Volume 6 Preprint 89
Metallic Components in Coal-Gasification Fuel Gas Paths
P.J. Kilgallon, N.J. Simms, J.F. Norton and J.E. Oakey
Keywords: materials issues, gasifier, heat exchanger, filter, downtime corrosion, deposits
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Volume 6 Paper H045
Metallic Components in Coal-Gasification
Fuel Gas Paths
P.J. Kilgallon, N.J. Simms, J.F. Norton* and J.E. Oakey
Power Generation Technology Centre, Cranfield University, Cranfield,
Bedfordshire, MK43 OAL, UK, firstname.lastname@example.org * Consultant
in Corrosion Science & Technology, Hemel Hempstead, Herts, HP1 1SR
Gasification systems offer the potential to generate electricity from
coal much more efficiently and with substantially less environmental
impact (i.e. lower CO2, SOx, NOx and particulate emissions) than
conventional pulverised fuel combustion systems. There is a wide
variety of gasification processes and fuel gas path options that
continue to be investigated. However, the hot fuel gas path
environments produced by all these gasification systems have the
potential to be extremely aggressive for materials during plant
operation and downtime periods.
This paper reports on a series of tests carried out to investigate the
performance of candidate materials for two types of component in hot
fuel gas path environments i.e. the fuel gas cooler and metallic filter
elements. One series of laboratory tests was carried out for up to 3000
hours at temperatures in the range 450-550ºC in which materials were
exposed to gases that simulate both oxygen and air-blown
gasification systems. The materials in these tests were exposed both
bare and with a coverage of the appropriate deposit for the type of
gasification system. A second series of test was carried out to
investigate the downtime corrosion behaviour of candidate heatexchanger materials in which materials covered with a deposit were
exposed to humid atmospheres. A third series of tests was carried out
combining the first two test methods; i.e. materials were exposed
alternately to high temperature fuel gas environments and downtime
conditions. The performance of the materials in all these tests was
assessed using standard optical and SEM/EDX techniques, as well as
dimensional metrology. The combined results from these assessment
methods allowed the materials to be ranked in terms of their
performance in each of the types of test. The relative importance of
these different test methods in the selection of materials for different
fuel gas path components is discussed.
Keywords: materials issues, gasifier, heat exchanger, filter, downtime
A number of coal gasification systems have been developed [#ref01],
based on different types of gasification process, e.g. entrained flow,
fixed bed, oxygen blown fluidised bed. Variations on these processes
may use either oxygen or air as their oxidant in the gasifier vessel and
can be controlled to give varying degrees of conversion of the coal to
fuel gas, from complete (>99% conversion) to partial (e.g. 75%
conversion). Once generated, the fuel gases need to be cooled and
cleaned before use, e.g. being burnt in gas turbines. All gasification
technologies require a heat exchanger (often called either a syngas
cooler or fuel gas cooler) between the gasifier and the gas cleaning
system. The function of this heat exchanger varies depending on the
type of gasifier, gas cleaning requirements (e.g. hot dry cleaning or
wet scrubbing) and steam cycle needs. However, gasifier hot gas path
environments are potentially very aggressive for materials both during
plant operation and off-line periods. This has the effect of imposing a
temperature window for the safe operation of these heat exchangers
(with current materials restricting their use to modest steam
conditions and preventing their use as superheaters with commercially
viable lives). Thus, in different gasification systems evaporators are
used to produce saturated steam at 10 MPa/320 °C with metal
temperatures of 320-400 °C depending on the syngas temperature
[#ref02]. However, there is a drive towards raising evaporator steam
conditions to 18 MPa/350 °C, with corresponding metal temperatures
of 380-450 °C. Under these steam conditions, the use of highly
alloyed materials will be required to give economically viable heat
exchanger lives in gasifier hot gas paths [#ref03]. However, some
gasification cycles would be more efficient (and economically viable) if
at least some superheating could be carried out by a heat exchanger in
this location in the hot gas path: this would involve steam at
temperatures of 500-550 °C with corresponding metal temperatures of
550-600 °C [#ref02]. Both water tube and smoke tube heat exchanger
designs are reported in the literature for gasifier heat exchangers.
