Hiroshi YAKUWA*
Manabu NOGUCHI*
*
Technologies, R&D Division
This paper outlines high temperature corrosion and corrosion protection for a power recovery turbine for oil refinery plants (FCC gas expander turbine). The paper describes operating conditions for FCC gas expander turbines and characteristics of high-temperature sulfidation-corrosion behavior of UNS N07001 (Ni-base heat resistant alloy) used in turbine rotors. Furthermore, it introduces prevention measures, such as a chromium diffusion osmotic treatment and a steam cleaning system, and development of a sulfidation-corrosion resistant alloy (RK1000).
Keywords: High temperature corrosion, Sulfidation corrosion, Grain boundary corrosion, Power recovery turbine, Gas expander, Nickel base alloy, Chrome diffusion coating, Fluid catalytic cracking unit, Hydrogen sulfide, Sulfur dioxide
Gas expander turbines constitute one kind of industrial turbine and can be roughly classified into two types according to the purpose of use: Cryogenic turbines and power recovery turbines. Cryogenic turbines remove heavy components from a working gas through reduction in temperature of the gas itself during gas adiabatic expansion. They are known as air separation expanders and natural gas liquefaction expanders. On the other hand, power recovery turbines recover kinetic energy from a working fluid. They are also known as blast furnace top pressure recovery turbines, which use exhaust gas from the blast furnace, and FCC gas expander turbines, which use the exhaust gas from the catalyst regenerator of a fluid catalytic cracking (hereafter, FCC) unit (a gasoline-producing unit) 1). In an FCC unit, the exhaust gas is generated at high temperature during the regeneration process of the catalyst, with a pressure energy of 98-206 kPa. Thus, because of strong demand for power recovery as well as heat recovery from waste heat boilers, an FCC gas expander turbine was developed in 1963 2). Since then, such turbines have been increasingly used. Today, more than 100 turbines are operating around the world. In the beginning, FCC gas expander turbines had a big problem with catalyst scattered from the FCC unit wearing down the rotor blades 3)-6). This problem required extensive time and labor to develop countermeasures. On the other hand, in the early 1990s, the high temperature sulfidation corrosion due to hydrogen sulfide or sulfur dioxide included in the working fluid made headlines. It was reported from overseas that fracture accidents of turbine rotor blades had occurred arising from that corrosion 7). Subsequently, Ebara and the Elliott Group established prevention measures through their diligent research on high temperature sulfidation corrosion in gas expanders 8)-15).
This paper outlines the problem of high temperature sulfidation corrosion in FCC gas expander turbine rotors and prevention measures developed by Ebara and the Elliott Group.
Figure 5-1, Figure 5-2, and Figure 5-3 show the appearance and cross-sectional view of an FCC gas expander turbine, and the gas system diagram of an FCC unit, respectively 16). Both the single-stage and multistage types of FCC gas expander turbines are axial flow type turbines. In an FCC gas expander turbine, rotor blades that carry a heavy load are particularly subject to high temperature corrosion. The rotor blades and disc fitting part, where the temperature can reach up to a relatively low 873 K, require high corrosion resistance and high temperature strength; therefore they are constructed from UNS N07001 (Waspaloy: a registered trademark of United Technologies, Inc.), an Ni-base alloy, or Alloy 738LC. In applications involving lower operating temperatures (about 823 K), UNS S66286 (A286), an Febase alloy, may be used. Table 5-1 shows the chemical compositions of these alloys.
On the other hand, the chemical composition of exhaust gas from a catalyst regenerator is either completely combusted or partially combusted, depending on whether the regenerator is operating in ‘complete combustion mode’ or ‘partial combustion mode’ 17). Table 5-2 shows compositions of exhaust gas in each mode. Figure 5-4 18) shows an Ni and Cr-S-O equilibrium diagram with sulfur partial pressure (PS2
) and oxygen partial pressure (PO2
) at 873 K. Since Ni-oxide and Ni-sulfide become stable in complete combustion mode and partial combustion mode, respectively, it is expected that corrosion state and behavior vary, depending on the operating conditions of the regenerator.
