during electricity peak demand.

In the other alternative, the hydrogen-rich gas is fed to an additional pressure swing adsorption (PSA) unit to produce high purity hydrogen and a tail gas stream consisting of hydrogen and impurities in the de-carbonised fuel. Hydrogen can be sold or stored during low electricity demand periods and fed to the gas turbine during peak load operation. Main constraints for this alternative are related to the capability of the gas turbine to vary the hydrogen load and the local availability of geological structures suitable for hydrogen storage.

The main options for storing hydrogen are as a compressed gas (above ground or underground), as a liquid or in metal hydrides. Generally for these specific applications, underground storage is the best solution in relation to the very large volumes of hydrogen to be stored for long periods.

In fact, aboveground compressed gas storage and the metal hydride option are not suitable to large quantities of hydrogen, due to very high costs, while liquid hydrogen has specific applications related to high storage energy density, but requires very expensive cryogenic facilities.

3.3 AGR (CO2 capture) shutdown

Unlike in the post combustion CO2 capture processes, the Acid Gas Removal Unit cannot be shut down completely, as it is needed at least to remove the H2S from the syngas stream, before being fed to the Gas Turbine, to meet the environmental limits. On the other hand, if necessary it could be possible to avoid the separation of the CO2 from the syngas, by properly designing the AGR in order to have the possibility to by-pass the CO2 absorption column only.

A net power plant power production increase of 10-15% is expected in case CO2 is not captured and compressed.

In fact, as no CO2 is separated, the CO2 compressor is shutdown avoiding significant power consumption. In addition, part of the CO2 that has not been captured from the syngas, may act as diluent in the gas turbine for the control of NOx production and therefore nitrogen diluent would not be (partially or totally) required for the Gas Turbine, leading to a power saving because of the nitrogen compressor shutdown or operation at low load.

On the other hand, the CO2 would be released to atmosphere from the combined cycle stack, similarly to an IGCC without CO2 capture. Therefore, this solution could be followed if the cost of emitted CO2 were fluctuating around low figures as in the present market conditions, as it may be economically convenient release the CO2 rather than limit the plant flexibility in electricity generation.