gas quality control in oxy-pf technology for carbon...
TRANSCRIPT
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Gas quality control in oxy-pf technology
for carbon capture and storage
By
Xianchun Li, Yinghui Liu, Rohan Stanger, Lawrence Belo, Tim Ting and Terry Wall
Chemical Engineering, University of Newcastle, Australia, 2308
February 2012
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A report commissioned by Australian National Low Emissions Coal R&D Program Acknowledgment We acknowledge the support from Xstrata Coal Low Emissions Research and Development Corporation Pty limited for the research project to the University of Newcastle on “Coal quality impacts and gas quality control in oxy-fuel technology for CCS”. Tim Ting acknowledges a UNRS scholarship from the University of Newcastle. Terry Wall’s contribution is partially based on his role as a Science Leader in the Australian National Low Emissions Coal Research and Development (ANLEC R&D), and he wishes to acknowledge financial assistance from ANLECR&D. ANLEC R&D is supported by Australian Coal Association Low Emissions Technology Limited and the Australian Government through the Clean Energy Initiative. Disclaimer Use of the information contained in this report is at the user’s risk. While every effort has been made to ensure the accuracy of that information neither ANLEC R&D nor the authors make any warranty, express or implied, regarding it. Neither ANLEC R&D nor the authors are liable for any direct or indirect damages, losses, costs or expenses resulting from any use or misuse of that information. The views offered in this report may not be considered as necessarily representative of organisations commissioning or undertaking this work. Copyright notice © No reproduction of any part of this report may be sold or distributed for commercial gain nor shall it be modified or incorporated in any other work, publication or website. All reproductions of this report must be reproduced in full and must fully attribute authorship to the stated authors, unless you have the authors' express written consent.
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ACRONYMS AND ABBREVIATIONS ACI Activated carbon injection AH Air heater AL Air Liquid APCD Air pollution control device(s) ASU Air separation unit BAHX Brazed aluminum heat exchangers BFW Boiler feed water B&W Babcock & Wilcox BOP Balance of plant CFB Circulating fluidized bed CFD Computational fluid dynamics COAL Coal handling system COP Callide oxyfuel project CPU CO2 purification unit CCS Carbon capture and storage DCCPS Direct contact cooler/polishing scrubber DOE Department of Energy in the United States DRET Department of Resources, Energy and Tourism EERC The Energy & Environmental Research Center EPA Environmental Protection Agency EPRI Electric Power Research Institute ESP Electric static precipitator FD Forced draft FDF Forced draft fan FF Fabric filter FGC Flue gas conditioning FGD Flue gas desulfurization GCCSI Global Carbon Capture and Storage Institute HgRS Mercury removal system HHV High heating value ID Induced draft IDF Induced draft fans IDLH Immediately Dangerous to Life or Health IGCC Integrated gasification combined cycle ITM Ion transport membrane LCOE Levelized cost of electricity LHV Low heating value NETL National Energy Technology Laboratory NGCC Natural gas combined cycle OCC1 The 1st Oxy-fuel Combustion Conference O&M Operation & maintenance PC Pulverized coal pf Pulverized fuel PJFF Pulse jet fabric filter
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PM Particulate matter RFG Recycled flue gas SC Super critical SCR Selective catalytic reduction SDA Spray dryer adsorbent SNCR Selective non-catalytic reduction STG Steam Turbine Generator TS&M Transportation storage & maintenance UN United Nation USC Ultra super critical VPSA Vacuum pressurized swing adsorption WFGD Wet flue gas desulfurization
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Table of Contents
EXECUTIVE SUMMARY ...................................................................................................... 10
1. INTRODUCTION ................................................................................................................ 13
2. GAS QUALITY AND CLEANING ISSUES ...................................................................... 17
3. COAL QUALITY IMPACTS– SULFUR............................................................................ 18
3.1 Coal sulfur reactions and impacts in oxy-fuel combustion ................................................ 18
3.1.1 Sulfur species .............................................................................................................. 18
3.1.2 Impacts ........................................................................................................................ 19
3.2 Control of impacts of sulfur ............................................................................................... 22
3.2.1 Control in the power plant ........................................................................................... 22
3.2.2 Control by CO2 purification and compression ............................................................ 22
4. COAL QUALITY IMPACTS- MERCURY ........................................................................ 22
4.1 Coal mercury reactions and impacts in oxy-fuel combustion ............................................ 22
4.2 Mercury emissions in oxy-fuel combustion ....................................................................... 24
4.3 Control of impacts of mercury ........................................................................................... 27
4.4 Significance of future mercury treaty ................................................................................. 28
5. COAL QUALITY IMPACTS– NITROGEN ...................................................................... 29
5.1 Coal nitrogen reactions and impacts in oxy-fuel combustion ............................................ 29
5.1.1 Nitrogen species .......................................................................................................... 29
5.1.2 Impacts ........................................................................................................................ 30
5.2 Control of impacts of nitrogen ........................................................................................... 32
5.2.1 Control in the power plant ........................................................................................... 32
5.2.2 Control by CO2 purification and compression ............................................................ 35
6. COAL QUALITY IMPACTS– OTHER SPECIES ............................................................. 36
7. PUBLISHED FLOWSHEETS ............................................................................................. 37
7.1 Published flow-sheets for front-end (combustion) ............................................................. 37
7.1.1 Callide oxy-fuel Project (COP) ................................................................................... 37
7.1.2 Babcock and Wilcox flowsheet for low sulfur (<1%) coal ......................................... 38
7.1.3 Babcock and Wilcox FutureGen 2.0 flowsheet for high sulfur (>1%) coal ................ 39
7.2 Published flow-sheets for back-end (compression) ........................................................... 40
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7.2.1 Air Liquide (AL) design for the Callide Oxyfuel Project and other AL options
reported ................................................................................................................................. 40
7.2.2 Air Products sour gas compression ............................................................................. 43
7.2.3 LINDE process at the Schwarze Pumpe oxy-fuel pilot-plant ..................................... 45
8 ECONOMIC ASSESSMENTS ............................................................................................. 46
8.1 The review of published study results ................................................................................ 46
8.1.1 Pulverized Coal Oxy-combustion Power Plants of DOE NETL study ....................... 47
8.1.2 Economic Assessment of Carbon Capture and Storage Technologies from a GCCSI
study ..................................................................................................................................... 50
8.1.3 The EPRI study of Australian Electricity Generation Technology Costs commissioned
by DRET .............................................................................................................................. 53
8.2 Cost impacts ....................................................................................................................... 55
REFERENCES ......................................................................................................................... 60
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List of Tables
Table 1 Illustrative gas compositions, vol % or as stated, for coal-fired CCS technologies,
based on .................................................................................................................................. 16
Table 2 Listing of some gas quality and cleaning issues in oxy-fuel technology ................ 17
Table 3 Sulfur impacts in pulverised coal-firing power plant with oxy-fuel combustion .. 20
Table 4 SOx issues from compression to injection of CO2 .................................................. 21
Table 5 Mercury emission data for Rollestone coal, compared with other two Australian
coals .......................................................................................................................................... 25
Table 6 Hg and Chlorine in coal and flue gas, tested at Hitachi facility ............................. 25
Table 7 Mercury speciation data from 0.8 MWth Oxy-CFB experiment ........................... 26
Table 8 Summary of the performance for NOx control when applied to the oxy-fuel process
.................................................................................................................................................. 32
Table 9 Moisture impacts in pulverized coal combustion .................................................... 36
Table 10 USDOE/NETL Case Description ........................................................................... 47
Table 11 GCCSI Case Description....................................................................................... 51
Table 12 Summary of sulfur gas removal flowsheets ......................................................... 56
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List of Figures
Figure 1 Simplified flow sheet for oxy-fuel technology, showing in bold the additional
operations added to a standard pf plant ................................................................................... 14
Figure 2 Simplified roadmap for oxy-fuel technology deployment. ....................................... 15
Figure 3 Thermodynamic conversion of SO2 to SO3 for calculated for the flue gas of a coal
compared to the measured SO3 conversions of coals in the IHI pilot study taken at 500°C. .. 18
Figure 4 Plant locations for sulfur impacts. ............................................................................ 19
Figure 5 Interactions of mercury with other species in the oxy-fuel flue gas phase .............. 23
Figure 6 Mercury concentrations along the convective heat transfer pass way in IHI oxy-fuel
test facility for which coal ....................................................................................................... 24
Figure 7 Fraction of oxidized mercury from four coals burning at three conditions ............. 26
Figure 8 Mercury speciation data during air-firing and oxy-fuel firing from EERC ............. 27
Figure 9 Mercury control options in oxy-fuel combustion ..................................................... 27
Figure 10 The overall mechanism of NO formation and reduction ....................................... 30
Figure 11 Experimental data on NOx emissions under air-fired and oxy-fuel conditions . .... 34
Figure 12 Schematic of Callide 30MWe oxy-fuel retrofit program ....................................... 38
Figure 13 Schematic of B&W and Air Liquide’s 100MWe oxy-fuel demonstration program
for low sulfur coal .................................................................................................................. 39
Figure 14 Schematic of B&W and Air Liquide’s FutureGen 2.0 oxy-fuel commercialization
program ................................................................................................................................... 40
Figure 15 CO2 purification and compression flowsheet in the Callide Oxy-fuel Project ...... 41
Figure 16 Air Liquid’s first generation option ....................................................................... 42
Figure 17 Air Liquid’s second generation option .................................................................. 42
Figure 18 Air Liquid’s revised second generation option ...................................................... 43
Figure 19 Sour Gas Compression technology by Air Products, (a) Raw oxy-fuel CO2
compression with integrated SOx and NOx removal (b) CO2 low temperature purification
process ..................................................................................................................................... 44
Figure 20 CO2 purification and compression flowsheet in the Schwarze Pumpe oxy-fuel
pilot-plant ................................................................................................................................ 46
Figure 21 Plant efficiency ...................................................................................................... 48
Figure 22 Levelized Cost of Electricity including CO2 Transport, Storage and Monitoring . 49
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Figure 23 CO2 Mitigation Costs ............................................................................................. 50
Figure 24 Plant efficiency ...................................................................................................... 51
Figure 25 Levelized Cost of Electricity including CO2 Transport, Storage and Monitoring . 52
Figure 26 CO2 Mitigation Costs ............................................................................................. 53
Figure 27 Plant Efficiency ...................................................................................................... 54
Figure 28 Levelized Cost of Electricity including CO2 Transport, Storage and Monitoring . 55
Figure 29 Pulverized Coal Plant Costs, US Gulf Coast vs. Australia .................................... 55
Figure 30 Capital cost breakdown of oxy‐fuel technology for a low sulfur coal which
excludes CO2 transport and storage ......................................................................................... 58
Figure 31 Capital cost breakdown of oxy‐fuel technology for a high sulfur coal which
excludes CO2 transport and storage ......................................................................................... 59
Figure 32 LCOE breakdown of oxy‐fuel technology for a high sulfur coal which includes
CO2 transport and storage ........................................................................................................ 59
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EXECUTIVE SUMMARY
The coal quality impact associated with coal impurities from oxy-pf technology for CCS
differs greatly from pre- and post-combustion technologies in quality and quantity, having
higher levels of several impurities associated with the coal composition - sulfur and nitrogen
gases (SO2, SO3, NO, NO2) and mercury gases (as elemental or oxidised, Hg0 and Hg2+).
Options are available for control in the furnace, using standard technologies currently used in
air firing, and also by cleaning and treating flue gas with potentially further removal of
impurities during compression.
