Mitigating plant efficiency loss from carbon capture & storage

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Current technologies for capturing carbon dioxide from power generation processes all produce significant losses in total plant efficiency. A study has identified the main efficiency penalties and highlights potential technology fixes to improve overall plant efficiency.
Suzanne Ferguson, Foster Wheeler, UK

Fossil fuel fired power stations are under growing pressure to cut their carbon emissions. One emerging technology, or set of technologies, that has been proposed to mitigate future CO2 emissions is carbon capture and storage (CCS).

A Foster Wheeler study has identified areas in which significant improvements to the efficiency of carbon capture power generation schemes may be anticipated and quantified the impact on the overall efficiency of a plant. The power generation systems examined were an ultra-supercritical pulverized coal fired scheme (USCPC) with post-combustion capture, and an integrated gasification combined-cycle (IGCC) plant.

In the USCPC scheme, a single pulverized coal fired unit with a nominal 800 MWe capacity was assumed. The boiler was simulated as raising steam at 275 bara/600 à‚°C with single reheat to 600 à‚°C, and incorporating selective catalytic reduction (SCR) for nitrogen oxides removal, an electrostatic precipitator (ESP) for particulate removal and limestone scrubbing for sulphur dioxide removal. An amine-based post-combustion carbon capture process was applied to this plant, followed by CO2 compression to 150 barg with CO2 dehydration.

The IGCC plant comprises two gasification lines supplied by a common air separation unit (ASU), two F-class gas turbines with heat recovery steam generators (HRSGs) and a common steam turbine. The ASU supplies oxygen to the gasifiers and sulphur recovery unit, and also supplies nitrogen for coal conveying and for dilution of hydrogen-rich gas turbine fuel gas.

In each gasification line, coal is milled and dried and fed to an entrained-flow gasifier. The product gas flows through heat recovery with steam generation, particulate removal filtration, sour shift and syngas cooling with heat recovery.

A selective DEPG (polyethylene glycol dimethyl ether) unit first removes hydrogen sulphide (H2S) and then CO2. The H2S-rich stream is treated in a Claus sulphur removal unit (SRU) and tail gas treating unit (TGTU), while the CO2-rich stream is compressed to 150 barg and dehydrated for export to storage. The hydrogen-rich stream is diluted with nitrogen before combustion in the gas turbines.

When carbon capture is applied to a power generation system it reduces the overall efficiency of the plant by introducing a number of parasitic loads resulting in more energy being used internally and leaving less available for export.

These parasitic loads can be caused either by electrical loads such as additional rotating machinery, or as thermal loads, e.g. the heat required for regenerating solvents. The heat requirement reduces the power produced because steam that would have been used for generating electrical power is instead used as a heat source. In order to improve the overall efficiency of a power plant with carbon capture it is necessary to reduce or eliminate as much of the internal energy demand as possible. It is also necessary to consider the power plant system as a whole in order to identify sensible energy saving targets.

USCPC with post-combustion capture

Applying a monoethanolamine-based post-combustion unit to the pulverized coal plant introduces two main parasitic loads and a number of lesser loads (see Figure 1). Firstly, a significant quantity of low-pressure steam is required for solvent regeneration, reducing the electrical output of the steam turbine generator. The second load is the power needed to drive the CO2 compressor.

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Figure 1: The key parasitic loads in the USCPC scheme, incorporating post-combustion carbon capture
Source: Vattenfall

Of the lesser loads, the largest is often the flue gas blower required to elevate the pressure of the entire flue gas stream sufficiently to overcome the pressure drop across the absorption column and any associated heat exchangers. Based on previous work by Foster Wheeler, the typical loads are as follows: solvent reboiler (56 per cent); CO2 compression (33 per cent); flue gas blowers (4 per cent); and others (e.g. the transport of the solvent around the capture plant loop) (7 per cent).

The duty of the solvent regeneration reboiler has been extensively targeted for reduction by improving or changing solvents, or by flashing a portion of the lean solvent to generate a semi-lean stream.1 Study work undertaken by the International Energy Agency Greenhouse Gas Research & Development (IEA GHG R&D) Programme estimates that savings of 27″40 per cent on regeneration energy requirement can be made compared with conventional processes.2 A saving of 30 per cent on reboiler duty is considered for the purposes of this article.

