Scholarly article on topic 'Flexible CCS plants–A key to near-zero emission electricity systems'

Flexible CCS plants–A key to near-zero emission electricity systems Academic research paper on "Materials engineering"

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Abstract of research paper on Materials engineering, author of scientific article — John Davison

Abstract Power generation processes with CCS that are capable of operating at variable load will be needed to achieve deep reductions in emissions of CO2 to the atmosphere. This paper assesses the effects of operating load factor on costs of coal and gas fired power generation processes with CCS and analyses the emissions and costs of fossil fuel fired plants in an electricity system that includes 35% wind and 25% nuclear generation. The paper shows how the costs of generation increase at an increasing rate as the emissions are reduced using power plants with integrated CCS such as post combustion capture, because many of the CCS plants have to operate at low load factors. This could be avoided by using coal gasification plants with CCS which feed hydrogen to underground buffer storage and then to flexible combined and open cycle gas turbines. The gasification, CO2 capture and storage equipment would operate at base load which would avoid potential practical difficulties of flexible operation and reduce costs. Emissions from the fossil fuel plants in the system with wind and nuclear generation could be reduced to 16 g/kWh at electricity costs competitive with coal-based post combustion capture with emissions of 140 g/kWh. Emissions from the overall electricity system including the wind and nuclear would be 6 g/kWh.

Academic research paper on topic "Flexible CCS plants–A key to near-zero emission electricity systems"

GHGT-10

Flexible CCS plants - A key to near-zero emission electricity

systems

John Davison*

IEA Greenhouse Gas R&D Programme, Orchard Business Centre, Stoke Orchard, Cheltenham, GL52 7RZ, UK

Abstract

Power generation processes with CCS that are capable of operating at variable load will be needed to achieve deep reductions in emissions of CO2 to the atmosphere. This paper assesses the effects of operating load factor on costs of coal and gas fired power generation processes with CCS and analyses the emissions and costs of fossil fuel fired plants in an electricity system that includes 35% wind and 25% nuclear generation. The paper shows how the costs of generation increase at an increasing rate as the emissions are reduced using power plants with integrated CCS such as post combustion capture, because many of the CCS plants have to operate at low load factors. This could be avoided by using coal gasification plants with CCS which feed hydrogen to underground buffer storage and then to flexible combined and open cycle gas turbines. The gasification, CO2 capture and storage equipment would operate at base load which would avoid potential practical difficulties of flexible operation and reduce costs. Emissions from the fossil fuel plants in the system with wind and nuclear generation could be reduced to 16g/kWh at electricity costs competitive with coal-based post combustion capture with emissions of 140g/kWh. Emissions from the overall electricity system including the wind and nuclear would be 6g/kWh.

© 2011 Published by Elsevier Ltd.

Keywords: CCS; flexibility; electricity; hydrogen; wind; costs

1. Introduction

It is becoming accepted that developed countries will need to reduce their emissions by 80% or more by 2050 to reduce the risk of harmful climate change and robust reductions will be required over intermediate timescales [1]. Countries that are currently classed as 'developing' will also have to make substantial reductions [2]. Making large reductions in emissions in some sectors such as small and mobile sources and agriculture may be relatively difficult so large point sources of emissions such as power plants will be expected to achieve near-zero emissions. This paper assesses the role that CCS can play in achieving near-zero emissions of CO2 from electricity systems and the importance of operating flexibility in achieving this goal.

doi:10.1016/j.egypro.2011.02.152

2. Electricity generation systems with low CO2 emissions

To achieve near-zero emissions from an overall electricity generation system it will be necessary to use near-zero emission technologies for nearly all electricity generation. Development of CCS technologies has been focussed on base load generation but a substantial fraction of generation is non-base load (intermediate and peak load). For example in the UK in 2009 around 40% of generation was non-base load [3], as shown in Figure 1. Flexible power plants with near-zero emissions will be needed to decarbonise this electricity.

1 40 <i>

o 30 ra

£ 20 o

0 2000 4000 6000 8000 10000

Figure 1 Electricity load duration curve, UK.

Hydro electricity and biomass fired power plants can be used to satisfy intermediate and peak load demand but their contributions are likely to be limited by resource availability and environmental impacts. Most of the other leading non-fossil fuel near-zero emission generation technologies are poorly suited for satisfying the intermediate and peak loads. Nuclear power plants have poor operating flexibility, and although renewable technologies such as wind and solar can satisfy some of the current intermediate and peak electricity demands they create more intermediate and peak loads at other times due to their variability. CCS technologies are potentially well suited to near-zero emission intermediate and peak load operation but further work is needed to demonstrate their operating flexibility.