These radically diverse types of designs will have dissimilar
characteristics in terms of deposit formation, due to the different gas
flows around or through them. Significant differences in the hot gas
path environment exist between the various gasification systems
which utilise different fuels, but unfortunately these simply have the
effect of changing the balance between different potential degradation
modes arising. It is possible to carry out the gas cleaning by water
scrubbing the cooled fuel gases, but this leads to lower cycle
efficiencies and requires the provision of a scrubbing and waste-water
treatment facility, which generates liquid waste for later disposal. The
first generation gasification systems have been built to use water
scrubbing for gas cleaning. Hot dry gas cleaning, using barrier filters
to remove particulates and catalysts/sorbents to remove gaseous
species (e.g. sulphur, chlorine, ammonia), offer higher cycle
efficiencies as well as lower capital and operating/disposal costs.
However, hot dry gas cleaning is still at the developmental stage and
so only parts of the processes are included in the latest demonstration
There are many significant differences between the various gasification
systems [#ref01], both in terms of the operation of the actual
gasification process and the requirements for different downstream
components with different ranges of operating conditions. These give
rise to economic and efficiency differences between the systems that
are beyond the scope of this paper. However, from the perspective of
materials performance and optimum materials selection, the
component operating conditions and the environments produced in
each of the systems are critically important.
Table 1 lists published bulk gas compositions produced by some of
these gasification systems.
Table 1 Gasifier Gas Compositions
* Dependent on coal sulphur and chlorine content
Further differences arise from the minor and trace gas species which
are very important in determining materials performance, both
through direct reaction and indirectly through deposit formation and
subsequent reaction. The levels of these minor and trace gas species
in these gasification systems are rarely reported in the published
The majority of the coal gasification processes which have reached the
pilot and demonstration plant scale are based on pressurised oxygen
blown entrained flow slagging gasifiers [#ref04] but a number of air
blown pressurised fluidised bed gasification (PFBG) processes have
been developed. The use of partial gasification systems results in
hybrid cycles, in which unburnt carbon from the gasifier is burnt in a
combustor to raise steam for the steam cycle [#ref05-#ref07].
The overall aim of this study was to assess the potential corrosive
effects of deposits formed on heat exchangers and metallic filter
elements in ABGC and IGCC systems. The effects of deposits on High
Temperature Gaseous Corrosion (HTGC), Downtime Corrosion (DTC)
and synergistic interactions were assessed. This work helps to identify
the operating conditions and materials that could produce rapid
material failures due to interactions with the deposits formed during
gasification plant operation.
The performance of materials in various simulated and real coalgasification atmospheres has been investigated by research groups in
the US, Japan and Europe for more than 25 years [#ref02-#ref03,
#ref08-#ref25]. The initial generic studies investigated the
performance of materials in a range of highly reducing atmospheres
with varying levels of sulphidation at high temperatures. Later studies
have tended to concentrate on higher alloyed materials and/or lower
exposure temperatures. Following plant experience, more recent
studies have been targeted at increasingly realistic exposure
simulations to match the degradation morphologies observed in
Several potential degradation processes have been established during
the studies carried out in these types of environment [#ref02-#ref03,
elevated temperature gas phase induced corrosion: this
includes oxidation, sulphidation, carburisation/metal dusting
corrosion induced by surface deposits either as particles from
the gasifier or by species condensing onto those particles or
directly onto the component surfaces;
dewpoint corrosion: induced by high temperature deposits
absorbing moisture or gaseous species (such as HCl or H2S)
reacting with condensing water during part-load operation (to
form HCl and polythionic acids) or deposits forming on cooler
gas path surfaces;
downtime corrosion: induced by high temperature deposits
becoming damp during plant shut-down, gaseous species (e.g.
HCl, H2S, etc.) reacting with condensed water during plant shutdown (e.g. forming HCl and polythionic acids) or hygroscopic
deposits being exposed to damp air during plant shut-downs
(e.g. during the course of maintenance operations);
interaction of any of the above degradation modes with
mechanical factors, e.g. creep or fatigue, to produce synergistic
degradation, e.g. creep-corrosion or corrosion-fatigue;
spallation of corrosion products: of critical importance on the
clean side of the filter unit from where spalled scale may enter
the gas turbine and cause erosion damage.
In any gasification system, different combinations of degradation
mode will be found on components along the hot gas path due to
variations in operating temperature and local plant environment
(deposition, local gas composition, i.e. the extent of gas clean-up, gas
temperature at that point in the system, component temperature, etc.).
Most studies of materials in gasifier hot gas paths (mainly heat
exchangers materials) have targeted elevated temperature gas phase
induced corrosion with increasing levels of realism allowing the
successful development of predictive models for sulphidation /
oxidation [e.g. #ref15, #ref24-#ref25]. However, pilot plant tests have
shown that deposit covered components can suffer rapid failure due to
both dewpoint and downtime corrosion. Thus, it is important to avoid
(or at least minimise) damage by these degradation modes.