The report provides reported flowsheets for oxy-pf technology for the power plant and CO2
processing units (CPUs), which determine the capital and operating costs as well as
influencing the efficiency penalty of the technology. The unit operations in the power plant
flowsheet are determined by the coal sulfur levels, with different flowsheets for high (>1% S)
and low sulfur coals. Flowsheets from the gas vendors - Air Liquide, Air Products, LINDE
and Praxair – detail integrated gas cleaning and compression schemes, removing SOx, NOx
and Hg (all as liquids) as well as Ar, O2 and N2 gases during compression.
The mechanisms by which the impurities in coal determine gas quality are detailed, for coal
sulfur, for coal mercury and for NOx formed from the coal nitrogen.
Sulfur in coal is released during combustion forming species in the ash and flue gas which
have a range of impacts and control options. SO2 is the dominant species, with some H2S and
COS formed in locally reducing gas conditions of furnace gases. The concentration of SO3
formed influences corrosion of furnace metals and determines the acid dew point temperature
that must be exceeded by the furnace exit gas temperature (and thereby influences efficiency).
SO2 and SO3 control options include using an FGD in the power plant, and scrubbers prior to
compression. These are costly additions.
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The physical-chemical transformations of coal mercury determine its partitioning into its
various product species, i.e. elemental mercury, oxidized mercury and particulate matter
adsorbed mercury. The speciation of mercury is the most critical parameter determining
mercury emission and control options. Oxidized mercury is water soluble which can be
controlled by a wet scrubber and particulate mercury can be separated by particulate matter
control devices such as an ESP or FF. Hg control is required primarily due to Hg attack on
aluminum heat exchangers in CO2 compression. Industrial practice in the natural gas industry
sets a low value (<0.01 µg/m3) for the mercury concentration at the inlet to the heat
exchangers due to the explosion risk associated with failure. For CO2 purification and
compression unit, there is no risk of explosion so a more tolerant specification may be
possible.
Many laboratory and field studies indicate that chlorine in coal is an important factor in the
nature of mercury compounds formed during coal combustion, which can promote the
conversion of elemental mercury to oxidized and particulate mercury. The latter is easy to be
removed by the flue gas cleaning system, such as by a FF or FGD.
NOx is also a significant impurity in the flue gas. NOx is formed primarily from nitrogen in
the coal, but the amount is not directly related to the nitrogen content but rather to burner
design and operation. In oxy-fuel technology the recycled flue gas recycled to the burners
contains NOx, which is reburnt to N2 as it passes through the flame gases. NOx levels are
thereby reduced by 50-70% from pilot-plant experiments. Control options in a power plant
include: fuel staging, air staging, low-NOx burner, flue gas recirculation, selective catalytic
reduction (SCR) and selective non catalytic reduction (SNCR). White et al. [47] has
suggested that the catalytic deNOx systems common in some countries can be eliminated, and
even low-NOx burners were not required in oxy-fuel technology due to reduction associated
with the recycled flue gas. For the sour-gas compression process of Air Products where
mercury is removed as HgNO3, NOx actually is required in the compressed CO2.
Breakdowns of published costs from three published studies are provided to indicate impacts
of sulfur and mercury control in oxy-fuel technology these being;
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• A DOE NETL study published in 2008
• An EPRI study of Australian Electricity Generation Technology Costs commissioned
by DRET, published in 2010
• A GCCSI report published in 2011
The reports confirm the significance of sulfur control. For a high sulfur coal the requirement
of a wet FGD for sulfur gas removal from the full flue gas is associated with a plant capital
cost increase of 7.62%, similar to the CPU cost estimates.
Mercury control is of some significance. If mercury control is included as a carbon bed in the
compression system, with a capital cost of 0.27% and operation cost of 1.5%, which includes
the cost of the carbon sorbent. But a recent report indicates that there is a risk of a thermal
excursion within the bed at high pressure, so removal at atmospheric pressure will require a
larger unit, as LINDE has used at the Vattenfall pilot-plant.
The three published studies did not include selective catalytic reduction (SCR) and selective
non catalytic reduction (SNCR) for NOx control, which is associated with savings in capital
and operating costs.
The UN has initiated a process to prepare an international treaty to address the emissions to
atmosphere and use of mercury in products, wastes and international trade. The negotiations
are expected to result in a global agreement that will be signed in late 2013 leading to national
agreements to reduce emissions of mercury. In oxy-fuel, the mercury concentration in flue gas
will be controlled to prevent aluminum heat exchanger corrosion in the CO2 compression
process and this is expected to meet mercury emission levels required by a future mercury
treaty. Compared to current plant, cost differences between future air-fired plant and oxy-fuel
plant will thereby be reduced, improving the future competiveness of oxy-fuel technology.
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1. INTRODUCTION
Reduction of greenhouse gas emission from coal-fired power generation can be achieved
incrementally by efficiency improvement, switching to lower carbon fuels and by step-change
options such as CO2 capture and storage (CCS).
There are several technology options for capture and storage of CO2 from coal combustion
and gasification [1], including:
Post-combustion capture: CO2 capture from conventional pulverized coal-firing plant with
scrubbing of the flue gas by chemical solvents
Pre-combustion capture: Integrated gasification combined cycle (IGCC) with a shift reactor to
convert steam and CO to make H2 fuel, and CO2 for storage
Oxy-fuel combustion: combustion in oxygen rather than air to avoid N2 in the flue gas
Conventional pulverized fuel (pf) coal-fired boilers, i.e., currently being used in power
industry, use air for combustion in which the nitrogen from the air dilutes the CO2
concentration in the flue gas. During oxy-fuel combustion, a combination of oxygen (typically
of greater than 95% purity) and recycled flue gas is used for combustion of the fuel, as shown
in the flow sheet presented in Fig 1.
A gas consisting mainly of CO2 and water vapor is generated with a concentration of CO2 that
can be purified if required for geological sequestration. This gas contains gaseous impurities
derived from the impurities in the coal, the impurities from supplied oxygen, and air-leakage.
The recycled flue gas is used to control flame temperature and make up the volume of the
missing N2 to ensure there is enough heat transfer in the boiler. Fig. 1 details the unit
operations associated with the technology, indicating the new plant for a retrofit, being air
separation unit (ASU), CO2 gas purification and compression, and recycled flue gas (RFG) to
maintain the heat balance of the furnace and control gas temperatures. The RFG is split into
primary (~20%) and secondary gas (~80%), the primary gas usually being dried prior to
passing through the coal crushing mill. The flow sheet, first published in 2007 [1], indicates
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the possibility that the SO2 impurity may be transported and stored with the compressed CO2.
This possibility remains today.
Figure 1 Simplified flow sheet for oxy-fuel technology, showing in bold the additional operations added to a
standard pf plant [1]
The development of oxy-fuel technology for first-generation plant [2] is projected to 2025 in
Fig. 2, this technology using an ASU for oxygen supply, standard furnace designs with
externally recirculated flue gas, and limited thermal integration of the ASU and compression
plant with the conventional power plant units. The figure includes the currently announced
partial demonstrations, pilot-scale and industrial scale plant and full demonstrations with and
without CCS.
Boiler or Gas Turbine
Ash removal / cooler /
condenser / FGD
Steam Turbine
Purification / compression
Steam
Oxygen
Fuel
Power
CO2 (SO2)
CO2 –rich Flue Gas
Air Separation unit (ASU)
Air
Recycled Flue Gas (RFG)
Nitrogen
Conc. Stream of CO2
Vent
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Figure 2 Simplified roadmap for oxy-fuel technology deployment. Noted High Heating Value HHV % net basis
efficiency in black coal firing Ultra Super Critical (USC) plant can be higher in colder country [2]
In Fig. 2, gas quality is listed in two areas, as an early research issue and a regulation issue
related to the CO2 quality required by regulation for storage. The relationship of gas quality
and coal composition is the focus of the present report.
The CO2 gas quality from oxyfuel differs from pre- and post-combustion technologies, having
higher levels of inert gases, oxygen, sulfur and nitrogen oxide gases and other impurities in
the flue gas, with illustrative magnitudes given in Table 1. Thus, knowledge of the impact of
gas quality on power plant and materials, on transport systems and also gas quality
regulations for storage is required, as the cost of gas cleaning is likely to be more significant
for oxyfuel than for other carbon capture technologies. The high priority for gas quality R&D
is due to its impact on the cost and energy penalty of CCS associated with oxyfuel
technology, which is of greater relevance to its application in Australia than in most other
countries, for there is no installation for sulfur oxide or nitrogen oxide removal system at
Australian power plants.
2010 2015 2020 2025
- Partial demonstration, without CCS or power generation
- Integrated demonstration
- Integrated and CCS>1Mtpa
First generation technology Second generation
Research- Pilot-scale testing and gas cleaning
-O2 supply - Thermal integration
Regulation- Gas quality, transport and storage
PF USC efficiency target, with CCS, %HHV 40-42% >45%
Oxy
-fuel
tech
nolo
gy
deve
lopm
ent
Effi
cien
cy
mile
ston
es
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Table 1 Illustrative gas compositions, vol % or as stated, for coal-fired CCS technologies, based on [3]
Oxy-fuel combustion Post combustion capture Pre combustion capture
Gas stream Raw flue gas without CO2 cleaning CO2 product Raw flue gas without CO2 cleaning [4] CO2 product CO2 product
CO2,% 70 >99 >99 95-99
H2O,% 10 <1 <1000ppm
Total Sulfur
(SO2,H2S,COS)
600-1800 ppm for black coal
300-900 ppm for brown coal
<200 ppm 200-600 ppm for black coal
100-300 ppm for brown coal
2 ppm 3 ppm as SO2, H2S, COS
Total Nitrogen (NO, NO2,
NH3, HCN etc)
300-700 ppm for black coal
100-200 ppm for brown coal
<200 ppm 300-700 ppm for black coal
100 -200 ppm for brown coal
5 ppm 50 - 100 ppm as NH3 and HCN
Hg, ug/Nm3 0.3 – 1.0 Based on natural gas
specification, <0.01µg/m3
1-10 Uncertain Uncertain, but Hg removal common
Trace element emissions ppm – ppb level Uncertain ppm – ppb level Uncertain Uncertain
Combustibles,%
(H2,CH4,CO, etc)
0 trace 0.05-0.02
Inerts,% (N2, Ar, etc.) 15 70-80 Trace Trace
O2,% 4.5 5-10 Trace Trace
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The technology impact of the gas quality is due to:
• Uncertainty of the oxyfuel technology flow sheet, in the need for gas cleaning unit
operations
• The higher concentrations of gas impurities in the furnace and flue gas compared to air
firing (by about a factor of 3) due to oxygen firing (and removal of N2 in the oxidant)
• Uncertain future regulatory requirements of CO2 gas quality for transport and storage
• Uncertainty of the impact of impurities on CO2 recovery (% capture) and energy for
compression.
Compared to other locations, the Australian application is most sensitive as:
• Currently, flue gas cleaning for SOx and NOx is not required in some countries such as
Australia on emission grounds. The addition of such unit operations, if required for
oxyfuel technology, will involve greater cost than in countries with SOx and NOx
cleaning.
2. GAS QUALITY AND CLEANING ISSUES Table 2 lists some of the issues involved in the technology blocks, indicating that different
gases impact multiple areas.
Table 2 Listing of some gas quality and cleaning issues in oxy-fuel technology
Here, three of the coal impurities listed in Table 2 of significant impact are considered in
detail, these being sulfur, mercury and nitrogen.