Fig. 5-1 Appearance of FCC gas expander turbine <sup>16）</sup>
Fig. 5-2 Cross-sectional view of FCC gas expander turbine <sup>16）</sup>
Fig. 5-3 FCC exhaust gas system diagram <sup>16）</sup>
Fig. 5-4 Ni and Cr-S-O equilibrium diagram with <em>P<sub>O2</sub><em> and </em>P<sub>S2</sub></em> (873 K) of exhaust gas from the catalyst regenerator<sup>18）</sup>
| Ni | Cr | Co | Mo | W | Ta | Nb | Al | Ti | Fe | C | B | Zr | |
| UNS N07001 | bal. | 19.5 | 13.5 | 4.3 | − | − | − | 1.3 | 3.0 | − | 0.08 | 0.006 | 0.06 |
| UNS S66286 | 26.0 | 15.0 | − | 1.3 | − | − | − | 0.2 | 2.0 | bal. | 0.05 | 0.015 | |
| Alloy 738LC | bal. | 16.0 | 8.5 | 1.7 | 2.6 | 1.7 | 0.9 | 3.4 | 3.4 | − | 0.11 | 0.010 | 0.05 |
| O2 | N2 | H2O | CO | CO2 | H2 | H2S | SOx | |
| Partial combustion mode | Trace | 60-70 | 13-20 | 2-9 | 8-14 | 0.2-0.4 | 0-0.03 | 0-0.01 |
| Complete combustion mode | 0.5-3.8 | 62-76 | 7-24 | 0-0.1 | 13-14 | Trace | Trace | 0-0.15 |
As described above, several heat resistant alloys are used in FCC gas expander turbine rotors. High temperature sulfidation corrosion behavior is described below focusing on UNS N07001 alloy.
As shown in Figure 5-4, in partial combustion mode, sulfide is more stable than oxide in the gas composition. Accordingly, sulfide is produced in priority to oxide and the corrosion rate becomes relatively high. Figure 5-5 18) shows a typical corrosion morphology found on a UNS N07001 alloy blade used for a plant operating in partial combustion mode. The thickness of the entire surface does not reduce uniformly, but Crenriched sulfide grows inside the alloy, forming notches along the grain boundary of the alloy. Grain boundary, notch-formed corrosion is often found on the rotor blades and disc fitting part, which are subject to large external stress from centrifugal force.
Figure 5-6 shows backscattered electron images of cross-sections of the interface between UNS N07001 alloy and scales that were sulfidized in a mixed gas of N2-3%H2-0.1%H2S at 873 K (PS2
= 10-3.6 Pa at 600 °C) under a stress load (Figure 5-6 (a)) and no load (Figure 5-6 (b)) 9), 18). As shown above, no significant grain boundary corrosion is found under no load, while under stress load, the grain boundary of the alloy that is vertically closer to the main stress axis will be preferentially corroded. Grain boundary, notch-formed corrosion grows almost according to the parabolic law as shown in (Figure 5-7) 9). However, as shown in Figure 5-8 19), in an environment at a sulfur partial pressure of 10-3.4 ～ -3.6 Pa, grain boundary corrosion occurred at an oxygen partial pressure of less than 10-30 Pa, while uniform corrosion occurred at an oxygen partial pressure of 10-18.5 Pa. Likewise, in an environment at a sulfur partial pressure of 10-0.2 ～ -0.8 Pa, grain boundary corrosion occurred at an oxygen partial pressure of less than 10-18.5 Pa, while uniform corrosion occurred at an oxygen partial pressure of 10-12.4 Pa. Thus, when the oxygen partial pressure is high, grain boundary corrosion does not occur unless at a high sulfur partial pressure. In addition, the lower the temperature becomes, the less grain boundary corrosion occurs. At 773 K, even under a stress load, significant grain boundary corrosion is rarely found (Figure 5-9) 9).
