science direct - energy _ performance and costs of power plants with capture and storage of co2
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EnergyVolume 32, Issue 7, July 2007, Pages 1163-1176
doi:10.1016/j.energy.2006.07.039| How to Cite or Link Using DOI
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Performance and costs of power plants with captureand storage of CO2
John Davison,
IEA Greenhouse Gas R&D Programme, Orchard Business Centre, Stoke Orchard, Cheltenham,
GL52 7RZ, UK
Received 23 February 2006; Available online 2 October 2006.
Abstract
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Article Figures/Tables (11) References (28) Cost and performance of fossil fuel power plants with C...Energy Policy
Techno-economic study of CO2 capture and storage in coa...
Fuel Processing Technology
Techno-economic evaluation of advanced IGCC lignite coa...
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s paper assesses e ree ea ng ec no og es or cap ure o 2 n power genera on p an s,
i.e., post-combustion capture, pre-combustion capture and oxy-fuel combustion. Performance, cost
and emissions data for coal and natural gas-fired power plants are presented, based on information
from studies carried out recently for the IEA Greenhouse Gas R&D Programme by major engineering
contractors and process licensors. Sensitivities to various potentially significant parameters are
assessed.
Keywords: CO2; Capture; Electricity; CCS; Costs
Article Outline
1. Introduction
2. Basis of plant assessments
2.1. Technical criteria
2.2. Economic criteria
3. Plant descriptions
3.1. Post-combustion capture plants
3.2. Pre-combustion capture plants
3.3. Oxy-combustion
4. Plant performance
4.1. Efficiency and power output4.2. CO2 emissions
5. Resource consumptions and emissions
6. Costs
6.1. Costs of power generation
6.2. Costs of CO2 emissions avoidance
6.3. Costs of CO2 transport and storage
6.4. Sensitivity to fuel cost
6.5. Sensitivity to discount rate
6.6. Sensitivity to load factor
6.7. Sensitivity to coal type
7. Potential for future improvement
8. Other criteria affecting technology choice
9. ConclusionsReferences
Development of a scalable infrastructure model for plan...
Applied Energy
Environmental impacts and costs of woody Biomass-to-Liq...
Forest Policy and Economics
Reducing energy penalties in carbon capture with Organi...
Applied Thermal Engineering
Electric Power Generation: Fossil Fuel
Encyclopedia of Energy
Integrated Gasification Combined-Cycle Power Plants
Encyclopedia of Physical Science and Technology
Power Generation and Human Health
Encyclopedia of Environmental HealthTurbines, Gas
Encyclopedia of Energy
Gas-Turbine Power Plants
Encyclopedia of Physical Science and Technology
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S i Di t E P f d t f l t ith t d t f CO2 htt // i di t / i / ti l / ii/S0360544206002155
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e ex s ng coa - ase p an s nc u es s convers o n an 2 cap ure.
The IEA Greenhouse Gas R&D Programme (IEA GHG) has assessed the performance and costs of
new power plants with and without CO2 capture. Studies were carried out for IEA GHG by the
following leading engineering contractors and process developers:
• Post combustion capture: Fluor, in collaboration with Mitsui Babcock and Alstom, and MHI [3].
• Pre-combustion capture (IGCC ): Foster Wheeler, with data from gasification and gas treating
vendors [4].
• Oxy-combustion: Mitsui Babcock, in collaboration with Air Products and Alstom [5].
IEA GHG's recent studies on new power plants do not include natural gas-based pre-combustion
capture but IEA GHG has carried out a study on retrofit of capture to existing natural gas combined
cycle plants [6]. That study showed pre-combustion capture to be significantly more expensive than
post-combustion capture. IEA GHG carried out a later study which put some of the results from the
earlier studies [3] , [4] and [5] on a consistent basis with updated fuel prices and currency exchange
rates [7]. This paper presents results from that later report [7] and also includes more of the cases
from the IGCC study [4] on the same updated basis.
