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FINAL TECHNICAL REPORT
January 1, 2010, through May 31, 2012
Project Title: TURBINE AND BOILER MATERIALS DEVELOPMENT
FOR IGCC ENVIRONMENTS
ICCI Project Number: 10/9A-1
Principal Investigator: Anand Kulkarni, Siemens Energy Inc.
Project Manager: Francois Botha, ICCI
ABSTRACT
In moving towards higher efficiency power generation systems that produce lower
CO2 emissions, the use of gasification based combined cycle technologies
becomes increasingly attractive. The coal-fired combined cycle power systems
that are being developed are mainly based on coal gasification and/or combustion,
with associated gas cleaning technologies to meet system and emission
requirements. The gasification procedure generates very aggressive atmospheres.
The gas streams contain CO, CO2, H2S, SO2 and H2O, that result in corrosion
degradation including oxidation, carburization and sulphidation along with fly ash
particulates that results in erosion of downstream components. Owing to this,
there is a greater need to investigate the influence of these atmospheres on
materials performance and its effect on lifetimes in their required operational
environments. The project aims to understand the complex materials degradation
mechanisms that take place in these aggressive atmospheres that would be
instrumental in developing future advanced material systems capable of
withstanding higher firing temperatures and increased mass flow in IGCC
environments. The scope of the current project within the ICCI-funded project is
obtaining experimental information about materials degradation
(oxidation/corrosion loss) on boiler and gas turbine materials and coatings. Efforts
would focus on addressing materials degradation in (a) gas turbines and (b) utility
boilers. In both of these applications, there exists a need to generate quantitative
information on materials degradation in novel environments compared to natural
gas. The prime objective would be performance evaluation of relevant alloys and
coatings in novel gas environments resulting from coal combustion/gasification of
Illinois coals, compared to natural gas application. The proposed research,
establishing advanced testing techniques and characterization methodologies will
lead to better solutions of coating evaluation for proposed advanced IGCC
material systems.
2
EXECUTIVE SUMMARY
A number of concepts have been employed to enable power plants (both gas
turbine and utility boilers) using coal and coal derived synfuels including
pressurized fluidized bed combustion (pfbc), coal gasification combined cycle
(gcc), and direct coal fired combustion turbines (dcft). However, compared to oil
and natural gas, coal contains greater quantities of sulfur, nitrogen, trace elements,
ash, etc., and produces more CO2 for the same fuel calorific value. Therefore, the
usage of coal for power generation must be highly efficient and have excellent
environmental protection features. The gas turbine when fully fired on typical
syngas compositions has the potential to develop enhanced power output capacity
due in large part to the significant flow rate increase (≈ 14% increase over natural
gas), resulting from the low heating value fuel combustion products passing
through the turbine. This power output could increase as much as 20-25% when
compared with the natural gas. However, this increase in power output is also
accompanied by an increase in the moisture content of the combustion products
due largely to higher hydrogen content in the syngas and the increased turbine
flow which can contribute significantly to the overheating of turbine component
parts. The gasification procedure generates very aggressive atmospheres. The gas
streams contain CO, CO2, H2S, SO2 and H2O, that result in corrosion degradation
including oxidation, carburization and sulphidation along with fly ash particulates
that results in erosion of downstream components. The extent to which impurities
are present in the fuel gas will be a function of the process used to produce the gas,
as well as the type of feedstock from which the gas is derived. Maximizing the
lifetime and reliability of existing PC fired utility boilers will remain critical to
maintaining power generation capacities as well. This includes repowering of
aged, low-efficiency, pulverized coal units by adding emission controls to comply
with environmental requirements. The industry continues to see development of
coating materials and application techniques to provide better characteristics to
resist delamination in cyclic service, improved corrosion and erosion resistance,
and faster rates of both shop and field application. The use of overlays and
coatings for protection of boiler parts is increasing, particularly for furnace
waterwalls having high metal loss in reducing environments associated with
staged combustion for low NOx, but also for protection against molten ash
corrosion in superheaters, flyash erosion and corrosion in the convective pass, and
for sootblower and water lance erosion in units burning coals with severe slagging
characteristics.
As many IGCC turbine systems will operate at slightly different temperature
ranges, pressures, and mass flow rates, a firm understanding of the types of failure
mechanisms associated with the various environments is critical. Other than
design parameters, operating environment factors such as, contamination, water
vapor, corrosives, fly ash erosives, thermo-mechanical, and high heat flux
behavior is important in constructing data bases and future thermokinetic models
of proposed advanced turbine systems. The program structure involves utilizing
the Siemens capabilities to conduct experiments in selected test rigs and also
establishing a baseline of the materials performance in IGCC compared with
3
natural gas environments. Understanding the present failure mechanisms,
chemical effects of deposits on alloys and coating systems, and isolation of those
effects from the thermomechanical failure mechanisms will result in the ability to
tailor advanced materials systems for current and future IGCC operating
environments. The test rigs simulate the gas compositions of the combusted fuel,
the hot gas temperature and velocities, the alkali and ash impurities to replicate
the actual engine conditions. The availability of multiple rigs enables relevant
alloys and coatings testing in simulated environments in isothermal and high heat
flux conditions. This research is vital in taking initial steps to identify,
characterize, and evaluate degradation mechanisms in material systems to develop
logical engineering solutions to the many difficulties associated with demanding
requirements on materials performance in PC fired boilers and in turbines for
future IGCC environments. Owing to this, there is a greater need to investigate
the influence of these atmospheres on materials performance and its effect on
lifetimes in their required operational environments in both gas turbine and
boilers.
In particular, Illinois coals, on average, are slightly more abrasive than other
domestic coals as a result of the relatively higher pyrite content found in the coals
of the Illinois basin. The potential for severe slagging within the furnace is of
particular concern. This is primarily due to generally lower ash fusion
temperatures derived from a relatively high iron content, which is found in the
form of pyrites. The presence of the high pyrite content can also be detrimental in
high temperature turbine environments where they can deposit on the surface of
the components influencing life, similar to CMAS effect on thermal barrier
coatings. Also, Illinois basin coals are considered to be corrosive at elevated
temperatures due to a sufficiently high ratio of alkali metals and in combination
with sulfur from SO3. The combination forms the alkali iron trisulfates
Na3Fe(SO4)3 and K3Fe(SO4)3 which in a molten state are primarily responsible for
metal loss downstream in superheaters. Also, this phenomenon can be similar to
metal dusting phenomenon observed in auxiliaries in a power plant.