Table 2 gives the composition of the heat exchanger alloys and
metallic filter alloys used and also lists the alloys corresponding Pitting
Resistance Equivalent Number (PRENW (including tungsten)) as given
PRENW =%Cr+3.3(%Mo+0.5%W) +16% N
It has been established that the pitting behaviour of stainless steels
can be broadly related to composition using empirical relationships
such as PREN [#ref26]. Crevice corrosion is influenced by many
factors and therefore PREN is generally not so useful for prediction of
this type of behaviour. In the HTGC tests the AISI 316L and Hastelloy
X were in the form of Sintered Metal Powder (SMP).
Table 2. Compositions of Alloys (1Only tested in HTGC tests, 2not
tested in HTGC tests)
Nominal Composition (wt %)
4.6Al 0.3Si 0.25Y
0.5Si 0.5Cu 0.5Mn
30Co 2.7Si 1W 0.5Mn
18Co 2.4W 0.2N
1.5Co 1Si 1Mn 0.6W
3.8W 2.5Co 1Mn
High Temperature Gaseous Corrosion
HTGC tests using controlled atmosphere furnaces were carried out
using the parameters detailed in Table 3. Specimens were exposed to
either the ‘high H2S’ (= IGCC) or ‘low H2S’ 1 (= ABGC) simulated gases,
the gas compositions of which are given in Table 4. The components
of the test gas were supplied from two gas cylinders and mixed at the
entrance of the furnace. The moisture was added to the hydrogen
sulphide / carbon monoxide gas stream by bubbling the gas through a
heated flask containing deionised water.
Table 3. Test Parameters (*High = IGCC and Low = ABGC)
Gas H2S Level*
Table 4. Gas Compositions
Gas Compositions (vol.%)
‘Low H2S’ 1
‘Low H2S’ 2
Simulated deposits were applied to samples with a recoat interval of
1000 hours. Either the ‘High H2S’ 1 or ‘Low H2S’ 1 deposits (Table 5)
were used (i.e. to match the test gas). Samples were also tested
without an applied simulated deposit. These deposits were produced
by mixing the dry deposit components together with propan-2-ol to
produce a slurry. This slurry was applied to one side of the test
specimens and the solvent evaporated before testing. After testing,
maximum oxide thickness measurements were made on polished
cross-sections of samples using optical microscopy.
Table 5. Deposit Compositions
Deposit Compositions (wt.%)
‘High H2S’ 1
‘Low H2S’ 1
‘High H2S’ 2
‘Low H2S’ 2
Figure 1. Diagram of DTC Testing Setup.
DTC testing was carried out using a modified EPRI downtime corrosion
test using the setup shown in Figure 1. Specimens were coated with
the ‘Low H2S’ 1 deposit (Table 5) and were exposed to water saturated
air at 30 °C for 25 hour cycles. After exposure the deposit was
removed and the specimens cleaned and examined before the next
cycle. Longer cycles were also used to investigate whether the more
resistant materials had an initiation period greater than 25 hours.
Damage was assessed by visual inspection and depth of attack
measured microscopically [#ref27].
Samples were exposed to cycles of HTGC testing followed by DTC
testing for four cycles. The furnace exposure was for 500 hours at
400ºC in the ‘Low H2S’ 2 gas mixture (Table 4). DTC exposure was for
100 hours at 70ºC. Deposits with composition ‘Low H2S’ 2 (Table 5)
were applied prior to the furnace exposure.
Results & Discussion
High Temperature Gaseous Corrosion
The results of the HTGC testing are shown in Figures 2 to 4. The
maximum oxide thickness was used as the measure of damage in the
HTGC tests as the sulphide layer was incorporated with the deposit.
Figure 2 gives the maximum oxide thickness for the 3000 hour test at
450ºC in the simulated IGCC gas. During this test the Hastelloy X
specimen (SMP) was removed after 2000 hours with a maximum oxide
thickness corresponding to 100% of the metal particle size. After
3000 hours the AISI 316L (SMP) also had a maximum oxide thickness
corresponding to the metal particle size.
Figure 3 gives the maximum oxide thickness for the 1000 hour test at
550ºC test in the simulated IGCC gas. As above, the Hastelloy X
specimen has a maximum oxide thickness corresponding to 100% of
the metal particle size. Comparison of Figures 2 and 3 indicate the
effect that the test temperature increase from 450 to 550 ºC had (even
though the test times differ). Overall the damage to the materials is
comparable between these tests indicating similar oxide thicknesses
after 1000 hours at the higher temperature compared with those
measured after 3000 hours at 450 ºC.