Technology block Gas Impact Cleaning
1. ASU Ar Energy for ASU and CO2
compression
Increasing ASU
efficiency
2. Furnace, and standard gas
cleaning
SOx, NOx, fly ash and O2 and
N2 from air leakage
Emissions, corrosion,
impacts in CO2 compression
FGD, low-NOx burners,
catalytic NOx removal,
FF, ESP
3. Gas scrubbing with
NaOH and/or water
Gases not collected in 2 Impacts in CO2 compression Acid gases removed
(SOx, NO2) but not NO
4. CO2 compression Gases not collected in 2, and
Hg in particular
Hg is known to attack
aluminum heat exchangers
Options for NOx, SOx
and Hg removal
5. CO2 transport and storage SOx, NO2, O2, H2O Pipeline corrosion, and
regulations for CO2 storage
quality
Cleaned by 2,3,4
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3. COAL QUALITY IMPACTS– SULFUR
3.1 Coal sulfur reactions and impacts in oxy-fuel combustion
3.1.1 Sulfur species
Sulfur in coal is released during combustion forming species in the ash and flue gas which
have a range of impacts and control options [5, 6]. SO2 is the dominant species, with some
SO2, H2S and COS formed in locally reducing gas conditions of furnace gases.
The concentration of SO3 influences corrosion of furnace metals and determines the acid dew
point temperature that must be exceeded by the furnace exit gas temperature. Without SO2
removal, the furnace gases in oxy-fuel technology will be higher (typically by a factor of 3)
compared to air firing. SO3 levels will also be higher. SO3 formed from SO2 as gases cool,
with pilot-scale data on Fig. 3 indicating the SO3/SO2 conversion is from 0.5-3%.
Figure 3 Thermodynamic conversion of SO2 to SO3 for calculated for the flue gas of a coal (solid line – oxy-
fuel, dotted line- air) compared to the measured SO3 conversions of coals in the IHI pilot study taken at 500°C.
Also shown are SO2 to SO3 conversion results from the IVD Stuttgart 0.5MW facility[7]. The arrows pointing
towards the thermodynamic curve indicates temperatures at which the SO3 kinetics is “frozen”.
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3.1.2 Impacts
The sulfur species have impacts throughout operations of oxy-fuel power plant. Fig. 4
indicates the locations of the potential impacts and Table 3 elaborates the issues.
Figure 4 Plant locations for sulfur impacts. ESP is short for Electrostatic Precipitator [5] and a fabric filter (FF) can substitute the ESP for ash collection
ESP
& Sequestration SiteTransport (pipeline, truck, etc)
Deep Geological Storage
Air Separation
Unit
Coal Handling
O2
N2
Recycled Flue Gas
CO2compression
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Table 3 Sulfur impacts in pulverised coal-firing power plant with oxy-fuel combustion
[5]
Impact Reference on Fig. 4 Operation Notes Reference
Water wall corrosion 1 Furnace -High SO2 in gas due to nitrogen omission, higher H2S in sub-stoichiometric flame. -Radiative section has little SO2 pick up -Higher mass fraction of bottom ash
[6]
Ash deposition, slagging and fouling
2 Furnace and convective pass
-Increased SO2/SO3, metal sulphate and dust concentrations
[6]
Enhanced SO3 production and formation of ammonium sulfates
2 SCR -Increased SO3 concentration -Increased Ammonia consumption (cost) -Causes fouling in SCR -Precursor for particulate matter (PM2.5) emission
[8]
Ash precipability 3 ESP -Higher SO3 in fly ash improves ESP efficiency [8, 9]
Reduced Mercury Capture
3 - 4 Mercury Capture -Higher SO3 competes for adsorption sites in activated carbon capture units
[10]
CO2 recovery and energy for compression
4 CO2 compression -Isothermal compression most sensitive to SO2 -CO2 Distillation systems also sensitive to SO2
[11]
Pipeline corrosion 5 CO2 transport -Corrosive effects of SOx in high pressure/ supercritical CO2 uncertain -Thermodynamic VLE data with SO2-CO2-H2O not available.
[12]
Compliance with CO2 quality for transport to storage
6 CO2 transport -Regulations for CO2 transport in pipeline, truck or ship needs to be finalized, particularly over international borders. Experience to be drawn from acid gas injection
[13]
Compliance with CO2 quality for geological storage
7 CO2 storage -Effects of SOx with adjacent mineral matter in supercritical CO2 modelled. Experience to be drawn from acid gas injection
[14]
Sulfur is known [5] to have impacts in the furnace and power plant, during ash collection,
CO2 compression and transport as well as storage, with many options for its removal or
impact control.
• Thermodynamic calculations can predict that higher SOx levels are associated with
higher amounts of secondary sulfur species (SO3, H2S, COS) in the boiler and
convective pass and also a higher acid dew point temperature in the cooler sections
leading to an increased risk of corrosion.
• SO2 emission levels (eg, as mg/MJ) may be lower in oxy-fuel than air due to sulfur
retention in the ash.
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Sulfur is also now known to have impacts in CO2 compression, transport and storage, with
Table 4 detailing these.
Table 4 SOx issues from compression to injection of CO2
Aspects Related Issues and Comments
Compression - SO2 has a large impact on compression energy
- SO2 may be catalytically converted to H2SO4 under compression
- Gas clean-up under pressure may reduce overall sizing of equipment
- VLE data for H2O-SO2-CO2 unavailable at supercritical level
Transport - May be transported by rail, truck, ship or pipeline
- Transport type and route will affect required SOx regulations and economics
- Hydrate formation in H2O-SO2-CO2 unknown and may affect pipeline transmission or
injection
- Pipeline corrosion rate or effect of H2SO4 unknown, particularly in supercritical CO2
- Corrosion based on both SO2 and H2O concentration
Storage - H2S co-injection with CO2 is well established in acid gas injection. SO2 not well
established.
- Geophysical/chemical modelling uses SO2 dissolved in brine, rather than supercritical
CO2 as no VLE data available
- Mineral sequestration modelling of SO2 injection with CO2 shows a greatly increased
acidified zone and higher mineral porosity
Toxicological - Associated with potential leakages from underground storage
- Minimum limit for SO2 in IDLH (Immediately Dangerous to Life or Health) is
100ppm by NIOSH
- 50-100ppm SO2 considered the maximum concentration for exposures of 0.5-1 hour.
- 400-500ppm SO2 is considered dangerous for even short periods
Legislative - No current SO2 legislation for pipeline or sequestration
- Must consider the risks between pipeline corrosion, toxicological risks of leakage,
mineral reactions in sequestration and economic disincentives from over stringent
specifications
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3.2 Control of impacts of sulfur
3.2.1 Control in the power plant
Standard flue gas desulfurization (FGD) units use a calcium-based sorbent, and can treat all
the flue gas by locating it after the ash removal unit, or part of the flue gas by locating it in the
recycle loop. The option depends on the coal sulfur level.
3.2.2 Control by CO2 purification and compression
CO2 purification and compression plant may include a scrubber to remove SO2 and SO3 prior
to compression, or alternatively SO2 removal integrated with NO removal within the
compression plant. As indicated in Table 4, there are substantial impacts of sulfur gases on
compression, transport and storage, and so its removal is considered critical.
4. COAL QUALITY IMPACTS- MERCURY
4.1 Coal mercury reactions and impacts in oxy-fuel combustion
The physical-chemical transformation of mercury determines the partition of mercury into its
various species, i.e. elemental mercury, oxidized mercury and particulate matter adsorbed
mercury, and the speciation of mercury is the most critical parameter determining mercury
emission and control options. Oxidized mercury is water soluble which can be controlled by a
wet scrubber and particulate mercury can be separated by particulate matter control devices
such as an ESP or FF.
Typically, the speciation of mercury is practically determined by experiments. Another
alternative is to use predictive models derived from detailed or simplified chemistry
mechanisms. However, the complexity of a detailed chemistry mechanism can restrict the
value of predictive models. Fig. 5 indicates mercury is mainly released from fuel, and its
oxidation is affected by chlorine, steam, NOx, SOx and unburnt carbon.
- 23 -
Figure 5 Interactions of mercury with other species in the oxy-fuel flue gas phase [15] At present theoretical studies with chemistry mechanisms for oxy-fuel combustion have been
carried out such as by Leeds University [15, 16]. The detailed chemistry incorporates volatile
combustion, NOx formation, SOx formation, mercury oxidization by oxygen and chlorine.
Sensitivity study results indicate chlorine is a stronger oxidant than oxygen and that sulfur has
an inhibition effect on mercury oxidation [15]. The work at Leeds University was extended to
CFD simulation in which the mechanism scheme incorporating gas phase reaction as well as
gas-solid heterogeneous reaction is simultaneously solved with fluid flow. Mercury oxidation
on carbon in ash is initialized by adsorption of gaseous mercury onto the surface, chlorination
of the adsorbed mercury and desorption into the gas phase. By adding gas-solid reactions, the
prediction performance was improved [16].
The mitigation of the known mercury impacts on the aluminum heat exchangers in CO2
compression is achieved by reducing elemental Hg levels in the CO2 and operating heat
exchangers at temperatures below -40℃. The specified limit of < 0.01 µg/Nm3 of the natural
gas industry is due to the possibility of an explosion with a leaking heat exchanger. This level
is not considered appropriate for CO2 compression, as CO2 is an inert gas, with no explosion
risk. However, the asphyxiation effect is still a concern. A level of 1 µg/Nm3 has been
suggested, but an appropriate level has yet to be established. Table 1 suggests a level of 0.01-
0.1 µg/Nm3.
- 24 -
4.2 Mercury emissions in oxy-fuel combustion
Mercury emission data from pilot scale oxy-fuel combustion experiments have been reported
in IHI test facility [17], Hitachi test facility [18], CANMET test facility [19], EERC [20] and
other laboratory scale experimental rigs [21].
The mercury speciation has been measured along the convective heat transfer pass in the IHI
oxy-fuel test facility. The facility consists of a furnace, gas cooler and fabric filter. Four
sampling and measurement points located at the air heater inlet (450℃), air heater outlet (200℃
), bag filter inlet (170℃) and bag filter outlet (120℃). Fractions of elemental mercury,
oxidized mercury and mercury in dust have been reported for both air-firing and oxy-fuel
firing conditions, as shown in Fig. 6. Generally, as the flue gas cools, the fraction of elemental
mercury decreases accompanied by the increase in the oxidized mercury and adsorbed
mercury in dust. At the inlet of air heater, less than 20% mercury is in the oxidized form. But
at the outlet of bag filter, most of mercury is in the oxidized form. There is no significant
difference on mercury transformation between air-firing and oxy-fuel firing. Additionally, the
mercury adsorbed in dust (about 10%) formed in oxy-fuel flue gas is completely captured by
the bag filter. The oxidized mercury is expected to be captured by any scrubber common in
oxyfuel technology due to its high water solubility.