This paper assesses the costs and emissions of flexible CCS processes on their own and also in the context of an electricity system that includes substantial fractions of other near-zero emission generation (wind and nuclear).

3. CCS plant descriptions

The following types of fossil fuel power plant with CCS are included in the analysis:

• Pulverized coal with post combustion capture (amine scrubbing)

• Natural gas combined cycle with post combustion capture (amine scrubbing)

• Coal gasification with intermediate storage of hydrogen-rich gas

- Combined cycle gas turbine (CCGT) power plant

- Open cycle gas turbine (OCGT) power plant

• Coal gasification with PSA hydrogen purification, intermediate storage of hydrogen and post

combustion capture of CO2 from combustion of PSA tail gas

- Combined cycle gas turbine power plant

- Open cycle gas turbine power plant

Most work on gasification processes with CCS has been on integrated gasification combined cycles (IGCC) but for this paper an alternative with greater operating flexibility, proposed in [4] and shown in Figure 2 is used as the basis for analysis. In this process the coal gasification hydrogen plant is capable of operating independently of the main power plant, so the gasification, CO2 capture, transport and storage equipment can be operated at full load while the power plant operates flexibly in response to the electricity demand. This is made possible by underground buffer storage of hydrogen. Underground bulk storage of hydrogen in salt caverns has been operated at a

commercial scale in the UK and USA [5]. If required, the gasification and power plants could be on separate sites. The gasification plant includes a small on-site combined cycle plant to provide steam and power and to make optimum use of waste heat and steam from process units. Another advantage of separating the gasification/CCS and power generation units is that open cycle gas turbines, which are highly flexible, can be used. Open cycle gas turbines are not well suited to post combustion capture using the current low temperature solvent scrubbing technology because of the high gas turbine exhaust temperature. Open cycle gas turbines are also not suitable for IGCC because the flexibility of the gas turbine cannot be utilized due to flexibility constraints elsewhere in the plant.

This paper assesses two variants of gasification hydrogen plants; one in which the hydrogen-rich gas from CO2 separation is fed directly to storage and/or the main power generation plant and the other in which the hydrogen rich gas is passed through a pressure swing adsorption (PSA) unit that produces high purity hydrogen for storage and/or the main power plant and a tail gas which consists of the impurities in the hydrogen rich gas (CO, CO2, N2 etc) along with some hydrogen. The PSA tail gas is burned in the on-site combined cycle plant, which includes in-duct firing of the HRSG. The flue gas, which contains around 10 mol% CO2, is fed to a post combustion capture unit, thereby increasing the CO2 capture level of the overall plant to 98.5%.

Figure 2 Non-integration gasification combined cycle with hydrogen storage

Natural gas partial oxidation to produce hydrogen was not assessed in detail because it was shown that for the fuel prices assumed in this study it would be more expensive than coal gasification hydrogen production but it could be attractive at low gas prices [6]. Oxy-combustion was also not assessed because it is at a relatively early stage of development. Oxy-combustion, in common with post combustion capture, is an integrated process in which the power generation and CCS equipment have to operate at the same load factor and as such the conclusions in this paper regarding post combustion capture will also apply in broad terms to oxy-combustion, except that oxy-combustion is in principle able to achieve closer to zero emissions if required.

Detailed discussion of the practicality of flexible operation of CCS is beyond the scope of this paper. The main potential issues for the coal hydrogen cases are the ability to vary the load of hydrogen burning gas turbines and the local availability of suitable geological structures for hydrogen storage. In most other respects the technology is proven. For post combustion capture the ability to balance the solvent and gas flows and distributions within the columns, the thermal integration, the interaction with the steam turbine and the ability to operate CO2 compression, transport and storage with varying flowrates need to be considered. Allowing the percentage capture of CO2 to vary during load changes could help to improve the operating flexibility but this would result in higher emissions. Further work would be needed to quantify the significance of this increase in emissions.

4. Input data

The overall technical and economic input data used in the modelling are given in Table 1 and the data for specific types of plants are shown in Table 2. The specific CO2 emissions and fuel prices are from [7]. The annual capital charge factor corresponds to a discount rate of 8% in constant money values, excluding inflation, a plant life of 25

years and a construction time of 3 years [7]. The capital costs given in Table 2 exclude interest during construction but this is taken into account in the derivation of the annual capital charge factor.