2. Basis of plant assessments
The reference power plants without CO2 capture in this paper use high-efficiency commercially
demonstrated technologies. The CO2 capture units are based on current designs but it is recognisedthat CO2 capture has not yet been demonstrated in large commercial power plants. The efficiencies of
all of the power-generation technologies considered in this study will improve in future due mainly to
development of more advanced gas and steam turbines. The performance and costs of CO2 capture
technologies are also expected to improve in future due to technology developments and ‘learning by
doing’. This is discussed further in Section 6.
The main criteria used in the assessments in this paper are summarised below and in the following
plant descriptions.
2.1. Technical criteria
Coal feed Australian bituminous coal
Ash 12.2% as-received
Moisture 9.5% as-received
Carbon 82.5% dry-ash-freeHydrogen 5.6% dry-ash-free
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Oxygen 9.0% dry-ash-free
Nitrogen 1.8% dry-ash-free
Sulphur 1.1% dry-ash-free
Chlorine 0.03% dry-as-free
LHV 25.87 MJ/kg as-received
Natural gas Southern Norwegian North Sea
Methane 83.9 vol%
Ethane 9.2 vol%
Propane 3.3 vol%
Butane+ 1.4 vol%
CO2 1.8 vol%
N2 0.4 vol%
Plant location Greenfield plant site, Netherlands coastal location with no special civil works
Ambient pressure 101.3 kPa
Average air temperature 9 °C
Average sea water temperature 12 °C
Cooling water system Once-through sea water cooling
CO2 output pressure 11 MPaMaximum emissions Particulates 25 mg/Nm3 (6% O2)
NO X 200 mg/Nm3 (6% O2)
SO2 200 mg/Nm3 (6% O2)
The pressure to which CO2 is compressed will depend on how it is transported and the nature of the
storage reservoir. The data in this paper include compression of CO2 to 11 MPa, at which pressure it
is a dense phase fluid with a density of about 0.75t/m3
at 35 °C. Because of its high density, the CO2
could if required be pumped to a higher pressure with very little impact on the plant performance and
cost.
2.2. Economic criteria
DCF rate 10% per year, excluding inflation
Plant operating life 25 years
Plant construction time 3 years
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Expenditure schedule 20%/45%/35%
Load factor 85%
Coal price US$2.2/GJ (LHV basis), with sensitivity to $1.1/GJ 1
Natural gas price US$7.8/GJ (LHV basis), with sensitivity to $3.9/GJ
Contingencies: 10% of installed plant cost
Fees and owners cost 7% of installed plant cost (excludes interest during construction)
Interest during construction Calculated from the expenditure schedule and discount rate
Decommissioning cost Zero net cost (assumed to be equal to scrap value)
Working capital 30 days of raw materials and consumables, excluding natural gas
Start up costs 3 month commissioning period
Reduced load factor (60%) for remainder of year 1 for coal plants
Operating labour €50k/year (excludes maintenance labour), 5 shift operation
Maintenance costs 2–4% of installed cost per year, depending on type of process unit
Local taxation and insurance 2% of installed cost per year
By-product/waste values Zero net values for sulphur, slag/ash and gypsum
Exchange rate 1.23 US$/€
The base case fuel prices are the average of Mott MacDonald's long-run forecast prices up to 2025 for
the Netherlands coastal location [7]. The sensitivity to lower prices (half those of the base case) is
assessed because of the high uncertainty in prediction of long-term energy prices and because prices
vary between different locations.
The capital costs shown in Table 4 include miscellaneous owner's costs but exclude interest during
construction and start-up costs, although these are taken into account in the calculation of costs of
electricity generation. Costs of electricity (380 kV) and CO2 (11 MPa) transmission beyond the plant
boundary are excluded. Coal is delivered to the plant boundary by conveyor and 30 days of outdoor storage is included on-site. The inlet and discharge ducts for the seawater cooling system are
included.
The capital costs in IEA GHG's original studies [3] , [4] and [5] were estimated using source data
denominated mainly in US$ and €. The $/€ exchange rate has varied between about 0.85 and 1.35:1
between 2001 and 2006, which introduces a degree of uncertainty into cost estimates. In IEA GHG's
latest study [7], costs for selected cases from the earlier studies [3] , [4] and [5] were updated using
the 2005 average exchange rate of 1.23$/€. For this paper further cases were updated using this
same exchange rate.