The focus of the work has been to mainly address the key customer question: “For
a given fuel specification and material system, what is the predicted life time
under engine operating conditions?” A focused research program was proposed to
explore materials degradation modes in IGCC systems, and develop alternative
coatings suitable for use in syngas, high hydrogen and future oxy fuel fired
systems. While drive gas chemistry and impurities may vary widely based on the
fuel source (coal, petroleum coke, oil residuals, biomass, etc.) and the process
used to generate and clean the syngas, the raw gas is composed primarily of
carbon monoxide and hydrogen. Lesser amounts of methane, nitrogen, carbon
dioxide, and water are also present. High sulfur levels coupled with alkali vapor,
hydrogen chloride, hydrogen cyanide, carbonyl sulfide, ammonia can contribute
to premature thermal barrier coating (TBC) degradation. Iron and nickel
carbonyls have proven to be particularly troublesome in that they lead to heavy
deposits on the turbine blades, vanes, combustors and fuel nozzles. In addition,
particulate carryover, condensate and incomplete combustion can lead to the
4
formation of deposits on the turbine blades altering the strain tolerance of the
coating system. Initial research has shown that mixtures of high temperature
steam, CO2 and corrosives/ impurities/ deposits unique to these environments lead
to unique and severe degradation modes.
For the gas turbine materials, understanding of turbine material system limitations
in corrosive environments is essential to meet design requirements and also to
assess risk for fuel flexible operation. The efforts focused on evaluating the
impact of isothermal simulated environments on the oxidation/corrosion design
curves of metallic superalloys and bond coats. For the ceramic coatings,
evaluating the interaction of solid particles, originating from the environment (e.g.
desert sand) or coal-gasifier (e.g. fly ash), with the thermal barrier coating (TBC)
will determine the deterioration of the TBC. For boiler materials, the evaluation of
advanced coating materials for boiler tubes corrosion & erosion resistance under
simulated low NOx firing using Illinois No. 6 coal conditions in carried out and
compared to the IN625 weld overlay baseline. The objective was to achieve
quantitative ranking of the coating materials for both corrosion and erosion
resistance.
Results showed accelerated degradation and hence an impact on oxidation curves
in IGCC environments. It is shown that the exposure in gaseous environment does
have a debit on oxidation rate of the bond coats, the data shows 20 degree drop in
oxidation temperature limit. For TBCs, the Illinois fly ash melts above 1260 °C,
and hence complete infiltration is observed when samples are exposed above that
temperature. This infiltration is indicated in change in thermomechanical
properties of the coating. On the boiler samples, Significant corrosion occurred to
varying degrees on the samples that were tested underneath the deposit (solid state
corrosion) with an oxidizing gas at 1200 oF, and by direct gaseous attack with a
reducing gas at 1200 oF (gaseous corrosion). The current commonly used Inconel
625 Weld Overlay is the best for both corrosion & erosion resistance
simultaneously on boiler tubes. The complete Boiler Materials Report is also
available separately as Appendix C.
5
OBJECTIVES
To characterize the range of fuel gas atmospheres anticipated in solid fuel
fired gasification systems, typically C/H ration of 0 to 2 for shifted to
unshifted syngas and moisture content of up to 8.5% with syngas fired IGCC
engines to 90% for oxy-fuel fired turbines.
To expose selected alloy/coating combinations to burner rig testing and
determine deposition and oxidation rates and the erosion/ corrosion resistance
of state-of-the-art materials and coating systems over the appropriate
operating temperature ranges in a thermal gradient environments (up to
gradient of 400°C) for up to 1000 hour exposures.
To expose selected alloy/coating combinations to simulated drive gas
conditions in isothermal furnace testing and determine oxidation and
corrosion rates in hot corrosion regime (650 to 1100 °C) for up to 500 hour
exposures and establish quantitative analysis through weight gain, depth of
oxidation/degradation and dimensional metrology.
To quantify the major degradation effects on gas turbine materials operating
with LCV fuel gases, including coal- biomass- and waste-derived syngas, in
order to improve component design and life prediction methods.
To develop and validate life prediction methods to assess component integrity
and deposition/oxidation/corrosion kinetics.
Demonstrating that the researched base alloy/coating systems offer improvements
in component lives over current state-of-the-art materials systems in the novel
syngas derived operating environment in a pilot plant would be the ultimate goal
for this program.
INTRODUCTION AND BACKGROUND
The substantially higher surface temperatures expected in syngas fired turbines
(and future oxy fuel based systems), combined with higher water vapor contents
and impurities intrinsic to coal derived syngas (and high hydrogen fuels) will
expose the inadequacies of current flow path alloys and thermal barrier systems.
IGCC systems fueled with syngas have shown increased TBC degradation, as
well as failure modes that are distinct from those observed with natural gas fired
system. An example of alloy and TBC system degradation after exposure to a
syngas-based burner rig test environment is shown in Figure 1, and illustrates the
severity of the attack of materials that are otherwise suitable for natural gas-fired
systems. The base material superalloy on the left is Alloy(CM)247 and the middle
picture is the overlay/bond coated ALLOY(CM)247 and the right one is the 8YSZ
coated TBCs. It also shows coatings to provide hot corrosion resistance to
underlying base materials in hot gas path.
6
Failure initiation
Extensive
degradation
Less severe damage of coated specimens compared to bare alloysFailure initiation
Extensive
degradation
Less severe damage of coated specimens compared to bare alloys
Figure 1: Materials system degradation observations after burner rig testing in a
syngas environment
Alloys and coatings tested under simulated IGCC flue gas environments exhibited
greater degradation than those exposed to the natural gas environment, as shown
in Figure 2. The degradation in the IGCC environments was attributed to the
higher CO2/H2O ratio and a higher test temperature. Degradation observed
following the IGCC#2 test and the high hydrogen test was attributed to the higher
moisture content. The multiple IGCC environment encompasses varied coal
feedstock combined with gasified coal in shifted and unshifted conditions. The
results show the performance of the materials is highly dependent on the
feedstock conditions resulting in different flue gas environment in the hot gas path.