Table 1 Overall technical and economic data

Parameter Units Value

CO2 production - coal kg/MWh (LHV) 328

CO2 production - gas kg/MWh (LHV) 209

Annual capital charge factor % of capital cost 10

Annual maintenance and miscellaneous operating costs % of capital cost 4

Coal price €/GJ (LHV basis) 2

Natural gas price (base case) €/GJ (LHV basis) 6

Natural gas price (sensitivity case) €/GJ (LHV basis) 8

CO2 transport and storage cost €/tonne CO2 5

Hydrogen storage capital cost €/kg 10

Table 2 Input data for power generation and hydrogen plants

Parameter Units Hydrogen Hydrogen Pulverised coal Natural gas CCGT Natural

production power plant power plant gas

Without With CCGT OCGT Without With Without With OCGT

PSA PSA capture capture capture capture

Efficiency %, LHV 57.4 54.2 58 44 45 36 59 52 45

Capital cost €/kWe 1100 1200 790 480 1600 2500 750 1250 430

CO2 capture % 85 98.5 0 0 0 90 0 85 0

Availability % 92 92 93 95 91 88 93 90 95

The plant data used in this paper are based on current technology and are for 'nth plants', i.e. excluding the additional costs associated with first-of-a-kind plants. Costs of all types of power plants are currently highly uncertain due to the recent large fluctuations in capital and fuel costs [8]. The plant capital costs and efficiencies in table 2 were derived from studies undertaken by engineering contractors [8,9,10,11]. The non-fuel operating costs are based on these same references; differences in costs between different technologies are considered to be not significant within the context of this study.

The annual load factor of the hydrogen plants is the same as the annual plant availability, because hydrogen storage enables the plants to operate whenever they are technically available. The load factors of the power plants are dictated by the variability of power demand and are therefore lower than the plant availability.

The cost of hydrogen storage used in this paper is based on a recent published cost of salt cavern natural gas storage and is conservatively high compared to the wide range of published costs of hydrogen storage [4]. Depleted natural gas reservoirs may be substantially cheaper than salt caverns for gas storage [4], so if such reservoirs could be used the costs would be lower than those reported in this paper. The cost of CO2 transport and storage was assumed to be a fixed cost per tonne of CO2 stored. In practise the cost per tonne would be higher if the CO2 flowrate was variable, so the ability of the gasification hydrogen production and storage scheme to provide a constant flow to the CO2 transport and storage system would be an additional benefit not taken into account in this analysis.

5. Costs of individual generation technologies

Costs of the individual electricity generation technologies with CCS were estimated for a range of load factors using input data described in section 4. The costs of hydrogen storage depend on the details of the electricity demand profile, as discussed in section 6. For the estimation of costs of individual technologies a fixed cost of €5/MWh has been included for hydrogen storage. Costs of individual generation technologies with CCS for a range of load factors are shown in Figure 3. Costs of electricity depend strongly on the fuel price. At the base case gas price of €6/GJ the lowest cost technology for load factors above 35% is natural gas combined cycle with post combustion capture but at a gas cost of €8/GJ coal-based plants have lower costs at all load factors. At load factors above 70% post combustion capture is the lowest cost coal-based option but its costs increase steeply as the load

factor is reduced because of the high fixed costs of the power generation and capture plants. The costs of the gasification-hydrogen options increase less when the load factor is reduced because the gasification and CCS units continue to operate at full load. At load factors between 70% and 30% the gasification hydrogen combined cycle option (without PSA) is the lowest cost coal-based option and at load factors below 30% the coal-hydrogen technology with open cycle gas turbines is the lowest coast option.

Load factor, %

- Gas post combustion, 6€/GJ

Gas post

combustion, 8€/GJ

Coal post combustion

Coal hydrogen CCGT

Coal hydrogen OCGT

Figure 3 Costs of generation technologies

The CO2 emissions of the individual technologies are shown in Figure 4. The lowest emissions are from the coal gasification hydrogen technology with PSA which has emissions of 15g/kWh.

.C 700

□ No CCS

□ With CCS

Pulverised coal

Natural gas Natural gas OCGT CCGT

Coal H2, OCGT

Coal H2, CCGT

Pulverised coal

Natural gas Coal H2, Coal H2 CCGT PSA, OCGT PSA, CCGT

Figure 4 CO2 emissions from electricity generation 6. Modelling of an electricity system including CCS and other low-CO2 technologies

6.1. Outline of the modelling

In most countries CCS would be used in combination with other technologies because generation companies and national energy policy makers like to ensure diversity to minimise the potential impacts of technical, economic and political uncertainties. A scenario has been modeled in which 35% of electricity is generated from wind, 40% is from flexible fossil fuel fired plants with and without CCS and the remaining 25% is from a base load technology with near-zero emissions, which could be nuclear or base load CCS. This is a simplified version of what may apply in the UK, where there is expected to be large scale use of wind energy and significant new nuclear capacity is being considered to replace plants that will retire. The analysis reported in this paper could be extended in future to include other technologies that may be significant in some countries, such as solar and marine energy, biomass and hydro, including pumped storage, although these technologies currently play only a relatively minor role in the UK generation system and this is not expected to change substantially in the near future.