Figure 6 Mercury concentrations along the convective heat transfer pass way in IHI oxy-fuel test facility for which coal [17] Australian coals usually contain less mercury compared with overseas coals, the typical mean
mercury concentration in the Australian coals being 0.04 ppm. Thus the mercury emissions
from burning Australian coals are also expected to be lower than from overseas coals. Three
Australian coals were tested in the IHI pilot scale oxy-fuel plant. The mercury emission data
in the flue gas is measured at the exit of fabric filter. The three coals tested are coals A, B and
- 25 -
C. coal A and coal C do not show great differences between oxy-fuel combustion and air-
firing. Coal B which is of high chlorine content shows greatest mercury reduction in
concentration in oxy-fuel combustion. As the flow rate of flue gas from oxy-fuel combustion
is about one third of that in air-firing, thus the mercury emission rate reported as (µg/MJ) in
oxy-fuel is reduced by more than 80% compared with air-firing. From Table 5, it is seen that
the mercury emission from burning coal C is the lowest among the three coals tested and
much lower than average level reported in Australian power plants.
Table 5 Mercury emission data for coal C, compared with other two Australian coals Coal Air-firing (µg/m3) Oxy-fuel firing (µg/m3)
A 0.87 1.03
A’ 0.271 0.276
B 1.84 0.25
B’ 1.47 0.185
C 0.263 0.161
In a 4 MWth Hitachi test facility, air-firing and oxy-fuel firing were tested and mercury
emission data is presented in Table 6. It reported 4, 34, and 10 µg/m3 mercury emission in air
combustion compared to 7, 70 and 22 µg/m3 in oxy-fuel firing respectively for three coals.
The sampling and measurement point is at the inlet to SCR. In another presentation given by
Hitachi, it was found that elemental mercury is oxidized in SCR to form mercury chloride,
which later is captured at dry ESP, wet ESP or Hg absorber prior to CPU. The amount of HCl
in the flue gas is in access to oxidize mercury. Most of the mercury is captured in a wet ESP,
with efficiency ranging from 77-92%.
Table 6 Hg and Chlorine in coal and flue gas, tested at Hitachi facility [18] Coal A Coal B Coal C
Hg, ppb, daf 55 381 132
Cl, ppm, daf 384 787 435
Hg, µg/m3,dry 4/(7) 34/(70) 10/(22)
HCl,ppm,dry 26/(54) 35/(98) 26/(83)
*Noted the numbers in ( ) are data from oxy-fuel combustion
CANMET carried out oxy-firing in a 0.8 MWth CFB boiler. A petroleum coke and a
bituminous coal have been tested at two riser temperatures. The speciation of mercury has
been reported, as shown in Table 7. The high conversion ratio of elemental to oxidized
mercury (around 80%) has been found for the bituminous coal, while the conversion ratio is
about 40% for the petroleum coke.
- 26 -
Table 7 Mercury speciation data from 0.8 MWth Oxy-CFB experiment [19] Pet coke 1 Pet coke 2 Coal 1 Coal 2
LHV, MJ/kg 32.46 25.28
Riser Temperature (℃) 850 950 850 920
Hg0, % 54.9 58.6 21.6 20.3
Hg2+, % 45.1 41.4 78.4 79.7
Mercury is regulated in China with 30 ug/m3 as the emission limit for Chinese coal fired
power plant. The mercury control strategy is based on the multiple pollutant control principle,
which is to co-capture mercury with the installed FGD (for sulfur removal), SCR (for NOx
removal) and ESP/FF (for particle removal). Four coals have been studied in air-firing, 21%
O2/ 79% N2, and 29% O2/ 71% CO2. Speciation data has been reported. Generally 20-35%
oxidized mercury formed and does not depend on the chlorine and sulfur content in coal, as
shown in Fig. 7[21].
Figure 7 Fraction of oxidized mercury from four coals burning at three conditions [21]
At the EERC, the US EPA Method 29 was used to collect samples from inlet and outlet of the
ESP and the scrubber outlet. EPA Method 30B was also used. Result indicates that with the
high sulfur coal used, 97% of mercury exists in the gas phase thus no capture across the ESP.
But with 40-50% capture happens at the scrubber because of around 50% gaseous mercury
was in the soluble oxidized form. During oxy-fuel combustion, mercury concentrations at the
ESP inlet were around 20 µg/Nm3 almost double compared to air-firing test. And the
oxidation extent in oxy-fuel combustion is higher than air-firing as shown in Fig. 8. Thus
higher reduction in mercury emission is achieved in oxy-fuel mode. Results also indicate the
mercury reactions were frozen inside the wet scrubber.
- 27 -
Figure 8 Mercury speciation data during air-firing and oxy-fuel firing from EERC [20]
4.3 Control of impacts of mercury
The mercury level in the flue gas requires control from both environmental emission
consideration and the safety issue caused by mercury attack to aluminum used in the cold box
in the CPU. Mercury can be controlled either in the environmental emission control devices
commonly met by combustion engineer or in the CO2 purification unit as shown in Fig. 9.
Figure 9 Mercury control options in oxy-fuel combustion
In a conventional air-firing power plant, co-capture mercury is a technology option in which
mercury is captured by particulate control units such as ESP or FF, sulfur control units either
dry or wet system, and the SCR unit which oxidizes mercury to enhance the mercury capture.
As Australian power plants have not installed environmental emission devices except for
particulate matter, thus only particulate mercury is expected to be captured.
- 28 -
Another option is injection technologies such as activated carbon injection (ACI) to capture
mercury onto particles which subsequently are captured by either ESP or FF.
In an oxy-fuel process, a gas purification unit is added at the back of the conventional boiler
system. Alternative mercury control options in oxy-fuel flue gas are as proposed by industrial
gases companies such as Air Liquide [22, 23], and Praxair [24] who provide technology
solutions to remove mercury at gas processing unit with an activated carbon bed. In the Air
Liquide process, mercury is under consideration for (Brazed Aluminum Heat Exchangers)
BAHX design to mitigate Hg induced corrosion risks. [23] It is claimed that the CO2 CPU
manages Hg more efficiently than flue gas capture technology by using either a guard bed or
Hg tolerant components. [22]
The process developed by Praxair uses a sequence of a flue gas cooler/condenser, a
compressor, a H2O contactor, a dryer, a carbon bed (for mercury removal), a cold box and an
expander to purify the oxy-fuel flue gas. Additional VPSA can be used to recover CO2 from
cold box, Catox is used to catalytically oxidize carbon monoxide, and an Activated Carbon
process is applied to removal SOx and NOx. The test results for SOx and NOx have been
presented and it suggested the fate of mercury requires further research. [24]
Hg control is therefore required primarily due to attack of aluminum heat exchangers in CO2
compression. Industrial practice in the natural gas industry sets an extremely low value (<0.01
µg/m3) for the mercury concentration at the inlet to the heat exchangers due to the explosion
risk associated with failure. For CO2 purification and compression unit, there is no risk of
explosion so a more tolerant specification may be possible.
4.4 Significance of a future international treaty on mercury emissions to atmosphere
In June 2011, the UN initiated a process to prepare an international treaty to address the
emissions to atmosphere and use of mercury in products, wastes and international trade. The
negotiations are expected to result in a global agreement that will be signed in late 2013
leading to national agreements to reduce emissions of mercury. According to a UNEP report
[25], the largest source is the combustion of fossil fuels, largely coal, which accounts for 46%
of total emissions to atmosphere, about 25% being from power stations. In Australia, coal
combustion contributes to 14.8% of anthropogenic emissions which is in the second largest
source. [26, 27]
- 29 -
Any existing air pollution control devices (APCDs) in a power station do capture particular
mercury species in flue gas. For example, ESPs and FFs collect particulate mercury, ESPs
retain oxidised mercury. Capture in APCDs therefore removes a fraction of the mercury, but
the mercury treaty is expected to require higher mercury removal levels and additional plant
or methods such as activated carbon injection (ACI), chemical additives and oxidation
catalysts etc. Adopting these methods will increase capital and operating cost and the
levelized cost of electricity (LCOE).
In oxy-fuel, the mercury concentration in flue gas will be controlled to prevent aluminum heat
exchanger corrosion in the CO2 compression process and this is expected to meet mercury
emission levels required by a future mercury treaty. Compared to current plant, cost
differences between future air-fired plant and oxy-fuel plant will thereby be reduced,
improving the future competiveness of oxy-fuel technology.
5. COAL QUALITY IMPACTS– NITROGEN
5.1 Coal nitrogen reactions and impacts in oxy-fuel combustion
5.1.1 Nitrogen species
NOx is also a signifigant impurity in the flue gas. NOx is formed primarily from nitrogen in
the coal, but the amount is not directly related to the nitrogen content but rather to burner
design and operation. NO is the dominant species, accounting for 95%, and NO2, accounting
for 5%. N2O is normally generated in the process of low combustion temperature such as
fluidized bed combustion. Its emission and mechanism have been studied extensively,
resulting in a large amount of literature [28-33].
It is well accepted that NOx is generated through three ways: thermal NOx, prompt NOx and
fuel-NOx. Thermal NOx refers to NOx formed with reactions between N2 and O2. Its
formation is dominated by the combustion temperature which is effective above 1400℃.
Prompt NOx refers to the reaction between N2 and hydrocarbon radicals such as CHi. Prompt-
NOx usually accounts for a very small part of overall NOx emissions from coal combustion
under typical operating conditions. Fuel-NOx comes from nitrogen species bound in fuel. In
pulverized coal devolatilization, fuel-N is divided into volatile-N and char-N. During
combustion process, the volatile-N transforms into either NO and N2, while char-N goes
through the heterogeneous reactions along with the char oxidation. The overall mechanism of
- 30 -
NO and NO2 formation is shown in Fig. 10 [33]. In conventional coal combustion, fuel-N is
the dominant source for NO production with the thermal-N as a minor contributor. In oxy-
coal combustion, N2 is substitute by the recycled flue gas which the main component is CO2
and H2O. So the NO is only formed by fuel-N in theory. Although the oxy-combustion PF
boiler has good furnace seal, air entrainment in the burners and milling system may give rise
to increased NOx emission due to thermal-N formation.
Figure 10 The overall mechanism of NO formation and reduction [33]
5.1.2 Impacts
As the characteristics of the nitrogen species in the flue gas, NO is the dominant proportion,
while NO is an inert and low solubility gas which has no impact on the furnace and gas
cleaning equipments, such as ESP and FGD. NO2 is an acid gas which forms HNO3 by
reacting with H2O, and corrosion may also occur during its passing through the convective
section because the flue gas may be cooled below the acid dew point. Although the oxy-fuel
combustion takes place in a low-nitrogen environment, the concentration of NOx in the flue
gas is higher than air combustion because of the reduction of nitrogen. Wilhelm and others
[34] studied the formation of NO2 in oxy-fuel combustion and found that the fraction of NO2
formation from the total NOx production was higher in the oxy-fuel experimental tests than in
the air comparison cases. The experimental data showed that the NO2 percentage increased
from 6.75% (in air) to 27.9% (in oxy-fuel) [34]. The relevant studies of higher concentration
NO2 in the flue gas and its corrosion problem are seldom, it is also noticeable in the designing
of oxy-fuel power station.
On the other hand, NO and NO2 will affect on the formation of Hg2+. NO can promote or
inhibit homogeneous Hg oxidation, depending on its concentration. According to Niksa’s test
result [35], at the lowest NO concentrations, NO promotes Hg oxidation, but the maximum
- 31 -
extent of oxidation is reached with only 20 ppm NO. At higher NO levels, it inhibits Hg
oxidation to the extent that there would be no Hg oxidation for NO concentrations above 100
ppm. With low concentration of HCl or Cl2, the slight Hg oxidation could occur by NO2.
The most important impact of NOx is on the CO2 compression, transport and storage process.
In a conventional power plant, SOx is removed by FGD unit and NOx is removed by SCR
unit. In the oxy-fuel process, since the CO2 has to be condensed for cost-effective
transportation and storage, it is possible to remove SOx and NOx in the compression process.