NG IGCC #1 IGCC #2 High H2Fuel CompositionNG IGCC #1 IGCC #2 High H2Fuel Composition
Figure 2: Micrographs showing material degradation after isothermal
environmental testing
Figure 3 shows the performance of two bond coats (Sicoat 2231 and Sicoat 2464)
in the burner rig. These bond coats typically tend to form thermally grown oxide
(alumina) in a natural gas environment. These bond coats form the spinel phase
after the aluminum rich beta phase is depleted. However, these bond coats formed
thicker oxide layer comprising mixed oxides (spinel phases) in a syngas
environment, even in the beta phase present. The difference is again the different
C/H ratio. Further research efforts are proposed to investigate the oxidation
kinetics in these novel environments.
7
Bond coat 1 Bond coat 2
NG
Syngas
TGO
Mixed
oxides
Bond coat 1 Bond coat 2
NG
Syngas
TGO
Mixed
oxides
Figure 3: Micrographs showing material degradation after isothermal
environmental testing
For boiler materials, the evaluation of advanced coating materials for boiler tubes
corrosion & erosion resistance under simulated low NOx firing using Illinois No.
6 coal conditions was carried out. At present, the boiler industry uses Inconel 625
Weld Overlay as the material for both corrosion and erosion resistance in boiler
pressure part tubes, but it is an expensive option. For a cost effective option,
under this R&D evaluation, four samples of coating materials from the material
coating industry expert companies were evaluated, in addition to a carbon steel
base plate and Inconel 625 Weld Overlay samples for baseline reference
comparison.
The focus of the work will be to address the key customer question: “For a given
fuel specification and material system, what is the predicted life time under
engine operating conditions?” The approach taken involves four phases as shown
in Figure 4 below. Phase 1 involves establishing the ranking of the alloys/coatings
performance in simulated environments. This report summarizes mostly the
experimental testing carried out in this first phase. Following the ranking and
initial insight into the degradation mechanisms, Phase 2 will further develop a
model to extrapolate the short term testing to predict the long term performance of
the materials. Phase 3 would then involve the correlation of the fuel specifications
to the corrosion flux used in the simulated experiments. This third phase would
also involve thermodynamic calculations to calculate the condensate/corrosion
flux kinetics and also allow for compensation of corrosive species with respect to
high pressures. The final phase would demonstrate real engine validation of the
predicted design curves. Phase 1 is the focus of this project involving isothermal
testing of hot gas path materials in simulated environments in the few hundreds of
hours to get insight into degradation mechanisms in a quantitative manner.
8
Final goal: Engine operating conditions
Phase 3: Correlation of fuel specs to
product deposits
Enabling processes :
(A) Thermodynamic calculations
(B) Calculation of condensate kinetics
Substrate TBC
Bond coat
Substrate TBC
Bond coat
Corr
osi
on p
roduct
flu
x
(g/c
m2 /h
)
Phase 1: establish trends & ranking & first insight
into mechanisms
Enabling processes : Experimental testing in
simulated environments.
Phase 2: Establish a model for the mechanisms
to explain the trend & ranking and provide a
direction for Materials development
Enabling processes : Modeling work
Phase 4: Engine validation of predictions
Final goal: Engine operating conditions
Phase 3: Correlation of fuel specs to
product deposits
Enabling processes :
(A) Thermodynamic calculations
(B) Calculation of condensate kinetics
Substrate TBC
Bond coat
Substrate TBC
Bond coat
Corr
osi
on p
roduct
flu
x
(g/c
m2 /h
)
Phase 1: establish trends & ranking & first insight
into mechanisms
Enabling processes : Experimental testing in
simulated environments.
Phase 2: Establish a model for the mechanisms
to explain the trend & ranking and provide a
direction for Materials development
Enabling processes : Modeling work
Phase 4: Engine validation of predictions
Figure 4: Materials approach to address environmental impact on hot gas path
components
EXPERIMENTAL PROCEDURES
Gas Turbine Materials:
The goal is to evaluate the impact of isothermal simulated environments on the
oxidation/corrosion design curves of metallic superalloys and bond coats. The
conditions of the test (Illinois #6 coal syngas and baseline natural gas) along with
materials and temperatures is shown in Figure 5. Isothermal testing in simulated
conditions were carried out at 3 temperatures between 900 – 1050 °C. Samples
were taken out at 50, 100, 200, 300, 400, 500 hours for mass gain and
beta/gamma prime depletion rate comparison of bond coats and superalloy
materials.
Figure 5: Materials test conditions and test matrix for isothermal testing
Set 1 IN939
Set 2 Rene80
Set 3 IN738
Set 4 CM247
Set 5 SC2464 on IN939
Set 6 SC2464 on Rene80
Set 7 SC2464 on CM247
Set 8 SC2231 on IN9391515SO2 ppm
1010CO ppm
BalanceBalanceN2
12.112.6O2
10.54.8CO2
10.717.1H2O
Illinois #6Natural gas
Test 2Test 1
Test ID
1515SO2 ppm
1010CO ppm
BalanceBalanceN2
12.112.6O2
10.54.8CO2
10.717.1H2O
Illinois #6Natural gas
Test 2Test 1
Test ID
9
Boiler Materials:
The objective was to achieve quantitative ranking of the coating materials for both
corrosion and erosion resistance. Under this R&D evaluation, four samples of
coating materials from the material coating industry expert companies were
evaluated, in addition to a carbon steel base plate and Inconel 625 Weld Overlay
samples for baseline reference comparison.
The test sample identification number and their vendors are listed below and
photos of the samples are shown in Figure 1:
Sample No. 1: Coating From Nanosteel.
Sample No. 2: Coating From Whertec Boiler Inspection Services.
Sample No. 3: Coating From Nooter/ Erickson.
Sample No. 4: Coating From Liquidmetal Coating.
Sample No. 5: Weld Overlay w/ Inconel 625 Sample from WTI/BPI –
Baseline material/process used for both Corrosion &
Erosion Resistance.
Sample No. 6: Carbon Steel - Base Metal.
Coating Sample
Vendor No. 1
Coating Sample
Vendor No. 2
Carbon Steel Base Metal
Sample No. 6
Inconal 625 Weld
Overlay Sample No. 5
Coating Sample
Vendor No. 4
Coating Sample
Vendor No. 3Coating Sample
Vendor No. 1
Coating Sample
Vendor No. 2
Carbon Steel Base Metal
Sample No. 6
Inconal 625 Weld
Overlay Sample No. 5
Coating Sample
Vendor No. 4
Coating Sample
Vendor No. 3
Figure 6: Test Samples photos
The corrosion behavior of the coatings was evaluated using gaseous and solid
state corrosion techniques. The erosion resistance behavior was evaluated using
an experimental set up followed that of ASTM C704 (Abrasion Resistance of
Refractory Materials at Room Temperature) as closely as possible. The corrosion
testing procedure and detailed results are presented in the report from Dr. John N.