6.2. Description of the modelling

Electricity system performance has been analysed using an Excel-based model in which electricity supply and demand is modelled in half-hourly periods throughout a year. The electricity demand is assumed to be satisfied according to a merit order based on marginal operating costs, using combinations of the fossil fuel technologies described in section 3, along with wind and nuclear generation. Wind and nuclear plants have the lowest marginal costs (i.e. operating costs excluding any fixed and capital-related costs) and they operate whenever they are available. At some times in some scenarios the total generation from these technologies exceeds the electricity demand and at these times any surplus is assumed to be discarded. Surplus electricity could be used at such times to produce hydrogen by electrolysis but this has shown to be not economically attractive except in very high renewable energy scenarios because the quantities of surplus electricity and the load factors of the electrolysers are low [4]. The plants with the next lowest marginal costs will be fossil fuel plants with CCS and the plants with the highest marginal costs will be fossil fuel plants without CCS. Fossil fuel plants with CCS will have lower net marginal costs than fossil fuel plants without CCS because the extra costs of operating the CCS equipment will be less than the costs of buying CO2 emissions permits (if this was not so it would not have been worthwhile building a plant with CCS). For plants without CCS, natural gas combined cycles are assumed to be used for load factors above 30% and open cycle plants are used for load factors below 30%. Open cycle plants tend to have lower costs for low load operation and their greater flexibility also makes them more suitable for this role. For this analysis it is assumed that new open cycle gas turbine plants would be built to satisfy low load operation but in most mature electricity systems few plants are normally built specifically for low load operation and instead the operators use old plants which are no longer competitive for base load operation due to their low thermal efficiencies. If such plants could be used the costs of generation would be lower than those shown in this paper.

The model uses half-hourly electricity demand and wind generation data for the UK in 2009 [3]. For the scenario assessed in this paper, which includes substantially more wind generation than at present, wind generation has been scaled directly from the 2009 data. This is a conservative assumption because when wind is used on a larger scale there will be greater geographical distribution and use of offshore sites, which are expected to reduce variability. For the gasification-hydrogen options the model includes a detailed calculation of the quantity of hydrogen storage required to enable the gasification and CCS plants to operate at full load throughout the year.

6.3. Modelling results

The large scale use of wind and nuclear generation pushes fossil fuel power plants into operating at only intermediate and peak load, as shown in Figure 5.

Figure 5 Electricity load duration curve for fossil fired plants

Costs of generation from the fossil fuel plants, based on a natural gas cost of €6/GJ, are shown in Figure 6. The proportion of the plants that include CCS is varied to show the relationship between costs and emissions. It should be noted that the costs in Figure 6 are for the intermediate and peak load generation in the overall electricity system.

These costs should not be compared directly to costs of base load generation because revenues per kWh for intermediate and peak load will be substantially higher than for base load.

CO2 emissions from fossil fuel plants, g/kWh

-•- Coal H2 PSA

-■- Coal H2 no PSA

♦ Gas post combustion CCS +gas peak

X Coal post combustion CCS + gas peak

-h- Gas no CCS

Figure 6 Cost of electricity generation from flexible fossil fuel plants, €6/GJ natural gas cost

The data point near the lower right hand corner of Figure 6 represents a system in which all of the fossil fuel plants are gas fired (combined and open cycle) without CCS. The lines to the left of this data point are:

1. Pulverized coal plants with CCS for higher load factor operation, along with natural gas plants without CCS (combined and open cycle) for lower load operation,

2. Natural gas combined cycle plants with CCS for higher load factor operation, along with natural gas plants without CCS (combined and open cycle) for lower load operation.

As the proportion of plants that include CCS increases, the CO2 emissions decrease but the costs increase. At low overall emission rates the costs increase steeply because CCS is used in plants operating at low load factors. The cost of CO2 abatement (€/tonne CO2) is proportional to the slope of the generation cost vs emissions curve, so it can be seen that the specific abatement cost increases at lower emission levels. For example, for gas fired plants, costs increase rapidly below around 100g/kWh (40g/kWh from the overall electricity system, taking account of the electricity from the near-zero CO2 emission wind and nuclear plants), This represents a system in which 90% of the fossil fuel generation is from plants with CCS and 52% of the installed capacity includes CCS. This shows that to avoid excessive costs it is important that regulations do not specify that all gas fired plants must include CCS if post combustion capture is to be used. Low load factor plants that are essential for electricity system operation should be excluded from such a requirement.