Fig. 5-5 Corrosion morphology of a gas expander turbine blade found in a partial combustion mode <sup>18）</sup>
Fig. 5-6 Corrosion morphology of N07001 alloy under a stress load and no load <sup>9），18）</sup> (873 K, in a mixed gas of N<sub>2</sub>-3%H<sub>2</sub>-0.1%H<sub>2</sub>S, 345.6 ks)
Fig. 5-7 Time dependency of the depth of grain boundary corrosion formed on N07001 alloy <sup>9）</sup> (873 K, σ= 588 MPa, 345.6 ks, in N<sub>2</sub>-3%H<sub>2</sub>-0.1%H<sub>2</sub>S)
Fig. 5-8 Influence on corrosion morphology of N07001 alloy by <em>P<sub>S2</sub></em> and <em>P<sub>O2</sub></em> <sup>19）</sup> (873 K, σ = 588 MPa, 345.6 ks)
Fig. 5-9 Corrosion morphology of UNS N07001 alloy at 773 K <sup>9）</sup> (in a mixed gas of N<sub>2</sub>-3%H<sub>2</sub>-0.1%H<sub>2</sub>S, σ = 588 MPa, 345.6 ks)
As shown in Figure 5-4, in complete combustion mode, oxide is more stable than sulfide. Accordingly, the corrosion rate is lower than that in partial combustion mode. Furthermore, grain boundary, notch-formed corrosion, which is found partial combustion mode, is rarely observed. However, even if oxide forms on the surface, the oxygen partial pressure lowers at the interface between the oxide and alloy, and sulfide may be produced. There have been some reports that this occurred to corrosion of Ni 20)-22), Ni-base alloy 23), and, Febase alloy 24) in environments containing SO2. Even if the equilibrium sulfur partial pressure is low, in a plant emitting a large amount of sulfur oxide (SOx), corrosion may grow to pitting like corrosion, producing sulfide and oxide alternately in a tree-ring form, as shown in Figure 5-10 18). Corrosion producing sulfide and oxide alternately in a tree-ring form is reproduced in a mixed gas of N2-10ppmO2-0.75%SO2 (PS2
＝ 10-20.2, PO2
= 10-2.4 Pa at 600 °C), which simulates a complete combustion mode (Figure 5-11) 25).
On the other hand, even in complete combustion mode, when the O2 content is relatively low (less than about 1 %) and the CO content is a little higher (about 1 %), sulfide may become stable by a slight change in gas composition. Figure 5-12 18) shows an Ni-S-O diagram with PO2 and PS2
at 873 K when the CO and O2 contents in the gas composition are changed to 1.0-1.5 % and 0.2-0.6 %, respectively. Figure 5-12 shows that when the CO content becomes 1.3 % or more, or when the O2 content becomes 0.4 % or less, sulfide becomes stable. In other words, even in complete combustion mode, if the O2 content is relatively small, or if the CO content is relatively large, it is suggested that a small change in O2 or CO concentration may cause the thermodynamic stabilized phase to change to sulfide from oxide. Under these circumstances, characteristics of corrosion in oxidizing and reducing environments appear at the same time. Accordingly, for predicting the corrosiveness in an environment, it is important to analyze the environment, including longer term gas variations, not in a single gas analysis, but in multiple gas analysis on a regular basis.
In addition, in an environment in complete combustion mode, deposition of sulfide (internal sulfidation) inside the alloy was confirmed in closed space. Figure 5-13 shows the corrosion that occurred on a test specimen simulating a gas expander blade/disc fitting part in a mixed gas of N2-10ppmO2-0.75%SO2 at 873 K (PS2 = 10-20.2 Pa, PO2
= 10-2.4 Pa at 600 °C). On the exposed surface of the part (Figure 5-13 (a)), like the corrosion shown in Figure 5-11, pitting-like corrosion producing sulfide and oxide alternately, which is peculiar to an oxidizing environment, was found, but no internal sulfidation was observed. In contrast, on the test specimen of disc fitting part (Figure 5-13 (b)), obvious internal sulfidation was found, which indicates that internal sulfidation affected the inside of the alloy along the grain boundary of the alloy.
This sulfidation could be caused by the following mechanisms: since the gas is not fully supplied to the disc fitting part to which the gas is not fully supplied, S2 produced by the reaction of [SO2 + 2Ni → 2NiO + 1/2S2]...(1) does not diffuse to the gas phase bulk, and the bulk does not readily supply new SO2 ; therefore, PS2 -PO2
that is estimated from the gas phase bulk composition cannot be maintained, and S2 diffuses to the inside of the alloy causing internal sulfidation.
As described above, complete combustion mode produces milder corrosion than partial combustion mode. It is significant, however, that when the SO2 concentration is high, sulfide may be produced at the interface between the alloy and scales or inside the alloy.