DuPont of Lehigh University, Bethlehem, PA, attached in Appendix A. The
erosion test testing procedure and detailed results are presented in the report from
Orton Ceramics, Westerville, OH, attached in Appendix B. The complete Boiler
Materials Report is also available separately as Appendix C.
10
The following four test conditions were utilized for the gaseous and solid state
corrosion techniques:
1. Reducing gas at 1200 °F with deposit (Solid state & gaseous).
2. Oxidizing gas at 1200 °F with deposit (Solid state & gaseous).
3. Oxidizing gas at 900 °F with deposit (Solid state & gaseous).
4. Reducing gas at 600 °F with no deposit (i.e., gaseous attack only).
The following four test conditions were utilized for erosion experiments:
Three 90 deg impact at 600 °F, 900 °F, and 1200 °F.
At max erosion case of 90°, perform 1 test at 45° impact.
RESULTS AND DISCUSSION
Gas Turbine Materials Results:
Task 1 - Understanding of turbine material system limitations in corrosive
environments is essential to meet design requirements and also to assess risk for
fuel flexible operation.
Figure 7 shows the characterization efforts for the exposed superalloys and bond
coats in the simulated gaseous environment. The samples are 8 mm diameter pins
and hence will be evaluated at multiple locations on the surface. The figure shows
the depth of degradation. The bottom left is for the superalloy sample. The
gamma prime depletion zone along with the oxide scale is regarded as the total
metal loss (oxidation rate) for the superalloys. For the bond coat sample on the
bottom right, the aluminum rich beta phase depletion is evaluated with
time/temperature exposure. The inner depletion tracks aluminum depletion into
the lower aluminum containing superalloy and the outer depletion is the
aluminum depletion to the surface to form protective oxide. The combination of
the inner and outer depletion calculates the total depletion and oxidation rate for
the bond coats.
11
A = Coating thickness, B = Interdiffusion zone, C = Substrate thickness
D = Surface oxide thickness, E = Internal corrosion depth, F = Deposit thickness
C1 B1 A1
D1
C2 B2 A2D2
Cn Bn An Dn
Measurements
taken at
equidistant
points spaced
300m
Where n 24
F1
F2
Fn
E1
En
To
central
reference
point
Outer
Inner
Beta
depletion
Gamma
prime
depletion
Oxide scale
Metal loss = kincub*tincubm + kprop*(t – tincub)n
Metal
loss
Time
Metal loss = kincub*tincubm + kprop*(t – tincub)n
Metal
loss
Time
A = Coating thickness, B = Interdiffusion zone, C = Substrate thickness
D = Surface oxide thickness, E = Internal corrosion depth, F = Deposit thickness
C1 B1 A1
D1
C2 B2 A2D2
Cn Bn An Dn
Measurements
taken at
equidistant
points spaced
300m
Where n 24
F1
F2
Fn
E1
En
To
central
reference
point
Outer
Inner
Beta
depletion
Gamma
prime
depletion
Oxide scale
Metal loss = kincub*tincubm + kprop*(t – tincub)n
Metal
loss
Time
Metal loss = kincub*tincubm + kprop*(t – tincub)n
Metal
loss
Time
Figure 7: Materials Characterization efforts
The isothermal tests for different simulated environmental conditions were
completed for all three temperatures and the samples have been characterized for
gamma prime depletion in superalloys and beta depletion in the bond coats. The
time dependent degradation of the bare Rene 80, and bond coated IN939
substrates is shown below. Figure 8 shows the time dependent degradation of the
Rene80 substrate for the Illinois #6 IGCC combustion environments. The sample
shows 25 microns degradation after 50 hours to 70 microns depletion after 300
hours.
50 h – 25 um degradation 100 h – 40 um degradation
300 h – 70 um degradation 200 h – 55 um degradation
Figure 8: The time dependent degradation of the Rene80 substrate for the Illinois
#6 IGCC combustion environments
12
The samples were characterized for depth of degradation for multiple superalloy
samples. The figure 9 below shows the specific mass change of the 4 superalloys
at one temperature in simulated Illinois#6 environment. The Alloy(CM)247 is the
material with minimal change in weight and hence the most resistant compared to
the other superalloys. The Rene80 samples show the maximum degradation in the
all tested samples. It is also evident in the attached microstructures.
CM247-Syngas
-14
-12
-10
-8
-6
-4
-2
0
2
4
6
0 50 100 150 200 250 300 350 400 450 500
Time (hours)
Spe
cifi
c n
et
mas
s ch
ange
(m
g/cm
2)
RENE 80 uncoated (Set-2-24)
CM247 uncoated (Set-3-20)
CM247 uncoated (Set-3-24)
IN738 uncoated (Set-4-24)
Rene80-Syngas
IN738
Rene80
IN939
CM247
CM247-Syngas
-14
-12
-10
-8
-6
-4
-2
0
2
4
6
0 50 100 150 200 250 300 350 400 450 500
Time (hours)
Spe
cifi
c n
et
mas
s ch
ange
(m
g/cm
2)
RENE 80 uncoated (Set-2-24)
CM247 uncoated (Set-3-20)
CM247 uncoated (Set-3-24)
IN738 uncoated (Set-4-24)
Rene80-Syngas
IN738
Rene80
IN939
CM247
Figure 9: Comparison of Superalloy degradation in Illinois#6 environments
The Figure 10 now shows the total wall loss calculated for the two extreme
conditions, the Rene80 with the most degradation and the Alloy(CM)247 with
least damage. The data points are for the three temperatures that the samples were
tested at. The figure shows the total wall loss in Rene80 is up to 5X than the
ALLOY(CM)247.
13
0
0.1
0.2
0.3
0 200 400 600
Time (Hours)
To
tal W
all L
os
s (
mm
)
Rene80 950C
CM247 1050C
Rene80 1010
CM247 1010C
CM247 950C
Rene80 1050C
Rene80 undergoes severe
degradation compared to CM247
Rene80-syngas
CM247-Syngas
Total wall loss
accounts for mass
change (alloy +
oxide) and depletion
0
0.1
0.2
0.3
0 200 400 600
Time (Hours)
To
tal W
all L
os
s (
mm
)
Rene80 950C
CM247 1050C
Rene80 1010
CM247 1010C
CM247 950C
Rene80 1050C
Rene80 undergoes severe
degradation compared to CM247
Rene80-syngas
CM247-SyngasCM247-Syngas
Total wall loss
accounts for mass
change (alloy +
oxide) and depletion
Figure 10: Comparison of total wall loss for Rene80 and Alloy(CM)247
The time dependent degradation of the bond coated IN939 substrates for the
Illinois #6 IGCC combustion environments is shown in Figure 11 below. The
inner and outer depletion increases with time. The samples show 20 microns
degradation after 50 hours to 52 microns depletion after 500 hours. Also, the
oxide thickness is also increasing.