The coal gasification plants with hydrogen storage are represented by two single data points, representing plants with and without PSA hydrogen purification. In these cases all of the power generation is by combined and open cycle plants fired with hydrogen or hydrogen-rich gas. For the same level of CO2 emissions the cost of the coal hydrogen case without PSA is almost the same as the cost of the pulverized coal case with post combustion CCS. The coal hydrogen case with PSA has a 4% higher generation cost but substantially lower CO2 emissions: 16g/kWh compared to 156g/kWh for the plant without PSA (with combined and open cycle power plants). The emissions of CO2 from the overall electricity system taking account of wind and nuclear plants would be 6g/kWh for the coal hydrogen PSA case.

The analysis only considers new plants. Retrofit of post combustion CCS to existing plants may be competitive for low load factor operation and should be included in the analysis in future studies.

In Figure 7 the cost of natural gas is increased to €8/GJ. Comparison of Figures 6 and 7 shows that the relative costs of the generation technologies are highly sensitive to the cost of gas. At this higher gas cost the coal-based hydrogen technology with PSA has the lowest cost of CO2 abatement compared to the reference case of natural gas fired plants without CCS.

CO2 emissions from fossil fuel plants, g/kWh

-•- Coal H2 PSA

-■- Coal H2 no PSA

—♦— Gas post combustion CCS +gas peak

-X— Coal post combustion CCS + gas peak

-A- Gas no CCS

Figure 7 Cost of electricity generation from flexible fossil fuel plants, €8/GJ natural gas cost

7. Conclusions

CCS plants capable of flexible operation will be needed to enable CO2 emissions from electricity generation to be reduced to near-zero. Flexibility will be needed to cope with the variability in power demand and greater flexibility will be needed if variable renewable and inflexible nuclear power plants are used on a large scale. Further work is needed to demonstrate the flexibility of CCS processes.

Costs of power generation with CCS depend highly on fuel costs, the type of electricity system and the required CO2 emissions. For operation at high load factors, power plants with integrated CCS such as post combustion capture have the lowest costs but it is not possible to achieve deep reductions in emissions by abating only base load plants. Costs increase at an increasing rate as the emissions of an electricity system are reduced using power plants with integrated CCS because many of the CCS plants have to operate at low load factors. This could be avoided by using coal gasification plants with CCS which feed hydrogen to underground buffer storage and then to flexible combined and open cycle gas turbines. The gasification, CO2 capture, transport and storage equipment would operate at base load which would avoid potential practical difficulties of flexible operation and reduce costs. Emissions from the fossil fuel plants in a system with 40% fossil fuel generation, 35% wind and 25% nuclear could be reduced to 16g/kWh at electricity costs competitive with coal-based post combustion capture with emissions of 140g/kWh. Emissions from the overall electricity system including the wind and nuclear would be 6g/kWh.

8. References

[1] G8, 2009. G8 leaders' declaration: responsible leadership for a sustainable future, www.g8italia2009.it

[2] IEA, 2009. Technology roadmap - carbon capture and storage, IEA/OECD, Paris, France.

[3] NETA, 2009. www.bmreports.com/bsp/bsp_home.htm

[4] Davison J. Electricity systems with near-zero emissions of CO2 based on wind energy and coal gasification with CCS and hydrogen storage, International Journal of Greenhouse Gas Control 3 (2009) 683-692.

[5] Roads2HyCom, 2009. Large hydrogen underground storage, www.ika.rwth-aachen.de

[6] IEAGHG, 2005. Retrofit of CO2 capture to natural gas combined cycle power plants. Report 2005/1, January 2005, IEAGHG, Cheltenham, UK.

[7] IEAGHG, 2009. Criteria for technical and economic assessment of plants with low CO2 emissions. Technical review 2009/TR3, May 2009, IEAGHG, Cheltenham, UK.

[8] Mott MacDonald, 2010. UK electricity cost update, www.decc.gov.uk/en/content/cms/statistics/projections/ projections.aspx

[9] IEAGHG, 2007. Co-production of hydrogen and electricity by coal gasification with CO2 capture. Report 2007/13, September 2007, IEAGHG, Cheltenham, UK.

[10] Klara, 2007. Cost and performance baselines for fossil energy plants, volume 1: bituminous coal and natural gas to electricity, final report. DOE/NETL-2007/1281, National Energy Technology laboratory, USA, May 2007.

[11] IEA GHG, 2004. Improvement in power generation with post combustion capture of carbon dioxide. Report PH4/33, November 2004, IEAGHG, Cheltenham, UK.