Recently much work has also been done to investigate how to reduce the power requirement for CO2 compression. In a paper by GE,3 savings of up to 20 per cent are anticipated by varying the compression route and achieving liquefaction at the lowest possible pressure for the available cooling medium. Further savings could be achieved by introducing refrigeration cycles; however, the power requirement of the refrigeration cycle was shown to offset the benefit of increased CO2 compression chain efficiency. A saving of 20 per cent on CO2 compressor power will be assumed.

There is a significant requirement for cooling in the amine-based post-combustion carbon capture flow scheme that results in low grade waste heat, which may be recovered elsewhere on the plant. It has been shown in previous Foster Wheeler work that, depending on the individual site circumstances, a greater degree of compressor intercooling can be preferable in overall plant efficiency terms to the recovery of CO2 compressor waste heat.

There is, however, still a significant quantity of recoverable waste heat available from the stripper condenser and solvent coolers to integrate with the power island boiler feedwater preheating. This integration reduces the quantity of steam that is extracted from the steam turbine to preheat the boiler feedwater, hence increasing the electrical output of the steam turbine generator.

A saving of one percentage point on overall power plant efficiency will be considered based upon the results of previous Foster Wheeler study work integrating carbon capture with this type of plant. By incorporating each of the suggested improvements above into a baseline flow scheme for the pulverized coal plant an increase in the net power output of approximately 9 per cent can be achieved, and consequently an increase of around three percentage points in overall plant efficiency.

IGCC Scheme

The IGCC system consists of a more complex process scheme than post-combustion capture, with more process units requiring either heat or power, or both. The main power users are the ASU, CO2 compression and acid gas removal unit (AGR), while the main users of steam are the AGR and the shift (see Figure 2).

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Figure 2: The key parasitic loads in the IPCC scheme, with by carbon capture

Based on previous work by Foster Wheeler, the distribution of the additional parasitic loads of an IGCC power plant due to adding carbon capture are: DEPG-based CO2 removal (46 per cent); CO2 compression (26 per cent); and other (28 per cent). However, when all of the parasitic power loads, excluding heat loads, on the plant, not just those due to adding carbon capture, are compared the picture is somewhat different. Nearly half of all power that is consumed within the power plant is due to the ASU, which only increases in duty by a relatively small amount when adding carbon capture to the IGCC scheme.

The contribution of ‘others’ to the plant parasitic loads is also significant. Improving the efficiency of heat recovery from gasification, energy conversion in the gasifiers and operation of the gas turbines also present opportunities for improving the efficiency of the overall IGCC plant with carbon capture.

Gasification improvements include:

  • Entrained flow gasifiers can be provided with mechanical coal pumping, avoiding need for high-pressure coal conveying nitrogen.
  • Medium-temperature gasification with outlet gas around 1000 à‚°C reduces oxygen consumption, reduces cost of heat recovery and increases the gas turbine contribution to total power output.
  • Fixed bed gasification with outlet gas around 500 à‚°C further reduces oxidant consumption and may be an attractive but so far little explored option.
  • Medium-temperature and low-temperature gasification open the way to practical use of air or enriched air in place of oxygen.

Based on these factors it is anticipated that an overall efficiency improvement of 0.5 percentage points could be realized because of gasification improvements, and therefore 0.5 percentage points improvement is assumed.

One factor limiting the thermal efficiency of IGCC with carbon capture is the generally low firing temperature of gas turbines fuelled with decarbonized fuel (basically hydrogen with nitrogen or steam dilution). The installed gas turbine exhaust temperature of a F-class machine firing natural gas is around 600 à‚°C, although representative exhaust temperatures recommended by manufacturers for firing of decarbonized fuel gas are of the order of 50″80 à‚°C lower.

Several factors are seen as contributing to this downrating, primarily the potential of hot component corrosion by higher steam content from the combustion of hydrogen-rich fuel; the lower calorific value of the decarbonized fuel increases exhaust flow rate, increasing mechanical stresses ” this can be alleviated by air extraction; the perceived need to meet NOx emission limits with existing diffusion burners without resorting to SCR; and understandable conservatism in absence of significant operating experience.

A simulation has shown the potential for increasing the thermal efficiency of an IGCC plant with carbon capture by approximately four percentage points just through increasing the gas turbine exhaust temperature to 626 à‚°C. This represents the best single potential improvement in gasification-based power with carbon capture.