50h – 20.1 um 100h – 26.4 um 200h – 31.3 um
300h – 38.6 um 400h – 42.8 um 500h – 51.5 um
50h – 20.1 um 100h – 26.4 um 200h – 31.3 um
300h – 38.6 um 400h – 42.8 um 500h – 51.5 um
Figure 11: The time dependent depletion of bond coated IN939 substrate for the
Illinois #6 IGCC combustion environments
14
The time temperature dependence of the beta depletion is evaluated for 3
temperatures and up to 500 hours. The data was analyzed and the bond coat
oxidation curves were plotted as shown in Figure 12. The data for exposure in air
environment is compared to the samples exposed in natural gas and Illinois #6
coal environment.
Time (Hours)
Tem
per
atu
re (
°C)
Test in air
Natural gas
Illinois#6
20 C drop in
bond coat
oxidation limit
Longer time at
exposed
temperatures
Higher
temperature at
required hours
Time (Hours)
Tem
per
atu
re (
°C)
Test in air
Natural gas
Illinois#6
20 C drop in
bond coat
oxidation limit
Longer time at
exposed
temperatures
Higher
temperature at
required hours
Figure 12: The Impact of gas environments on bond coat oxidation
It is shown that the exposure in gaseous environment does have a debit on
oxidation rate of the bond coats, the data shows 20 degree drop in oxidation
temperature limit. The graph can be interpreted in 2 ways. For the same
requirement of life in hours, the bond coat can be exposed to higher temperature
in air and natural gas environments compared to the syngas environment or for
the same service temperature, the bond coat will last for longer time in air and
natural gas environments compared to the syngas environment.
Task 2 – Evaluating the interaction of solid particles, originating from the
environment (e.g. desert sand) or coal-gasifier (e.g. fly ash), with the thermal
barrier coating (TBC). This interaction can lead to the deterioration of the TBC.
The scope of the current subproject within the ICCI-funded project is obtaining
experimental information about infiltration of TBCs by molten fly ash. Therefore,
several important chemical and physical characteristics of fly-ashes need to be
determined. The ash sample from a PC fired power plant was received from ICCI
for this effort. The chemical composition of the ash showed high iron and silicon
rich ash as shown in Figure 13. Also the viscosity of this ash was carried out to
evaluate the infiltration characteristics of the ash.
15
Oxides CMAS Eyjafjalla
LabA Lab B Average Lab A Lab B Average given Lab B
SiO2 48.27 36.80 42.53 54.05 51.15 52.60 48.35 50.64
TiO2 1.24 1.74 1.49 3.13 4.13 3.63 2.57
Al2O3 18.19 13.66 15.92 33.14 31.69 32.41 11.80 11.91
Fe2O3 21.51 29.05 25.28 5.61 7.76 6.69 16.25
CaO 3.64 4.91 4.28 1.27 1.75 1.51 33.20 8.88
MnO 0.05 0.04 0.05 0.04 0.04 0.04 0.35
MgO 1.24 0.70 0.97 0.94 0.64 0.79 6.50 1.29
K2O 3.46 4.79 4.12 1.14 1.71 1.43 3.48
Na2O 1.15 0.70 0.92 0.41 0.22 0.32 3.09
P2O5 0.41 0.52 0.47 0.23 0.22 0.23 0.38
SO3 0.81 6.07 3.44 0.00 0.32 0.16 0.30
ZrO2 0.03 0.00 0.02 0.04 0.00 0.02 0.00
Illinois Kreament
Chemical compositionOxides CMAS Eyjafjalla
LabA Lab B Average Lab A Lab B Average given Lab B
SiO2 48.27 36.80 42.53 54.05 51.15 52.60 48.35 50.64
TiO2 1.24 1.74 1.49 3.13 4.13 3.63 2.57
Al2O3 18.19 13.66 15.92 33.14 31.69 32.41 11.80 11.91
Fe2O3 21.51 29.05 25.28 5.61 7.76 6.69 16.25
CaO 3.64 4.91 4.28 1.27 1.75 1.51 33.20 8.88
MnO 0.05 0.04 0.05 0.04 0.04 0.04 0.35
MgO 1.24 0.70 0.97 0.94 0.64 0.79 6.50 1.29
K2O 3.46 4.79 4.12 1.14 1.71 1.43 3.48
Na2O 1.15 0.70 0.92 0.41 0.22 0.32 3.09
P2O5 0.41 0.52 0.47 0.23 0.22 0.23 0.38
SO3 0.81 6.07 3.44 0.00 0.32 0.16 0.30
ZrO2 0.03 0.00 0.02 0.04 0.00 0.02 0.00
Illinois Kreament
Chemical composition
Temp [°C] Viscosity [Pa s] Temp [°C] Viscosity [Pa s]
1483 5.50 1620 172.27
1434 8.45 1605 222.90
1385 13.41 1581 370.60
1556 884.22
Illinois Kreament
Viscosity
Figure 13: Chemical composition and viscosity of Illinois #6 coal ash
The differential scanning calorimetry (DSC) studies were carried out to get the
range of melting point for the ash samples as shown in Figure 14. The samples in
ash received state had a lot of volatiles and hence a lot of peaks were observed.
The samples were heat treated for 10 hours at 1300 °C and showed only on peak.
Both the runs however show the ash is completely molten above 1200 °C.
400 500 600 700 800 900 1000 1100 1200 1300 1400
DS
C-S
ign
al [a
.u.]
Temperature [°C]
First heating
After 10h @ 1300°C
CaCO3
decomposition
Melting point
1146 °C
Melting point
1176 °C
Melting point
1102 °C
All CMAFS is
molten < 1300°C
400 500 600 700 800 900 1000 1100 1200 1300 1400
DS
C-S
ign
al [a
.u.]