Air product, Air Liquid and Linde et al. proposed different technological methods，the basic
principle is Lead-chamber reaction which is performed at high pressure between 15bar and
30bar，the main reactions are:
NO +1/2O2→NO2 (1)
NO2+SO2→NO+SO3 (2)
SO3+H2O→H2SO4 (3)
2NO2+H2O→HNO2+HNO3 (4)
3HNO2→HNO3+2NO+H2O (5)
Under this reaction scheme, NO is oxidised to NO2 which oxidises SO2 to SO3. NO acts as a
catalyst for SO2 oxidation, after all of SO2 is converted to H2SO4, the flue gas will be
compressed to about 30bar, at which NO will be converted to NO2 and then into nitric acid
with moisture. This process also has potential to remove mercury by reaction with HNO3. The
bench scale and pilot scale experiment result show that [36-38] the SO2 and NOx conversion
ratio is more than 90% and affected by the pressure, residence time and SO2/NOx ratio. SO2
conversion decreased as SO2/NOx ratio increased, which indicate that NOx act as a catalyst
for SO2 oxidation to SO3 and NOx concentration in the flue gas would influence the
impurities removal during CO2 compression.
NOx in the CO2 stream have the potential to affect the efficiency and safety of transport and
storage systems, for example through increased risks associated with corrosion of pipeline
and well materials, or changes in the phase behaviour of the CO2 stream [39].
NOx can catalyze the oxidation of SO2 to form sulfuric acid, which lowers the pH and may
then cause mineral dissolution and precipitation of sulphates and it could potentially affect the
CO2 capacity and injectivity. Potential chemical effects on caprock integrity over the long
term are dissolution of both carbonate and aluminosilicate rocks, due to the presence of NOx
which can form nitric acid. However, when NOx concentration in the CO2 stream are less
- 32 -
than 200 ppm, the impact on the dissolution of the rocks is likely to be insignificant [39]. As
acid gas, NOx may affect the well materials after injection. The effect of acid impurities on
dissolution of cement constituents may be more significant on dissolution of rocks. If
protection from cement sheaths is lost, the steal casing could also be attacked.
5.2 Control of impacts of nitrogen
The fate of NOx in coal combustion is well known with Normann et al [32] summarising
NOx control in oxy-fuel combustion. Such a summary is shown in Table 8, and the NOx
control is split into primary measures and secondary measures. Primary measure aim at
adjusting the combustion parameters in order to reduce the NOx formed inside the furnace.
Secondary measures aim at capturing the NOx in the flue gas cleaning and CO2 purification
process. In this work, NOx control is divided into control in the power plant and control by
CO2 purification and compression.
Table 8 Summary of the performance for NOx control when applied to the oxy-fuel
process [32] Advantages Disadvantages Achievable reduction
Primary measures
Reburing Conventional technology (Natural gas consumption)
High temperature corrosion
60% a
Air staging Conventional technology Reduced combustion efficiency
High temperature corrosion
40% a
Low-NOx burner Conventional technology Reduced combustion efficiency
High temperature corrosion
60% a
Flue gas recirculation Induced in the oxy-fuel process 65% b
Secondary measures
Absorption Simultaneous removal SOx
Placed in high-pressure part
Extra unit
Waste (weak nitric acid)
90% c
Co-storage Included in the oxy-fuel process Pollution of the CO2 95% c
Distillation Simultaneous removal SOx
Placed in high-pressure part
Power consumption
Extra units
Waste (liquid NOx)
95% c
a Based on practical experience under air-fired conditions b Based on practical experience under oxy-fuel conditions c Based on modeling of the oxy-fuel process
5.2.1 Control in the power plant
NOx control options in the power plant include: fuel staging, air staging, low-NOx burner,
flue gas recirculation, selective catalytic reduction (SCR) and selective non catalytic reduction
(SNCR).
- 33 -
Fuel staging [40] aims at reducing the NOx already formed back to nitrogen during
combustion. Combustion can be divided into three zones, including primary zone, reburning
zone and burnout zone. Primary zone is the main combustion zone burning in an oxidizing
atmosphere. In the secondary zone, the fuel is injected into a sub-stoichiometric atmosphere
yielding hydrocarbon radicals which react with NO produced in the primary zone to formed
N2 and unwanted volatile nitrogen. Combustion is then completed in the burnout zone by the
final air.
Air staging [40] in the furnace is often called a two-stage combustion process. Its principle is
primarily to reduce NOx formation through reducing the supply of O2 in the primary
combustion zone, less NOx is formed from the fuel-N. At the same time, the peak temperature
of combustion is decreased because of the reduced atmosphere. In the secondary zone the
additional air is injected into the furnace to complete the combustion.
Low-NOx burners [40]are the common combustion devices for coal. Most of boiler and
burner manufacturers have developed low NOx burners for retrofit and new installations. The
burner is divided into NOx reducing zone and oxidizing zone through optimizing
configuration oxidizer. By staging the addition of air, the coal is devolatilised under
conditions of low stoichiometry, promoting the conversion of fuel-N to N2, and finally
realizing the purpose of NOx reduction.
Flue gas recirculation [40] aims at reducing the amount of available air through dilution and
to reduce the flame temperature. The success of reducing NOx through flue gas recirculation
depends on combustion conditions. In most coal-fired power plant the result is minimal. On
the contrary, this method is more suitable for oil and gas-fired boiler.
The above methods are also called combustion measures which are widely used in
conventional coal-fired power plant. In oxy-fuel combustion, the elevated CO2 concentration
also increases the formation of OH radical through reaction (6).
CO2+H→CO+OH (6)
The results by Park et al. [41] show that elevated CO2 concentration can suppress the reburing
mechanism. Staged combustion has been investigated by Maier et al. [42, 43] and Liu et al.
[44] in an O2/CO2 condition. The results show that like in an air combustion case, emission is
dependent on coal rank and combustion conditions. Oxidant staging for NOx reduction is
- 34 -
even more effective for oxy-coal combustion. As the same principle between the low NOx
burner and air staging, in order to reach the maximum NOx reduction in oxy-fuel combustion,
it is important to have a burner specifically designed for oxy-fuel combustion. This specific
design should take advantage of the use of O2 to maximize the NOx reduction potential
offered by oxy-fuel combustion [45]. Although the oxy-fuel combustion takes place in a low-
nitrogen environment, the molar concentration of NOx (ppm) in the flue gas is higher than air
combustion because of the recycle flue gas. However, the exit volume flow rate of flue gas is
reduced in oxy-fuel combustion. Thus the comparison of emission in molar concentration
(ppm) is inadequate. An expression considering the difference in energy input is required.
Emission rate (mg/MJ), which is defined as the mass of pollutant emitted per energy input is a
neutral way of expressing pollutant emission. The recently results of the experimental data on
NOx emissions under air and oxy-fuel combustions were summarized in Fig. 11 [32]. It was
concluded by the researchers [46-48] that a high concentration of NO in the recycling flue gas
could increase the reduction rate of NO in the flame and thus lead to a further reduction of the
emission rate.
Figure 11 Experimental data on NOx emissions under air-fired and oxy-fuel conditions
(maximum reduction achieved). Full line: NOx emission during oxy-fuel combustion is 34% of the
emission during air firing. The dashed line denotes equal emission [32].
SCR and SNCR are also called flue gas treatment technologies [40]. In the SCR method,
ammonia (NH3) is injected into the flue gases in the presence of a catalytic to reduce NO and
NO2 to N2 and H2O. The catalyst can be placed in different position in the flue gas flow path.
The flue gas temperature is an important factor to determine the type of catalyst used. The
- 35 -
position for the catalyst can be high dust, where the equipment is placed between the
economizer and the air preheater, the catalyst situated after ESP (or FF) and before the air
preheater.
The principle of SNCR is that NOx can be controlled through thermal reaction by using
appropriate reducing chemical. The reaction usually occurs at temperatures of 900-
1100℃.Ammonia and urea are generally used as the reducing chemicals. In comparison with
SCR, SNCR is a cost saving method because of no expensive catalyst required. But the NOx
achievable reduction of SNCR is much lower than SCR.
In oxy-fuel combustion, high concentration of SO2 is in the flue gas which could be oxidized
into SO3 in the SCR. SO3 in the flue gas is known to form sticky and corrosive ammonium
bisulphate when NH3 is added, which will severe clog the catalyst. To prevent (NH4)2SO4
formation, SCR should be placed after the FGD where the flue gas is cooled and must be re-
heated before entering the SCR, and this would decrease the power station efficiency. The
SCR unit is also capital intensive. In the oxy-fuel combustion, since the flue gas has to be
compressed, it is possible to remove NOx at high pressure and reduce capital and operating
cost [49].
White et al. [50] suggested that the deNOx system should be eliminated and even low-NOx
burners were not required in oxy-fuel technology. For the sour-gas compression process of
Air Products where mercury is removed as HgNO3, NOx actually is required in the
compressed CO2. This process remains to be demonstrated.
5.2.2 Control by CO2 purification and compression
CO2 purification and compression is one of the necessary components in oxy-fuel combustion
power plant. The oxidation rate of NO to NO2 by the O2 present in the flue gas is favoured by
low temperature and high pressure. NO2 is a soluble gas which is easy to react with NaOH in
the solution. According to the Lead-chamber reaction, NO also act as a catalyst for SO2
converting into H2SO4. It will be an innovative reducing NOx measure which is not feasible
in air-fired plants. In CO2 compression, the main reactions of reducing NOx are the equations
(1), (4) and (5). According to published results [36-38], in the absence of SO2, the conversion
of NO is up to 90% at 30 bar. In the existence of SO2, the main reactions are equations (2) and
(3), and NO is converted into HNO3 in water in a separate absorption column downstream the
absorption of SO2. The generated NO2 and HNO3, are sent to the gas scrubber to be removed
- 36 -
by reacting with NaOH solution. On the other hand, NO2 absorbed in the water in the high
pressure scrubber reacts with Hg0 to form HgNO3 which can remove both NO2 and Hg0
simultaneously. The relevant bench scale and pilot scale experiments are ongoing [51-55]. In
the CO2 purification process, NO2 can be efficient reduction through the distillation method.
6. COAL QUALITY IMPACTS– OTHER SPECIES
The moisture content of coal varies widely depending on their rank, ranging from below 5%
for anthracite to about 40% for low-rank sub-bituminous coal and lignite. In oxy-fuel power
plant, under the warm-recycle condition, the flue gas moisture is not removed from the
secondary oxidant stream, and the overall moisture content inside the boiler under steady-
state operating condition could reach 35% [56]. Moisture may have significantly impact on
boiler system and CO2 capture. Table 9 shows the potential impacts of moisture in pulverized
coal combustion.
Table 9 Moisture impacts in pulverized coal combustion Impact Operation Notes Reference
The dynamical behavior of the power
plants
Coal handling -High moisture in coal resulting in
changed dynamics of the coal mill,
and accumulation of coal in the
coal mill.
[57]
-Ignition and combustion rate
-Flame temperature
-Unburned carbon fraction
Furnace -High partial pressure of H2O
results in an increased gas
emissivity compared to air firing;
-Delay coal ignition
-Decrease coal combustion rate
-Decrease the flame temperature,
increase the unburned carbon
fraction
[58-60]
Raise the acid dew point Convection pass -lead to low temperature corrosion
and ash clogging of back-end
surface
[61, 62]
Reduced Mercury Capture Mercury capture -Inhibits Hg oxidation by chlorine
(Cl2).