Other potential gas turbine improvements include: higher gas turbine fuel gas preheat; lower burner pressure drop, reducing the fuel gas pressure upstream of the gas turbine and hence reducing the resulting oxygen and diluent nitrogen supply pressures requirements; improved burners and other hot components, permitting high firing temperatures and/or less dilution of the decarbonized fuel gas with nitrogen or steam; pre-mix burners for use with higher firing temperatures, as alternative to SCR for NOx emission control; and reduced capacity gas turbine air compressor, as a substitute for air extraction. An overall efficiency improvement of four percentage points has been applied because of gas turbine performance improvements, mainly as a result of increased exhaust temperature.

Large oxygen production plants currently use cryogenic air distillation, which has been practiced for more than 100 years. Cryogenic oxygen production is a highly energy intensive process, with typical power consumption for 95 per cent purity oxygen of approximately 320″350 kWh/tonne O2 delivered at gasifier pressure using current technology.

Large quantities of oxygen are required by IGCC power generation ” approximately 4700 tonnes/day for a 700 MW net IGCC plant with carbon capture. Oxygen production plants also account for a significant portion of the capital cost of IGCC with carbon capture plants ” approximately 10 per cent.

The significant contributors to the inefficiency of the air separation process are the air compression, the process pressure drops (i.e. heat exchangers and distillation columns) and heat exchanger temperature differences. Improvements in one or more of these increases air compression efficiency and the use of more complex and integrated ASU process cycles have the potential to reduce the energy consumption of cryogenic air separation.

Alternatively, ion transport membranes (ITM) or oxygen transport membranes (OTM) technologies are currently being developed. Studies indicate that ITM’s could significantly reduce the net capital and power costs for oxygen production by around 35 per cent. However, ITMs have not been demonstrated in large-scale plants, so their savings are not yet proven.4 Work undertaken by others indicate that an overall efficiency improvement of approximately 1.2 percentage points is achievable through the use of ITM compared with a cryogenic ASU,4 therefore 1.2 percentage points improvement are assumed.

Similarly to the USCPC case, recent work has been done to investigate possible means of reducing the power requirement for CO2 compression. Similar levels of power and efficiency savings as in the USCPC case would be anticipated for the IGCC case. A saving of 20 per cent on CO2 compression power is considered.

Incorporating all of the suggested improvements above into the baseline flow scheme for the IGCC plant results in an increase in the net power output of approximately 17 per cent and consequently an increase of approximately six percentage points in efficiency.

IGCC study results are encouraging

In the study two generic power plant configurations with carbon capture were considered, investigating potential for reductions in parasitic power and heat demand and improved integration. The suggested improvements were incorporated into a baseline design to quantify the resultant total improvements in plant efficiency with carbon capture from the baseline. Table 1 summarizes the results.

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A number of potential areas of efficiency improvements have been identified, although in all individual plant cases there will be variations in the efficiencies that can be realized depending, amongst other things, on the baseline design employed and specific basis of design.

In the USCPC case the study has shown a cumulative efficiency improvement of over three percentage points can be made. Considering a current delta of approximately nine percentage points between the efficiency of USCPC schemes with and without carbon capture this represents a 35 per cent improvement.

Most encouraging is the IGCC case. The study has shown a cumulative efficiency improvement of more than six percentage points can be made, dominated by the gas turbine. Considering a current delta of approximately nine percentage points between the efficiency of IGCC schemes with and without carbon capture this represents almost 70 per cent improvement.

Further analysis is recommended to understand the capital and operating costs associated with the design adjustments necessary to achieve the efficiency improvements reported, thereby enabling the economic impact to be understood, in terms of levelized cost of electricity, cost of CO2 captured and cost of CO2 avoided.


1. C.A. Roberts, J. Gibbins, R. Panesar et al, Potential for Improvements in Power Generation with Post-Combustion Capture of CO2, 7th International Conference on Greenhouse Gas Control Technologies, Vancouver, Canada, 5″9 September 2004.

2. IEA Greenhouse Gas R&D Programme (IEA GHG), Evaluation of Novel Post-Combustion CO2 Capture Solvent Concepts, 2009/14, November 2009.

3. C. Botero & Co (GE Global Research Centre) & S. Bertolo & Co. (GE Oil & Gas), Thermoeconomic Evaluation of CO2 Compression Strategies for Post Combustion CO2 Capture Applications, GE Oil & Gas Technology Insights 2010.

4. IEA Greenhouse Gas R&D Programme (IEA GHG), Improved Oxygen Production Technologies, 2007/14, October 2007.

The author would like to thank Tim Bullen, manager, Carbon Capture and Storage & Gasification and Geoff Skinner, Process Consultant, Business Solutions group, Foster Wheeler, UK, for their invaluable contribution to the article.

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