Temperature [°C]
First heating
After 10h @ 1300°C
CaCO3
decomposition
Melting point
1146 °C
Melting point
1176 °C
Melting point
1102 °C
All CMAFS is
molten < 1300°C
Figure 14: Differential scanning calorimetry of Illinois#6 ash
Following the DSC measurements, free standing TBC coatings were exposed in
isothermal furnaces with ash on top. Figure 15 below shows the ash interaction
when exposed to 1200 °C, 1300 °C and 1400 °C. The Figure shows no infiltration
of ash at 1200 °C. The infiltration is seen for samples exposed at 1300 °C and
area wide infiltration is seen at 1400 °C. This again confirms the melting point of
the ash to be above 1200 °C as seen in DSC.
16
Illinois ash
Almost no infiltration at 1200°C, but
increasing with higher temperature
Infiltration
Ash
1200°C
1300°C
1400°CArea-wide infiltration at 1400°C
Figure 15: Ash infiltration on TBCs in isothermal furnace testing
The impact of this infiltration on material properties was also investigated. The
ash came from PC boiler power plant. Two ashes were synthesized based on the
chemistry of the Illinois ash were prepared with different compositions, one iron
rich and the other Iron/Silicon rich. The two ashes with vastly different viscosities
were selected for evaluating the impact on thermal/mechanical properties. The
difference in the viscosity is mainly due to silica in one ash as shown in Figure 16.
The first CMAF ash is a very low viscosity due to no silica compared to the
CMAFS ash. This will affect the infiltration of the ash in the TBC and hence
affect the thermal and mechanical properties. The rationale thought is that the
infiltration will cause an increase in both thermal conductivity and elastic
modulus.
1200 1250 1300 1350 1400 1450 1500 1550 1600
0
2
4
6
8
10
12
14
16
Vis
co
sity [P
a s
]
Temperature [°C]
1200 1250 1300 1350 1400 1450 1500 1550 1600
0,0
0,2
0,4
0,6
0,8
1,0
1,2
1,4
Vis
cosity [P
a s
]
Temperature [°C]
CMAF CMAFS
Partly crystallisation
1200 1250 1300 1350 1400 1450 1500 1550 1600
0
2
4
6
8
10
12
14
16
Vis
co
sity [P
a s
]
Temperature [°C]
1200 1250 1300 1350 1400 1450 1500 1550 1600
0,0
0,2
0,4
0,6
0,8
1,0
1,2
1,4
Vis
cosity [P
a s
]
Temperature [°C]
CMAF CMAFS
Partly crystallisation
Figure 16: The difference in viscosity between the two ash compositions selected
for evaluating impact on thermal and mechanical properties
17
GZO
0
2
4
6
8
10
12
14
16
Uninfiltrated CMAF CMAFS
po
rosit
y (
%)
YSZ
0
2
4
6
8
10
12
14
16
Uninfiltrated CMAF CMAFS
po
ros
ity
(%
)
Small
infiltration
Large
infiltration
Small
infiltration
Figure 17: Density change with ash infiltration in 8YSZ
As shown in the Figure 17 above, the small decrease in porosity (12-18%) of
CMAF infiltrated YSZ is observed indicating the infiltration only in the top layer.
For the CMAFS ash, a large decrease in porosity (74%) of CMAFS on YSZ
indicated a clear infiltration, which must be deeper than the top layer only.
The thermal conductivity of the ash infiltrated measurements was measured by
Laser Flash technique. The graph 18 below shows the increase in thermal
conductivity resulting from infiltration of the ash. As expected, the ash with lower
viscosity (CMAFS) resulted in deeper penetration and hence has a larger impact
on thermal conductivity (increase of 40-50%) as compared to the other CMAF ash
which was 10-20% increase.
0 200 400 600 800 1000 1200
0.0
0.5
1.0
1.5
2.0
2.5
3.0
YSZ
Uninfiltrated
CMAF #1
CMAF #2
CMAFS #1
CMAFS #2
Th
erm
al C
on
du
ctivity [W
/mK
]
Temperature [°C]
0 200 400 600 800 1000 1200
0.0
0.5
1.0
1.5
2.0
2.5
3.0
YSZ
Uninfiltrated
CMAF #1
CMAF #2
CMAFS #1
CMAFS #2
Th
erm
al C
on
du
ctivity [W
/mK
]
Temperature [°C]
Figure 18: Thermal conductivity change with ash infiltration in 8YSZ
18
The elastic modulus was measured using 1N indentation technique as shown in
Figure 19. Since low load was used, a large scatter in data was observed in
modulus value. Up to 100 measurements were done in each case, however, the
trend shows that the modulus values increase with infiltration. The CMAF
infiltrated sample shows a bimodal behavior, this could be attributed to increased
filtration within the coating and hence localized changes. The CMAFS infiltrated
ash has larger viscosity and hence there might be less infiltration and more ash on
the surface.
0 2 0 4 0 60 80 1 00 12 0 14 0
0
10
20
30
40
50
Occ
ure
nce
[%
]
E-Modulus [GPa]
YSZ CM AFS
0 2 0 40 60 80 1 00 12 0 140
0
10
20
30
40
50
Oc
cu
ren
ce
[%
]
E-Modulus [GPa]
YSZ
0 20 4 0 60 80 100 1 20 14 0
0
10
20
30
40
50
Occ
ure
nce
[%
]
E-Modulus [GPa]
YSZ CM AF
Uninfiltrated CMAF CMAFS
YSZ
Figure 19: Increased modulus due to ash infiltration, affecting TBC life
Since 1N indentation gave the local variation, it is planned to look at mechanical
properties measured using other techniques (bending tests) in the future.
Boiler Materials:
Task 3 – The objective was to achieve quantitative ranking of the coating
materials for both corrosion and erosion resistance.
Significant corrosion occurred to varying degrees on the samples that were tested
underneath the deposit (solid state corrosion) with an oxidizing gas at 1200 oF,
and by direct gaseous attack with a reducing gas at 1200 oF (gaseous corrosion).
Light optical microscopy (LOM) photomicrographs of the samples in the as-
received condition and after 250 hours of corrosion testing at 1200 oF in the
oxidizing gas with a deposit (solid state corrosion) are shown in Figure 20. The
LOM photomicrographs of the samples after 250 hours of corrosion testing of
direct gaseous attack with a reducing gas at 1200 oF (gaseous corrosion) are
shown in Figure 21.