[63]
Impact to the compressor CO2 compression -Formation solid “ice-like”
hydrates with compressed CO2,
causing blockages
[39]
- 37 -
-Pipeline Corrosion
-Affect pipeline transmission or injection
CO2 transport -Moisture react with acid gas (SO2
and NO2) to form sulfuric and
nitric acid
- Hydrate formation
[39, 64]
Corrosion Caprocks and Well materials CO2 storage -Moisture react with acid gas (SO2
and NO2) to form sulfuric and
nitric acid
[39]
Chlorine is a trace elements in coal, which is regarded as being totally volatile following coal
heating. Most researchers are of the opinion that most of chlorine is emitted as HCl (>90%)
during coal combustion [65]. HCl is considered an air pollutant. However, in the atmosphere,
HCl is fairly short-lived (one to five days) since it is very soluble and reacts readily with
ammonia (NH3) or alkaline cations such as Ca or K to form chloride salts. Therefore, even
though the mass of HCl emitted may be substantial, the actual impacts of these emissions may
not be significant. HCl in the flue gas will lead to low temperature corrosion when it passes
through the convective heating surface. Finally, HCl can be effectively removed (>90%) by
the conventional flue gas desulfurization (FGD) systems [66].
On the other hand, chlorine has a positive impact. As mentioned above, mercury will
influence the safe operation of CO2 purification process in oxy-fuel power plant. Many
laboratory and field studies indicate that [67-70] chlorine is an important factor in the nature
of mercury compounds formed during coal combustion, which can promote the conversion of
elemental mercury to oxidized and particulate mercury. The latter is easy to be removed by
the flue gas cleaning system, such as by a FF or FGD.
7. PUBLISHED FLOWSHEETS
7.1 Published flow-sheets for front-end (combustion)
7.1.1 Callide oxy-fuel Project (COP)
The Callide oxy-fuel project is the first power plant evaluating the retrofit option which is
unique from other oxy-fuel demonstration projects in the world. Its flow sheet is shown in
Fig. 12. As there is no SO2 and NOx removal system in Australian power plants, it can be
seen that it has no specific units for this in the retrofit flow sheet. This flow-sheet is suitable
for low sulfur coal( <0.5%).
- 38 -
Figure 12 Schematic of Callide 30MWe oxy-fuel retrofit program [71]
For the Callide oxy-firing retrofit, the main boiler plant remains un-modified [71]. In order to
deal with changes in flue gas flow and temperature, the gas cooler is proposed to cool the gas
to the normal 150℃ outlet temperature to avoid high temperature for the fabric filter. The ID
fans and FD fans are modified or replaced since adding the gas cooler will increase the draft
head of the fans and handle recirculation gases of about 150℃. The recycled flue gas is
divided into a primary gas stream for the pulverizing mills and a secondary gas stream to the
windbox of the boiler. Because the moisture content of the recycle flue gas is higher than
under air firing conditions, the primary gas stream must be dewatered and reheated to ensure
it remains above saturation temperature. Although the COP has not included the mercury
removal unit from flue gas, Air Liquide [23] has proposed a method using brazed aluminum
heat exchangers (BAHX) for mitigating Hg corrosion risks.
7.1.2 Babcock and Wilcox flowsheet for low sulfur (<1%) coal
Fig. 13 shows the process schematic of B&W and Air Liquide’s 100MWe oxy-fuel
demonstration program. Following the recycle heater, the flue gas is split into the secondary
recycle, the primary recycle and CPU. Due to the low sulfur (0.85 wt. %) level in the coal, it
employs the warm-recycle configuration in the secondary gas stream and the cold-recycle
configuration in the primary gas stream. The secondary recycle temperature is decreased
before passing through a fabric filter (FF) and forced draft fan which returns the flow to the
recycle heater for reheating and then to the windbox. The flue gas desulfurization system
includes both a spray dryer absorber (SDA) and a polishing sodium-based wet scrubber to
reduce emission of SO2 to very low levels entering the CPU. The small amount of remaining
SO2 (<1 ppmv) that enters the CPU is condensed. In addition to the significant NOx reduction
- 39 -
produced by oxy-combustion, the combustion system design incorporates provisions to
reduce NOx formation in the burner zone. NOx produced in the process passes into the CPU
where it is removed during the compression process with a very small amount remaining in
the non-condensable gaseous vent stream to atmosphere. Mercury is removed in both the
SDA-FF and the polishing scrubber prior to entering the CPU. The remainder is removed
within the CPU process. Particulate is removed from both the secondary and main flue gas
streams by high efficiency fabric filter. The very small amount remaining is further reduced
within the CPU process.
Figure 13 Schematic of B&W and Air Liquide’s 100MWe oxy-fuel demonstration program for low sulfur coal [72] Since there is no SO2 or moisture removal in the secondary recycle steam, the moisture and
SO2 levels in the boiler are higher with warm recycle. The higher SO2 levels resulting from
oxy-combustion of the low sulfur coal are about the same as experienced in an air-fired boiler
burning a moderate sulfur content bituminous coal [72]. By returning warmer recycle gas to
the boiler and using some of the heat in the steam cycle, the plant heat rate is improved.
7.1.3 Babcock and Wilcox FutureGen 2.0 flowsheet for high sulfur (>1%) coal
Fig. 14 shows the process schematic of B&W and Air Liquide’s FutureGen 2.0 oxy-fuel
commercialization program. As a commercial plant design, due to the high sulfur (3.2 wt. %)
level in the coal, it employs the cold recycle configuration rather than the warm recycle
process for low sulfur coal. A wet flue gas desulfurization scrubber was selected to keep the
SO2 and HCl concentrations in the boiler about the same as they would be with air firing and
to minimize corrosion risk. Dry sorbent injection is also utilized upstream of the pulse jet
- 40 -
fabric filter (PJFF) to control SO3 [73]. Following the wet scrubber, the secondary flue gas is
reheated slightly to avoid condensation in the flues and forced draft fan and returned to the
recycled heater.
Figure 14 Schematic of B&W and Air Liquide’s FutureGen 2.0 oxy-fuel commercialization program [73] The remaining flue gas is conveyed through a direct contact cooler/polishing scrubber
(DCCPS). The primary function of DCCPS is to remove moisture from the flue gas, but it
also further reduces SO2. After slightly reheating the flue gas leaving the DCCPS, about half
of the flow goes to the CPU for CO2 purification and storage, and the remainder is sent to the
primary fans. After being heated in the recycle heater it becomes the coal drying and
conveying medium in the pulveriser.
7.2 Published flow-sheets for back-end (compression)
7.2.1 Air Liquide (AL) design for the Callide Oxyfuel Project and other AL options
reported
The flowsheet for the Callide oxy-fuel project gas cleaning and compression plant is given in
Fig. 15. As there is no installation for sulfur removal system, the flue gas is first fed into a
direct cooling and polishing scrubber to remove SO2. The Air Liquide scrubber design [27]
will act as both a direct cooler and capture unit which play a similar capacity to the FGC.
Both units use aqueous NaOH as a capture material and operate at atmospheric pressure.
After dust cleaning, the gas stream is compressed by a four-stage CO2 compression to 22 bar.
The compressed gas stream is cooled through the inter-cooler after each compression stages.
Part of NO in the stream is reacted with O2 to transfer into NO2. The moisture contained in
the CO2 stream is condensed and reacted with NO2 to form HNO2 or HNO3. The waste is
- 41 -
transported to the ash pit. After compression, the CO2 stream is chilled by the cold scrubber
and then sent to the dehydration unit to further remove the moisture by the activated alumina
adsorbent. After de-hydration, the dried CO2 mixture is liquefied and then purified through a
cold box, in which the liquid CO2 and the non-condensable gases are separated. The purified
liquid CO2 is transported by two trucks per day to the storage site. Mercury removal which
used activated carbon in the conceptual design has been deleted due to concerns about the
spontaneous combustion possibility of the bed under pressurised operation.
Figure 15 CO2 purification and compression flowsheet in the Callide Oxy-fuel Project [23] The Air Liquide design for the COP is a hybrid based on reported flowsheets by Tranier [74]
at OCC1, these flowsheets, given on Fig. 16, Fig.17 and Fig.18, are based on the following:
• A first generation flowsheet, having a sodium scrubber and NO2 removal from
compression, with undefined use or disposal.
- 42 -
Figure 16 Air Liquid’s first generation option [74]
• A second generation option with NO2 and SO2 disposal with CO2, an option requiring
regulations allowing this.
Figure 17 Air Liquid’s second generation option [74]
• A revised second generation option with NO2, HNO2 and HNO3 recycled from the
compression plant to the atmospheric pressure scrubber for removal as HNO3 together
with H2SO4.
- 43 -
Figure 18 Air Liquid’s revised second generation option [74] The COP compression design includes the NO2 recycle from the compression plant of the
second generation option to the atmospheric pressure scrubber, but with the NO2, HNO3 and
HNO2 following earlier compression going to the ash pit (i.e. waste).
7.2.2 Air Products sour gas compression
The possibility of simultaneously removing SOx, NOx and mercury during compression has
been developed by Air Products as their ‘‘Sour Gas Compression’’ technology [36, 75],
shown in Fig. 19. In this process, two scrubbers and one adsorption bed are operated at
elevated pressure (15 and 30 bar) and are designed on the basis of creating higher surface area
and residence time for gases to dissolve. The technology uses the oxidation of NO to NO2 to
convert SO2 to H2SO4 in the presence of H2O in the Lead Chamber process. A consequence of
this catalytic oxidation process is that nitrates will not be captured in the aqueous phase until
the SOx is exhausted in the gas phase. This process is unique in that the mercury will dissolve
in the nitric acid formed as a condensate and hence is directly linked to the capture of NOx
and SOx.
- 44 -
(a)
(b)
Figure 19 Sour Gas Compression technology by Air Products, (a) Raw oxy-fuel CO2 compression with integrated SOx and NOx removal (b) CO2 low temperature purification process [75] To allow removal of SO2, NO and NO2 from the process, a longer residence time and contact
with water is needed after compression of the raw CO2 as shown in Fig. 19(a). After adiabatic
compression to 15 bars the CO2 is cooled by preheating boiler feed water (BFW) and
condensate. At this point holdup is added to the process by use of a contacting column with
pumped around liquid condensate. A holdup of only a few seconds is necessary to allow time
for all of the SO2 to be removed as H2SO4. The contactors allow mixing of water with SO3
and then with NO2 to remove these components from the gas continuously thus allowing
reactions to proceed until all the SO2 and the bulk of the NO is removed. Little HNO2 or
- 45 -
HNO3 will be formed until all of the SO2 has been consumed. The SO2-lean CO2 is then
compressed to 30 bar where a similar process as at 15 bar adds another few seconds of holdup
to the process. Around 90% of the NOx and all of the SO2 can be removed in this way from
the CO2 before the inert removal. The impure 30 bar CO2 is then dried in a dual-bed thermally
regenerated desiccant drier. Oxygen, nitrogen and argon are removed from CO2 by low
temperature processing shown in Fig. 19(b).
