turbine and boiler materials development for ...a number of concepts have been employed to enable...

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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.

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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

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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

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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.

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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.

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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.

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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.

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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

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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.

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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.

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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

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

Time


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

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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)


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)



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


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


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 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






1

2






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 –


Fe Mo

or S

Cr

Ni O

Fe Mo

or S

Cr

Ni O

Figure 25: Gaseous Corrosion Test Results – 1200°F Reducing Conditions –


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°



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°




6


As Received Samples Carbon Steel Base Metal Sample No.

6



6


6



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


Sample No.

Weig

ht

Lo

ss,

gr.


0

0.005

0.01

0.015

0.02

0.025

0.03

0.035

0.04

0.045


Sample No.

Maxim

um

Th

ickn

ess L

oss,

inch


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


Sample No.

Ab

ras

ion

Are

a,

inc

h^

2


0

1

2

3

4

5

6

7


Sample No.

Weig

ht

Lo

ss,

gr.


0

0.005

0.01

0.015

0.02

0.025

0.03

0.035

0.04

0.045


Sample No.

Maxim

um

Th

ickn

ess L

oss,

inch


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.

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