19
Figure 20: LOM Photomicrographs of Before and After Samples Were Solid
State Corrosion Tested For 250 Hrs at 1200°F under Oxidizing Conditions
Sample 1 Sample 2 Sample 3
Sample 4 Sample 5 Sample 6
Sample 1 Sample 2 Sample 3
Sample 4 Sample 5 Sample 6Sample 4 Sample 5 Sample 6
Figure 21: LOM Photomicrographs of After Samples Were Gaseous Phase
Corrosion Tested For 250 Hrs at 1200°F under Reducing Conditions
20
The coated samples did not show significant corrosive attack under the following
three conditions:
1. Underneath the deposit with the reducing gas at 1200 °F
2. Underneath the deposit with an oxidizing gas conditions at 900 °F
3. In the reducing gas at 600 °F (no deposit)
Within the more severe test conditions, Samples 2 and 4 exhibited evidence of
significant corrosion. Samples 1, 3, and the weld overlay (Sample No. 5) coating
appear to provide better protection from inspection by light optical microscopy.
Samples 1, 3, and 5 were examined in more detail in order to determine if
localized diffusion of sulfur occurred down the splat boundaries in a Hitachi 4300
scanning electron microscope (SEM) equipped with light element detectors. SEM
imaging was conducted in secondary electron mode. Localized variations in
composition within the coating and corrosion scale were determined qualitatively
with a combination of energy dispersive spectrometry (EDS) spectra and maps.
Samples 1 and 3 are thermal spray coatings, and failure in these coatings typically
initiates by localized diffusion of the corrosive gas down the splat boundaries,
followed by subsequent attack at the coating/substrate interface. Samples 1 and 3
did not exhibit significant evidence of localized S penetration down the splat
boundaries when corrosion occurred underneath the deposit with an oxidizing gas
at 1200 oF. Samples 1 and 3 did show some evidence of localized S penetration
down the splat boundaries by direct gaseous attack with a reducing gas at 1200 oF
as shown in Figure 22 and 23.
3
Sample 3 – Corrosion Scale Zone
EDS Spectrum at Zone 1
Splat boundaries in the coating Area of the coating that is
farther away from the surface
EDS Spectrum at Zone 2 EDS Spectrum at Zone 3
1
2
3
Sample 3 – Corrosion Scale Zone
EDS Spectrum at Zone 1
Splat boundaries in the coating Area of the coating that is
farther away from the surface
EDS Spectrum at Zone 2 EDS Spectrum at Zone 3
1
2
Sample 3 – Corrosion Scale Zone
EDS Spectrum at Zone 1
Splat boundaries in the coating Area of the coating that is
farther away from the surface
EDS Spectrum at Zone 2 EDS Spectrum at Zone 3
1
2
Figure 22: Solid State Corrosion Test Results – 1200°F Oxidizing Conditions –
EDS Test Results on Sample 3
21
Cr
Ni
Mo
or S
Al
Fe
K
O
Si
Figure 1: EDS maps of the corrosion
scale and coating for sample three.
Cr
Ni
Mo
or S
Al
Fe
K
O
Si Figure 1: EDS maps of the corrosion
scale and coating for sample three at a
higher magnification.
Cr
Ni
Mo
or S
Al
Fe
K
O
Si
Figure 1: EDS maps of the corrosion
scale and coating for sample three.
Cr
Ni
Mo
or S
Al
Fe
K
O
Si Figure 1: EDS maps of the corrosion
scale and coating for sample three at a
higher magnification.
Figure 23: Solid State Corrosion Test Results – 1200°F Oxidizing Conditions –
EDS Map on Sample 3
It was not possible to separate the relative contributions from S and Mo within the
EDS X-Ray maps for sample 5, which is a weld overlay coating as shown in
Figures 23. However, there is no reason to expect significant localized S
penetration and corrosion within this sample.
22
Sample 5 – Corrosion Scale EDS Spectrum at Zone 1
Area of the Weld Overlay that is
farther away from the surface EDS Spectrum at Zone 3EDS Spectrum at Zone 2
1
2
3
Sample 5 – Corrosion Scale ZonesSample 5 – Corrosion Scale EDS Spectrum at Zone 1
Area of the Weld Overlay that is
farther away from the surface EDS Spectrum at Zone 3EDS Spectrum at Zone 2
1
2
3
Sample 5 – Corrosion Scale Zones
Figure 24: Gaseous Corrosion Test Results – 1200°F Reducing Conditions –
EDS Test Results on Sample 5
Fe Mo
or S
Cr
Ni O
Fe Mo
or S
Cr
Ni O
Figure 25: Gaseous Corrosion Test Results – 1200°F Reducing Conditions –
EDS Test Results on Sample 5
23
Erosion Test Results - Figures 25, 26 and 27 show the abrasion test results on the
coating samples (1 through 4) and weld overlay and carbon steel samples. Weld
Overlay and Coating Sample 2 are the relatively better erosion resistant materials
among all samples tested. Except for Weld overlay and coating sample No. 2, for
all other coating samples, the coating was abraded away exposing the base metal
for all test conditions. The as received coating sample No.3 showed some small
random orange spotting in the coating. The plates after testing showed some
minor reaction with the silicon carbide at the edges of the plate away from the
abrasion zone. The orange spotting was found to have a greenish hue after testing
at 1200°F. This observed minor reaction did not appear to affect the abrasion
testing. The complete Boiler Materials Report is also available separately as
Appendix C.
Figure 26: Comparison of Abrasion Area for Coating Samples 1 to 4 Tested
24
600 °F at 90°900 °F at 90°
1200 °F at 90°1200 °F at 45°
600 °F at 90°900 °F at 90°
1200 °F at 90°1200 °F at 45°
Weld Overlay After Erosion Test
Carbon Steel After Erosion Test
Carbon Steel Base Metal Sample No.
6
Inconal 625 Weld Overlay Sample No. 5
As Received Samples
600 °F at 90°900 °F at 90°
1200 °F at 90°1200 °F at 45°
600 °F at 90°900 °F at 90°
1200 °F at 90°1200 °F at 45°
Weld Overlay After Erosion Test
Carbon Steel After Erosion Test
600 °F at 90°900 °F at 90°
1200 °F at 90°1200 °F at 45°
600 °F at 90°900 °F at 90°
1200 °F at 90°1200 °F at 45°
600 °F at 90°900 °F at 90°
1200 °F at 90°1200 °F at 45°
600 °F at 90°900 °F at 90°
1200 °F at 90°1200 °F at 45°
Weld Overlay After Erosion Test
Carbon Steel After Erosion Test
Carbon Steel Base Metal Sample No.