7.2.3 LINDE process at the Schwarze Pumpe oxy-fuel pilot-plant
Vattenfall’s 30MWe pilot oxy-fuel project is the only coal-fired full chain oxy-fuel
demonstration currently operating, and has adopted a related gas conditioning process
designed by LINDE to remove SOx, NOx, water and mercury from flue gas. The product CO2
quality is 99.7%. The CO2 compression/purification system is located downstream the flue
gas cleaning processes (i.e. ESP, wet limestone FGD and flue gas condensation). A simplified
process flow diagram of the CO2 compression/purification is shown in Fig. 20. After the
upstream cleaning, the flue gas is fed into a separator, then further compressed by the fan to
around 1.25 bar in order to pass through an activated carbon filter to remove mercury. It
would appear that this option for mercury removal at low pressure was selected to avoid the
possibility of spontaneous combustion for a carbon bed operating at higher pressure. After
filtration, the gas stream is compressed by a two-stage CO2 compression to about 22 bar. The
compressors are of screw type and sealed and internally cooled through injection of water.
The compressed gas stream is cooled through the inter-coolers after each compression stages.
The moisture contained in the CO2 stream is condensed through the compression and inter-
cooling, then is removed as condensate in the separators. After the two-stage compression, the
CO2 stream is sent to the de-hydration unit to further remove the moisture below dew point.
After the de-hydration, the dried CO2 mixture is liquefied and then purified through a low
temperature rectification column, in which the liquid CO2 and the non-condensable gases are
separated. The purified liquid CO2 is the desired product for CO2 transport, and the vent gas
(containing mainly non-condensable gases and certain percentage of CO2) is sent to
atmosphere [76].
- 46 -
Figure 20 CO2 purification and compression flowsheet in the Schwarze Pumpe oxy-fuel pilot-plant [76] In order to get a low content of inert gases and impurities a process with rectification column
is installed. Additionally a recycle compressor and a refrigeration unit have to be installed.
Part of the rectification column is a reboiler at the bottom of the column. The liquid in the
bottom of the column will be constantly boiled. Inert gases like oxygen accumulate in the
ascending vapour, in the downstream liquid the purity of the CO2 will increase. The vapour
leaving the top of the column gets cooled down and is partly liquefied in the heat exchanger,
once again heated in the heat exchanger and used as regeneration gas. With the purification
stage requirements of oxygen contents <100ppmv and even of 10ppmv in the CO2 product
can be achieved. With the rectification of oxygen other components like nitrogen, argon and
carbon monoxide will be removed as well, resulting in a high-purity CO2 product[77].
8 ECONOMIC ASSESSMENTS
8.1 The review of published study results
Several studies have provided a techno-economic assessment of oxy-fuel combustion of
pulverized coal as means of CO2 capture, which have been compared with pre- and post-
combustion cases [78-85]. Although the cost of oxy-combustion power plant will be more
expensive than an air fired plant without capture, it was suggested that oxy-fuel combustion
offers a competitive technology option for capture.
- 47 -
To achieve a comparison of technologies, they must have the same design basis. Three in-
depth studies made by USDOE/NETL, GCCSI and AUS DRET/EPRI have systematically
evaluated the different technologies including post-, pre- and oxy-combustion power plant.
8.1.1 Pulverized Coal Oxy-combustion Power Plants of DOE NETL study
The DOE NETL study [83] was published in August, 2008, and considers twelve plant
configurations. In all cases, the coal feed rate was adjusted to maintain a nominal net plant
output of 550MW. The twelve cases examined include four conventional air-based
combustion cases for reference (with and without CO2 control), six oxy-combustion cases
with O2 provided by a cryogenic distillation process and two oxy-combustion cases with O2
provided by an ion transport membrane process. Both supercritical (SC) and ultra
supercritical (USC) steam cycles were analyzed. Different levels of oxygen purity and CO2
purity were also considered. The twelve cases are summarized in Table 10.
Table 10 USDOE/NETL Case Description Case Boiler Steam Parameters
MPa/℃/℃
Oxidant CO2 Purity
1 Wall-fired PC 24.2/599/621(SC) Air N/A
2 Wall-fired PC 27.7/732/760 (USC) Air N/A
3 Wall-fired PC 24.2/599/621(SC) Air ~100%
4 Wall-fired PC 27.7/732/760 (USC) Air ~100%
5 Wall-fired PC Oxy-fuel 24.2/599/621(SC) 95% O2
Cryogenic ASU
84%
5A Wall-fired PC Oxy-fuel 24.2/599/621(SC) 99% O2
Cryogenic ASU
88%
5B Wall-fired PC Oxy-fuel 27.7/732/760 (USC) 95% O2
Cryogenic ASU
88%
5C Wall-fired PC Oxy-fuel 24.2/599/621(SC) 95% O2
Cryogenic ASU
96%
6 Wall-fired PC Oxy-fuel 27.7/732/760 (USC) 95% O2
Cryogenic ASU
84%
6A Wall-fired PC Oxy-fuel 27.7/732/760 (USC) 95% O2
Cryogenic ASU
96%
7 Wall-fired PC Oxy-fuel 24.2/599/621(SC) ~100% O2
ITM ASU
88%
7A Wall-fired PC Oxy-fuel 24.2/599/621(SC) ~100% O2
ITM ASU
96%
- 48 -
The estimated plant efficiencies are shown in Fig. 21. Case 1 is an air-fired SC PC without
CO2 capture, which is the reference case to which the others are compared. Case 1 is a
commercially available plant configuration. Case 2 with USC steam conditions and no CO2
capture has a 5.2% point higher efficiency than Case 1. Case 3 and 4 using Econamine is a
post-combustion method for CO2 capture which results in similar decreases in efficiency
(approximately 11%) compared to the equivalent non-CO2 capture cases. Case 5 using oxy-
combustion with a cryogenic ASU result in the efficiency approximately 1% point higher than
case 3. Case 6 results in approximately the same efficiency as case 4. Case 7 with SC steam
conditions and ITM ASU has an efficiency that is essentially the same as the comparable
system with case 5.
Figure 21 Plant efficiency [83]
The Levelized Cost of Electricity (LCOE) results are shown in Fig. 22. The LCOE for case 4
and case 6 (USC CO2 capture) are lower than their SC counterparts, case 3 and case 5, by
approximately 0.5¢/kWh. The cryogenic oxygen cases have the lowest LCOE of CO2 capture
cases for similar steam conditions (compare case 5 to case 3 and 7, and case 6 to case 4). The
LCOE for case 7 is approximately equal to the case 4. Comparatively, the LCOE for
combustion cases with CO2 capture is 7-8% lower than air-fired case with CO2 capture.
- 49 -
It can also be seen that the capital cost is the major proportion in the LCOE, and the fuel cost
is next in importance, followed by the variable O&M cost, and fixed O&M cost, respectively.
The CO2 transport, storage & monitoring (TS & M) costs also influence the LCOE cost.
Figure 22 Levelized Cost of Electricity including CO2 Transport, Storage and Monitoring [83] Fig.23 shows the costs for all cases on a $/ton CO2 capture and $/ton CO2 avoided basis.
Comparing the SC cases, it is seen that the cryogenic oxy-combustion case with higher purity
oxygen (99%) has the lowest cost of CO2 captured and avoided. Case 5 has slightly higher
costs of CO2 captured and avoided than case 5A. Comparing case 5A and 5B, it is clear that if
a higher purity CO2 product is required, the more cost effective approach is to use a higher
purity oxygen supply rather than to add a purification process for the CO2 stream. Comparing
case 4, 6 and 6A, it is seen that the cost of CO2 capture and avoided is lower for the oxy-
combustion cases than for the air-fired amine based capture system (case 4). Comparing case
5 and 6, it can be seen that the cost of CO2 captured is similar for the SC and USC oxy-
combustion cases; however the higher efficiency of the USC case results in a lower cost of
avoided.
- 50 -
Figure 23 CO2 Mitigation Costs [83] The study results show that applying post-combustion technologies for CO2 capture results in
an increase in LCOE of nearly 75%. For the oxy-combustion cases studies, the increase in
LCOE ranged from a low of 52% for case 6 to a high of 63% for case 7. Cryogenic oxy-
combustion has a higher net thermal efficiency and a lower LCOE than an air-fired amine
based system. Case 5 and case 6 have the lowest cost of CO2 captured. Case 6 has the lowest
cost of CO2 avoided. One scenario to accomplish the DOE goal of no more than a 20%
increase in LCOE is an oxy-combustion USC PC boiler without FGD, without boiler
contingency, and with ASU capital and operating costs that are 62% of the current markets
costs of cryogenic ASU’s.
8.1.2 Economic Assessment of Carbon Capture and Storage Technologies from a
GCCSI study
The GCCSI report [84] was published in 2011, with the capital costs used in the reference
report at 2010 US$. The report considers eleven plant configurations. Here, seven cases with
CO2 capture were selected for comparison. Performance and capital cost data for PC power
plant were developed using data from various reports (Worley Parsons 2009a; Worley
Parsons 2009b; DOE/NETL 2007). The data for IGCC power plant are based on Shell
technology (dry feed). Table 11 is the case description.
- 51 -
Table 11 GCCSI Case Description Case Boiler Steam Parameters
MPa/℃/℃
Oxidant CO2 Purity
1 PC SC 24.2/599/621 Air ~100%
2 PC USC 27.7/732/760 Air ~100%
3 PC OXY-SC 24.2/599/621 95% O2
Cryogenic ASU
84%
4 PC OXY-USC 27.7/732/760 95% O2
Cryogenic ASU
84%
5 PC OXY-SC-ITM 24.2/599/621 ~100% O2
ITM ASU
88%
6 IGCC ~100%
7 NGCC ~100%
The plant efficiency data is shown in Fig. 24. It can be seen that the net efficiency of the PC
power plant is same as the DOE/NETL results. Compared with PC power plant, Case 6 with
IGCC has an approximately 4% point higher efficiency than case 1, case 3 and case 5 with SC
steam and ITM ASU conditions, and 1% point lower than case 2 and case 4 with USC steam
conditions. Case 7 with NGCC has the greatest plant efficiency up to 43.7%.
Figure 24 Plant efficiency [84] The LCOE results are shown in Fig. 25. The costs have increased from the DOE/NETL study,
because the data has been updated to 2010. For the reference cases, taking into account
currently available technologies, the LCOE for post-combustion with supercritical technology
was the greatest at US$129/MWh, while the oxy-combustion for ultra supercritical
technology was the lowest of the commercially available technologies at US$114/MWh. Pre-
combustion with IGCC has slight higher than oxy-combustion with supercritical technology
28.3 33.2
29.3 33
29.3 32
43.7
0.0
10.0
20.0
30.0
40.0
50.0
Plan
t Eff
icie
ncy
(%, H
HV
)
- 52 -
and post-combustion with ultra supercritical technology. The LCOE of post-combustion with
NGCC and pre-combustion with IGCC are similar. While the cost of CO2 avoided and
captured range by a factor of two, the LCOE estimates ranged between US$114-129/MWh
with currently available technologies.
Figure 25 Levelized Cost of Electricity including CO2 Transport, Storage and Monitoring [84] The costs for all cases on a $/ton CO2 capture and avoided basis are shown in Fig. 26. The
cost of CCS for power generation, based on the use of commercially available technology,
was found to range from US$47-107 per ton of CO2 avoided or US$39-90 per ton of CO2
captured. The lowest cost of CO2 avoided was US$47 per ton of CO2 for the oxy-fuel
combustion technology, while the highest cost at US$107 per ton of CO2 for the natural gas-
fired combined cycle (NGCC) with post-combustion capture (PCC). This compared with the
lowest cost of captured CO2 for the IGCC and oxy-combustion technologies at US$39 and
US$42 per ton of CO2 respectively and the highest of $90 per ton of CO2 for NGCC
technologies. In this study the fuel costs were based on values typical for 2010. It is
concluded that NGCC technology has the greatest plant efficiency, however, the cost of CO2
capture and avoided is the highest in the compared cases.