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avo e are e emssons o a p an w 2 cap ure compare o e emss ons o a ase ne p an
without CO2 emissions. The baseline plant should be type of plant that would be displaced by a plant
with CO2 capture. This could either be a plant based on the same type of power generation
technology as the plant with CO2 capture or an alternative type of plant. Table 2 shows the quantities
of emissions avoided for three baselines: the same type of power generation technology, a PF plant
and an NGCC plant. When compared to plants using the same type of power generation technology,the quantities of emissions avoided are lower than the quantities captured because of the reduction in
thermal efficiency, which results in greater production of CO2. In some circumstances plants with CO2
capture may displace old inefficient power plants, in which case the quantities of CO2 emissions
avoided would be significantly higher than those shown in Table 2.
Table 2. CO2 emissions
Fuel Power generation
technology
CO2
capture
technology
CO2
emissions
(g/kWh)
CO2
captured
(g/kWh)
CO2
captured
(%)
CO2 avoided (g/kWh)
Same
technology
baseline
PF
baseline
NGCC
baseline
Coal PF None 743 — — — — —
Fluor 117 822 87.5 626 626 262MHI 92 832 90 651 651 287
Oxy 84 831 90.8 659 659 295
IGCC None 763 — — — — —
(Shell) Selexol 142 809 85 621 601 237
IGCC None 833 — — — — —
(GE) Selexol 152 851 85 681 591 227
Gas IGCC None 379 — — — — —
Fluor 66 378 85 313 677 313
MHI 63 362 85 316 680 316
Oxy 12 403 97.2 367 731 367
The percentages of CO2 captured which are shown in Table 2 are in the range of 85–90% for the
post-combustion and pre-combustion capture plants and 90–97% for the oxy-combustion plants.
These are not necessarily the technical limits or economic optima for each of the technologies. For
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examp e, ncreas ng e percen age 2 cap ure n coa - ase pos com us on cap ure rom –
is reported to reduce the cost per tonne of CO2 captured by 2% [3]. Further work is needed to
determine the effects of percentage CO2 capture on costs and efficiency for all technologies.
The plants do not all produce the same purity of CO2. Some technologies inherently produce
high-purity CO2 but others inherently produce lower purity CO2 which has to be refined if a higher
purity is required. The relative merits of the technologies therefore depend on the CO2 purity
requirements.
5. Resource consumptions and emissions
The main resource consumptions, solid waste and by-product outputs and atmospheric emissions are
shown in Table 3. Natural gas-fired plants have the lowest resource consumptions and emissions.
Emissions to the atmosphere from plants without capture depend on environmental legislation and the
emissions shown in Table 3 do not represent the practical limits for each technology. For each type of fuel and power generation technology, CO2 capture results in increases in the fuel consumption and
outputs of wastes and by-products per unit of net electricity output, except for SO X emissions to the
atmosphere which are reduced.