Figure 4 gives the maximum oxide thickness for the 1000 hour test at
550ºC test in the simulated ABGC gas. Comparing Figures 3 and 4
clearly shows that the IGCC gas is far more aggressive than the ABGC
gas towards the majority of the materials. However, the damage on
the Fecralloy and AISI 310 samples was comparable for both gas
compositions even when a deposit was present.
In Figures 2-4 the effect of the applied deposits compared to the case
without deposit is mixed. The deposits either cause an increase in the
oxide thickness or for some alloys appears to be protective. For some
alloys the effect of the deposit is severe.
The data generated by this part of the work can be used for material
selection and/or setting plant operating conditions. The failure
criteria used for the lifetime calculations will depend on the material
form and location in the system. For example, wastage of a heat
exchanger or oxide/sulphide blocking of filter media pores, use
different life-assessment criteria.
Maximum Oxide thickness (µm)
Figure 2. High H2S gas at 450 ºC 3000 hours (Hastelloy X only 2000
hours) (Shaded is without deposits and unshaded with deposits)
Maximum Oxide thickness (µm)
Figure 3. High H2S at 550ºC 1000 hours (Shaded is without deposit
and unshaded with deposits)
Maximum Oxide thickness (µm)
Figure 4. Low H2S at 550ºC 1000 hours (Shaded is without deposit and
unshaded with deposit) (no bar indicates <1µm)
The severity of attack on the materials tested varied significantly with
Alloy 800H and AISI 316L being the most severely attacked, as shown
in Figure 5. In general the attack was a mixture of pitting and crevice
corrosion but Alloy 800H also showed intergranular attack. The other
materials showed little or no attack and no effect of increasing the test
cycle time from 25 to 75 hours was evident. AISI 310 had many more
pits than Haynes 160 (only one pit) and Sanicro 28. Alloy 800H was
very severely attacked over almost all of the exposed surface; a feature
of this damage was that over areas of intense attack a thin hard black
layer had formed. The attack on the AISI 316L changed from an
under-deposit/crevice type observed for periods of up to 50 hours to
predominately pitting after longer exposures. The ranking of the
overall resistance of the materials to the DTC test matches the PRENW
ranking well (Table 2).
Figure 5. Measured Damage on Samples During DTC Testing (Bars1-3
for each material are 50, 75 and 100 hours respectively)
The DTC test is more applicable to heat exchanger material testing
than metallic filters. Heat exchangers have a uniform surface
constructed from one or two materials that is well represented by the
DTC test. Metallic filters can have many materials in various forms
e.g. fibre, mesh, plate etc. in their construction. This more complex
system could lead to galvanic interactions between materials, surface
area effects and a more complex crevice/under-deposit system.
The data obtained in the synergistic tests are given in Figure 6. A
number of the alloys have been severely damaged. This HTGC/DTC
synergy is only one of the many combinations of synergistic conditions
that could be expected. The complex exposure environments within
gasification systems, combined with the mechanical duties of the
various components, make it highly likely that other synergistic
influences may play an additional role. There are many possible
combinations of exposure variable that could lead to enhanced
materials degradation. For example, the metallic filters would be
exposed to thermal cycling due to pulse cleaning and start-up/shutdown cycles possibly leading to corrosion fatigue. Only limited studies
have been carried out on such synergistic damage modes . This is
a topic that requires much more thorough study for gasifier hot gas
Figure 6. Damage Measured on Samples in Synergistic Tests – Four
cycles of 500 hours at 400ºC / 100 hours at 70ºC (unshaded bar is
typical and shaded bar is maximum)
Several series of HTGC, DTC and combined HTGC/DTC tests have been
carried out for conditions representing IGCC and ABGC gas coolers
and metallic filters. Specific conlusions from these tests are:
In the HTGC tests in the IGCC gas changing the temperature
from 450 to 550ºC caused a significant increase in the corrosion
experienced by all alloys tested.
For a number of alloys, HTGC tests with deposits was more
damaging than tests without deposits.
The data indicates longer lives for components in ABGC systems
than IGCC systems.
In the DTC tests, a good agreement was found for pitting
corrosion with the ranking predicted by PRENW.
In HTGC testing (400ºC) incorporating a DTCA period, many of
the alloys showed significant damage.
Alloys selected for gasification plant usage need to have a
combination of both high temperature and downtime corrosion
Synergistic testing in gasification environments requires more
extensive study to elucidate particularly damaging conditions
being encountered during plant operation.
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