129
120 121
114
123 123 122
105
110
115
120
125
130
135
LCO
E ($
/MW
h)
- 53 -
Figure 26 CO2 Mitigation Costs [59]
8.1.3 The EPRI study of Australian Electricity Generation Technology Costs
commissioned by DRET
In 2010, the Australian Government Department of Resources, Energy and Tourism (DRET)
commissioned EPRI to undertake an assessment of the costs of different energy technologies
to 2030. [85] Five PC cases and two IGCC cases are selected to compare with each other in
this paper. The PC plants were able to be specifically sized at the pre-selected 750 MWe sent-
out. The steam conditions are 26.7MPa/596ºC/596ºC. All of the IGCC alternatives were
configured with GE-9FA gas turbines as the primary power generation components and these
were arranged as 2+1 combined cycle units. Two types of coal, Hunter Valley Black Coal and
Latrobe Valley Brown Coal, were used in the economic estimate. The results of these estimates
are based on the data in mid-2009 Australian dollars.
Plant efficiency is shown in Fig. 27. It can be seen that the efficiency of PC power plant using
brown coal is lower than using black coal. Brown coal has very high moisture content and
requires drying before it can be used in either the conventional or the oxy-fired PC plant.
Black Coal does not require drying. Owing to requiring a lot of energy in the drying process,
therefore, the efficiency decreased. The efficiency of the cases with CO2 capture will decrease
approximately 10% point than the cases without CO2 capture. With CO2 capture, PC oxy-
combustion with black coal has the highest efficiency comparing with post-combustion and
pre-combustion (IGCC).
53 55
42 43 47 39
90 81
62 57
47 59
67
107
0
20
40
60
80
100
120
Mit
igat
ion
Cost
s ($
/ton
)
CO2 Captured
CO2 Avoided
- 54 -
Figure 27 Plant Efficiency [85] The LCOE results are shown in Fig. 28. It can be seen that the LCOE is higher than the
GCCSI study. The reason is that the magnitude of the cost adjustments varied by technology,
depending of the mix of major equipment, materials, and construction labor. Fig. 29 show the
relative overall capital cost adjustments for pulverized coal. The pulverized coal plant requires
a much larger fraction of field labor and therefore has an overall US Gulf Coast to Australia
adjustment factor of about 1.80, including currency conversion.
The capital cost is still the major contributor to the LCOE. Due to the lower fuel price and
higher labor cost in Australia, their proportions in the LCOE will differ in comparison with
other countries. Oxy-combustion has the lowest cost comparing with other technologies. It
can be seen that IGCC has the greatest cost with and without CO2 capture.
34.9 38.0 39.4
25.5 28.4 30.1 28.9
0.0
10.0
20.0
30.0
40.0
50.0
60.0
SCPC Brown
SCPC Black
IGCC Black
SCPC Brown
CCS
SCPC Black CCS
PC-OXY Black
IGCC Black CCS
Plan
t Eff
icie
ncy
(%,H
HV
)
with CO2 capture
without CO2 capture
- 55 -
Figure 28 Levelized Cost of Electricity including CO2 Transport, Storage and Monitoring [85]
Figure 29 Pulverized Coal Plant Costs, US Gulf Coast vs. Australia [85]
8.2 Cost impacts
We have seen that the coal-fired power plant flowsheet is primarily determined by the sulfur
level of the coal, with the sulfur removal from the flue gas and recycle stream indicated on
Table 12. For a retrofit power plant demonstration without flue gas desulfurization system, a
low sulfur coal (<0.5 wt %) is required. The position of the flue gas extraction (which is so-
SCPC Brown
SCPC Black
IGCC Black
SCPC Brown
CCS
SCPC Black CCS
PC-OXY Black
IGCC Black CCS
CO2 T&S 0 0 0 21 18 17 20
Fuel 8 14 14 11 19 18 19
O&M 11 9 23 25 23 17 34
Capital 73 54 93 134 107 115 141
0
50
100
150
200
250
LCO
E (A
SU/M
Wh)
without CO2 capture
with CO2 capture
91 78
130
191
167 166
213
- 56 -
called warm recycle) is located downstream of dust removal equipment. In order to prevent
the corrosion of the materials of the recycle duct and mill, the gas cooler should be set up to
remove the H2O in the primary recycle stream. For a commercial power plant, the optimum
flowsheet is mainly determined by the coal’s sulfur content. For the coal with less than 1 wt
% sulfur, the secondary recycle flue gas is usually extracted downstream the fabric filter and a
gas cooler to remove the fly ash and moisture. The primary recycle position should be located
downstream of the SDA followed by a PJFF to remove SO2 and part of SO3 and mercury. To
reduce sulfur dioxide and particulate matter to low levels, a small wet FGD polishing
scrubber may be put downstream the SDA and FF. The cleaned flue gas also needs to be
reduced in H2O and reheated before entering the pulverizer. To prevent corrosion, for coal
with more than 1 wt % sulfur, the full recycle flue gas should be cleaned by the high
efficiency WFGD combining the dry sorbent injection upstream the PJFF to reduce SO2 and
SO3. To remove the moisture in the flue gas, the DCCPS is used downstream the WFGD
which further reduces SO2.
Table 12 Summary of sulfur gas removal flowsheets
Flowsheet Sulfur and moisture removal from recycle gas
Full recycle Primary gas recycle
(~20% flow)
Secondary gas recycle
(~ 80% flow)
COP, Fig. 12 Probable removal in
H2O remover
B&W low S option, cool
gas recycle, Fig. 13
SO2 removal in SDA
and WFGD
H2O removal in
Cooler
H2O removal in Gas
Cooler
B&W high S option, warm
gas recycle, Fig. 14
Sorbent for SO3 prior
to PJFF
SO2 removal in
WFGD
H2O and SO2
removal in DCCPS
Compared with sulfur, nitrogen and mercury in coal are less sensitive based on the
flowsheets. Indeed, SCR or SNCR may be eliminated with NOx controlled through
optimizing parameters of the burner in oxy-fuel power plant flowsheets. Some mercury
species - Hg2+ and HgP - may be substantially removed by the FGD and FF equipment.
However the Hg0 fraction is generally not captured by exiting APCD and sorbent injection is
- 57 -
considered as an effective method for removing the Hg0. Halogen species have been regarded
as one important factor affecting mercury transformation. Some published data show that [86,
87] co-firing chemical additives such as CaCl2 and CaBr2 is a cost-effective mercury control
option for subbituminous and lignite coal-fired plants.
The differences in the flowsheets for the power plant identified in Table 10 will determine the
capital and operating costs as well as influencing the efficiency penalty of oxy-fuel
technology.
Fig. 30 (for low sulfur coal, S: 0.15%) and Fig. 31 (for high sulfur coal, S: 2.5%) give
published breakdowns of capital costs of the major operations of oxy-fuel technology. The
capital cost breakdown in Fig. 30 is calculated from the the study of Australian Electricity
Generation Technology. The selected case is a PC oxy-combustion power plant with a
supercritical cycle which the steam conditions are 26.7MPa/596ºC/596ºC and the net out
power is 750MWe.
The data in Fig. 31 is calculated according to the DOE/NETL study. The selected case is also
a PC oxy-combustion power plant with a supercritical cycle. The steam conditions are
24.2MPa/599ºC/621ºC and the net out power is 550MWe. The PC component of Fig. 30
includes the cost of air separation unit (ASU), fabric filter (FF) and mercury removal
equipment (HgRS). However, the data in Fig.31 separates components. The cost of mercury
removal system not included in the DOE/NETL study is cited from the report [88], which is
an activated carbon fixed bed at high pressure used in an IGCC plant. The mercury is
removed from the compressed syngas, which greatly reduces the gas volume and thus the size
of the equipment and the number of beds. The gas pressure is 26bar, and temperature is 39℃.
For the low sulfur coal the warm recycle process is adopted in the flue gas cleaning system
which treats about 30% percent of the full flue gas. The capital cost of FGD is only 0.7% of
the total cost. For the high sulfur coal the requirement of a wet FGD for sulfur gas removal
from the full flue gas is associated with a plant capital cost increase of 7.62%, similar to the
CPU cost. In addition associated operating costs will arise for limestone required for the FGD,
and associated water and power systems. At this time we are not able to evaluate the cost
differences between the compression flowsheets, but these will clearly be less than those for
the power plant.
- 58 -
Fig. 32 gives the LCOE breakdown of oxy-fuel technology for a high sulfur coal, which
includes CO2 transport and storage, from the DOE/NETL study.
The proportion of the capital cost required for sulfur gas control (with a FGD) is 7.62% and
its O&M cost proportion of the LCOE is 1.6%.
Mercury control is included as a carbon bed in the compression system, with a capital cost of
0.27% and operation cost of 1.5%, which includes the cost of the carbon sorbent. But a recent
report indicates that there is a risk of a thermal excursion within the bed at high pressure. The
study [89] showed that alternative methods in the natural gas process plant can be used in the
CO2 compression process to remove mercury – including metal-sulfide fixed bed absorbents
and silver-promoted molecular sieve adsorbents.
Figure 30 Capital cost breakdown of oxy‐fuel for a low sulfur coal which excludes CO2 transport and storage COAL---Coal Handling System, PC---Steam Generator and Accessories, FF---Fabric Filter, FGD---Flue Gas
Desulfurization, before recycle, ASU---Air Separation Unit, HgRS---Mercury Removal System within the
compression system, CPU---CO2 Purification Unit, STG---Steam Turbine Generator, BOP---Balance of Plant
including Feed water; Cooling water; Ash handling; Instrumentation & control; Building & structures etc.）
COAL , 3.9%
PC (ASU,FF,HgRS),
43.0%
FGD, 0.7%
CPU, 17.1%
STG, 13.1%
BOP, 22.2% COAL
PC (ASU,FF,HgRS)
FGD
CPU
STG
BOP
- 59 -
Figure 31 Capital cost breakdown of oxy‐fuel for a high sulfur coal which excludes CO2 transport and storage ASU---Air Separation Unit, COAL---Coal Handling System, PC---Steam Generator and Accessories, FF---Fabric Filter, FGD---Flue Gas Desulfurization, before recycle, HgRS---Mercury Removal System within the compression system (not included in DOE/NETL study, but estimated from scaled literature information on costs of IGCC Hg removal bed) , CPU---CO2 Purification Unit, STG---Steam Turbine Generator, BOP---Balance of Plant including Feed water; Cooling water; Ash handling; Instrumentation & control; Building & structures etc.）
Figure 32 LCOE breakdown of oxy-fuel technology for a high sulfur coal which includes CO2 transport and storage
ASU, 17.37% COAL, 4.40%
PC, 26.58%
FF, 2.39%
FGD, 7.62%
HgRS, 0.27%
CPU, 7.66%
STG, 9.23%
BOP, 24.74%
ASU
COAL
PC
FF
FGD
HgRS
CPU
STG
BOP
Capital, 55.8% O&M-Others,
15.8%
O&M-FGD, 1.6%
O&M-Hg, 1.5%
Fuel, 19.7%
CO2 TS&M, 6.3%
Capital
O&M-Others
O&M-FGD
O&M-Hg
Fuel
CO2 TS&M
- 60 -
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