6
Inconal 625 Weld Overlay Sample No. 5
As Received Samples Carbon Steel Base Metal Sample No.
6
Inconal 625 Weld Overlay Sample No. 5
Carbon Steel Base Metal Sample No.
6
Carbon Steel Base Metal Sample No.
6
Inconal 625 Weld Overlay Sample No. 5
Inconal 625 Weld Overlay Sample No. 5
As Received Samples
Figure 27: Comparison of Abrasion Area for Weld Overlay and Carbon steel
Samples Tested
0
1
2
3
4
5
6
7
Coating No.1 Coating No.2 Coating No.3 Coating No.4 Overlay 5 Crest Overlay 5 Valley Base Metal 6
Sample No.
Ab
ras
ion
Are
a,
inc
h^
2
600 F @ 90 Deg Impact 900 F @ 90 Deg Impact 1200 F @ 90 Deg Impact 1200 F @ 45 Deg Impact
0
1
2
3
4
5
6
7
Coating No.1 Coating No.2 Coating No.3 Coating No.4 Overlay 5 Crest Overlay 5 Valley Base Metal 6
Sample No.
Weig
ht
Lo
ss,
gr.
600 F @ 90 Deg Impact 900 F @ 90 Deg Impact 1200 F @ 90 Deg Impact 1200 F @ 45 Deg Impact
0
0.005
0.01
0.015
0.02
0.025
0.03
0.035
0.04
0.045
Coating No.1 Coating No.2 Coating No.3 Coating No.4 Overlay 5 Crest Overlay 5 Valley Base Metal 6
Sample No.
Maxim
um
Th
ickn
ess L
oss,
inch
600 F @ 90 Deg Impact 900 F @ 90 Deg Impact 1200 F @ 90 Deg Impact 1200 F @ 45 Deg Impact
Weld Overlay and Coating
Sample 2 are the relatively
better erosion resistant
materials among all samples
tested.
0
1
2
3
4
5
6
7
Coating No.1 Coating No.2 Coating No.3 Coating No.4 Overlay 5 Crest Overlay 5 Valley Base Metal 6
Sample No.
Ab
ras
ion
Are
a,
inc
h^
2
600 F @ 90 Deg Impact 900 F @ 90 Deg Impact 1200 F @ 90 Deg Impact 1200 F @ 45 Deg Impact
0
1
2
3
4
5
6
7
Coating No.1 Coating No.2 Coating No.3 Coating No.4 Overlay 5 Crest Overlay 5 Valley Base Metal 6
Sample No.
Weig
ht
Lo
ss,
gr.
600 F @ 90 Deg Impact 900 F @ 90 Deg Impact 1200 F @ 90 Deg Impact 1200 F @ 45 Deg Impact
0
0.005
0.01
0.015
0.02
0.025
0.03
0.035
0.04
0.045
Coating No.1 Coating No.2 Coating No.3 Coating No.4 Overlay 5 Crest Overlay 5 Valley Base Metal 6
Sample No.
Maxim
um
Th
ickn
ess L
oss,
inch
600 F @ 90 Deg Impact 900 F @ 90 Deg Impact 1200 F @ 90 Deg Impact 1200 F @ 45 Deg Impact
Weld Overlay and Coating
Sample 2 are the relatively
better erosion resistant
materials among all samples
tested.
Figure 28: Comparison of Abrasion Area, Minimum Thickness Loss, and
Weight Loss for all Samples Tested
25
CONCLUSIONS AND RECOMMENDATIONS
The conclusions derived from the above tests and are summarized below:
Multiple alloys systems tested in similar environments allow for
qualitative and quantitative ranking of materials and establish guidelines
for materials selection for design. The tests are complete and the samples
are being characterized for quantitative evaluation. Preliminary analysis
indicated accelerated degradation and hence an impact on oxidation curves
in IGCC environments. It is shown that the exposure in gaseous
environment does have a debit on oxidation rate of the bond coats, the data
shows 20 degree drop in oxidation temperature limit. The higher
aluminum containing alloys did have higher resistance to
oxidation/corrosion compared to the high chromium containing alloys.
Impact of ashes on TBCs and their chemical interactions are being
investigated as part of the program. Illinois fly ash melts above 1260°C
and hence complete infiltration is observed when samples are exposed
above that temperature. This infiltration is indicated in change in
thermomechanical properties of the coating. The impact of the ash
infiltration on TBC heat flux life and performance is planned for the future.
The current commonly used Inconel 625 Weld Overlay is the best for both
corrosion & erosion resistance simultaneously on boiler tubes. The bare
carbon steel sample had the worst corrosion resistance.
Coating Sample No.2 resulted as better erosion resistant material among
all 4 coating samples tested, but not as a good solid state corrosion
resistant material.
Coating Sample No.3 resulted as better solid state corrosion resistant
material among all 4 coating samples tested, but not as a good erosion
resistant material.
Overall the thermal sprayed coatings do provide a moderate protection
against corrosion and erosion compared to the Inconel 625 material, with
fraction of the cost.
The complete Boiler Materials Report is also available separately as Appendix C.
26
DISCLAIMER STATEMENT
This report was prepared by Anand A. Kulkarni, Siemens Energy Inc., with
support, in part, by grants made possible by the Illinois Department of Commerce
and Economic Opportunity through the Office of Coal Development and the
Illinois Clean Coal Institute. Neither Anand A. Kulkarni, Siemens Energy Inc.,
nor any of its subcontractors, nor the Illinois Department of Commerce and
Economic Opportunity, Office of Coal Development, the Illinois Clean Coal
Institute, nor any person acting on behalf of either:
(A) Makes any warranty of representation, express or implied, with respect to the
accuracy, completeness, or usefulness of the information contained in this
report, or that the use of any information, apparatus, method, or process
disclosed in this report may not infringe privately-owned rights; or
(B) Assumes any liabilities with respect to the use of, or for damages resulting
from the use of, any information, apparatus, method or process disclosed in
this report.
Reference herein to any specific commercial product, process, or service by trade
name, trademark, manufacturer, or otherwise, does not necessarily constitute or
imply its endorsement, recommendation, or favoring; nor do the views and
opinions of authors expressed herein necessarily state or reflect those of the
Illinois Department of Commerce and Economic Opportunity, Office of Coal
Development, or the Illinois Clean Coal Institute.