Table 3. Resource consumptions and emissions [g/kwh]
Fuel Power
generation
technology
Capture
technology
Resource consumptions Wastes and by-products (dry
basis)
At
emi
Fuel Limestone
/flux
Chemicalsorbent Ash
/slag
Gypsum Sulphur Spent
sorbent
CO
Coal PF None 316 8.4 — 39.3 13.8 — — 743
Fluor 400 11.6 1.31 48.9 19.1 — 2.63 117
MHI 394 11.4 0.13 48.3 18.8 — 0.26 92
Oxy-fuel 393 — — 48.0 — — — 84
IGCC None 323 10.0 0.01 44.7 — 2.78 0.01 763
(Shell) Selexol 404 12.5 0.02 55.8 — 3.48 0.02 142
IGCC None 367 — 0.01 54.1 — 3.16 0.01 833
(GE) Selexol 442 — 0.02 65.3 — 3.81 0.02 152
Gas NGCC None 120 — — — — — — 379
Fluor 141 — 0.61 — — — 1.19 66
MHI 135 — 0.10 — — — 0.20 63
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echnology echnology MW $/kW
Coal Pulverised fuel None 758 1408
Post-combustion (Fluor) 666 1979
Post combustion (MHI) 676 2043
Oxy-combustion 532 2205
IGCC (Shell) None 776 1613
Pre-combustion, Selexol 676 2204
IGCC (GE) None 826 1439
Pre-combustion, Selexol 730 1815
Gas Gas turbine combined cycle None 776 499
Post-combustion (Fluor) 662 869
Post-combustion, MHI 692 887
Oxy-combustion 440 1532
Table 5. Cost of electricity and CO2 avoidance
Fuel Power generation
technology
CO2 capture
technology
$1.1/GJ coal, $3.9/GJ
gas
$2.2/GJ coal, $7.8/GJ
gas
c/kWh $/t CO2
avoided
c/kWh $/t CO2
avoided
Coal Pulverised fuel None 4.46 5.36
Post-combustion, Fluor 6.34 30 7.49 34
Post combustion, MHI 6.27 28 7.40 31
Oxy-combustion 6.63 33 7.76 36
IGCC (Shell) None 4.88 5.81
Pre-combustion,
Selexol
6.52 33 7.68 39
IGCC (GE) None 4.55 5.60
Pre-combustion,
Selexol
5.66 20 6.94 27
Gas Combined cycle None 3.70 6.23
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Fuel Power generation
technology
CO2 capture
technology
$1.1/GJ coal, $3.9/GJ
gas
$2.2/GJ coal, $7.8/GJ
gas
c/kWh $/t CO2
avoided
c/kWh $/t CO2
avoided
Post-combustion, Fluor 5.07 44 8.03 58
Post-combustion, MHI 4.93 39 7.76 48
Oxy-combustion 6.84 85 9.98 102
Full-size image (56K)
Fig. 3.
Breakdown of costs of electricity.
The cost of electricity generation with CO2 capture is marginally higher for the natural gas combined
cycle plants with post combustion capture than for the coal-based IGCC and post-combustion plants.
The cost difference is greater between natural gas and coal based oxy-combustion plants. The natural
gas fired oxy-combustion plant has a cost of electricity that is about 25% higher than that of the natural
gas post-combustion capture plant. A 40% increase in the cost of the combined cycle unit (excluding
the oxygen plant and CO2 compression), per MW of gross output, contributes to the relatively high
cost of the natural gas fired oxy-combustion plant.
In Fig. 3 the costs of electricity generation are broken down into capital charges, operation andmaintenance (O+M) and fuel costs. It can be seen that the main cost for the gas-fired plants is fuel but
for the coal-fired plants, the capital charges are most significant.
The net outputs of the plants with and without capture [3] , [4] and [5] differ somewhat, as shown in
Table 4 because some items of equipment, e.g., gas turbines have fixed sizes. The only way to force
the plant outputs to be the same would be to operate some of them at non-optimum conditions, which
would not be realistic. The differences in plant size affect the economic comparisons, because plants
normally have economies in scale, i.e. the cost per unit output usually decreases with increasing plantsize. If all of the plants were converted to a hypothetical standard power out of 750 MWe using a scale
exponent of 0.8, the cost of electricity would decrease by 0.3 c/kWh for the oxyfuel plant, by 0.1 c/kWh
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av son omen c n ancuso cap ure n ow ran coa power p an s n:
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av son , omen c n , ancuso . 2 cap ure n ow ran coa power p an s. n:
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1These fuel prices are on an LHV basis, for consistency with the plant performance data. However, it
should be noted that fuel is often traded on an HHV basis. Bituminous coal prices on an LHV basis are
about 5% higher than on an HHV basis and natural gas prices are about 10% higher.
2This paper uses data for reference-pulverised coal and natural gas combined cycle plants from [3].
These data are similar to data from [5].
Copyright © 2006 Elsevier Ltd. All rights reserved.
EnergyVolume 32, Issue 7, July 2007, Pages 1163-1176
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