Fig. 5-10 Corrosion morphology of N07001 alloy found in a complete combustion mode <sup>18）</sup>
Fig. 5-11 Corrosion morphology of UNS N07001 alloy in an oxidizing environment at 873 K <sup>25）</sup> (in N<sub>2</sub>-10ppmO<sub>2</sub>-0.75%SO<sub>2</sub>（<em>P<sub>S2</sub></em>＝10<sup>-20.2</sup>，<em>P<sub>O2</sub></em>＝10<sup>-2.4</sup> Pa）, σ ＝ 588 MPa, 345.6 ks)
Fig. 5-12 Changes in <em>P<sub>O2</sub></em> and <em>P<sub>S2</sub></em> corresponding to changes in CO and O<sub>2</sub> concentrations (873 K, 1 atm) <sup>18）</sup>
Fig. 5-13 Internal sulfidation morphology of UNS N07001 alloy in an oxidizing environment at 873 K (in N<sub>2</sub>-10ppmO<sub>2</sub>-0.75%SO<sub>2</sub>（<em>P<sub>S2</sub></em>＝10<sup>-20.2</sup>，<em>P<sub>O2</sub></em>＝10<sup>-2.4</sup> Pa）, σ = 588 MPa, 345.6 ks) (a) surface exposed part of test specimen (b) test specimen of the disc fitting part
Gas expander turbine blades are subject to fluctuating stress due to gas bending stress whenever they pass stator blades during rotor rotation. Distinct striations were found on the fracture surfaces of the fractured blades, which suggests that cracks were developed by fatigue after the development of grain boundary corrosion. Thus, we investigated how the gas atmosphere affects the high temperature fatigue behavior of UNS N07001. Figure 5-14 (a) and (b) show cross sections of test specimens (UNS N07001) to which repeated stress (σ= 196±118 MPa, 50 Hz) was applied in N2-3%H2-0.1%H2S (PS2 = 10-3.6 Pa at 600 °C) and N2-10ppmO2-0.75%SO2 (PS2 = 10-20.2, PO2 = 10-2.4 Pa at 600 °C). In N2-3%H2-0.1%H2S, a reducing environment (Figure 5-14 (a)), corrosion occurred forming sharp notches in a relatively short time.
In N2-10ppmO2-0.75%SO2, an oxidizing environment (Figure 5-14 (b)), corrosion formed broad notches. Compared with the former, the latter requires at least ten times the period and repetitions of stress to reach the same depth as the former. As described above, in a “high PS2
- low PO2
” environment, it is suggested that sharp notches are likely to develop under repeated stress and may cause degradation of the fatigue strength.
Fig. 5-14 Corrosion morphology of UNS N07001 alloy under repeated fluctuating stress σ = 196 ±118 Mpa, 50 Hz, 873 K, (a) in N<sub>2</sub>-3%H<sub>2</sub>-0.1%H<sub>2</sub>S（<em>P<sub>S2</sub></em>＝10<sup>-3.6</sup> Pa），43.2 ks，2.16×10<sup>6</sup> cycles， (b) in N<sub>2</sub>-10ppmO<sub>2</sub>-0.75%SO<sub>2</sub>（<em>P<sub>S2</sub></em>＝10<sup>-20.2</sup>，<em>P<sub>O2</sub></em>＝10<sup>-2.4</sup> Pa），691.2 ks，3.45×10<sup>7</sup> cycles
As described above, where stress is concentrated on the rotor blades and disc fitting part, sulfidation corrosion progresses, forming notches along the grain boundary of the alloy. There are two views concerning the mechanism of fracture starting from the corrosion tip.
One is that cracks begin from sulfidation corrosion along the grain boundary of the alloy and develop due to corrosion fatigue, resulting in fracture. The authors 26) analyzed the fracture surface of a gas expander turbine blade in detail and observed the striation patterns. We pointed out that fatigue is involved in the fracture because the macro fracture surface is flat and because of evidence of fan-like fracture growth. In other words, as shown in Figure 5-15, they inferred that fracture occurred due to fatigue (or corrosion fatigue), starting from the crack tip caused by sulfidation corrosion. Meanwhile, in the laboratory, the initial crack length of the crack growth threshold 26) obtained in the laboratory air was longer than the corrosion notch length obtained from observation of the cross section of actual equipment. However, since the initial crack length of the crack growth threshold was obtained in the air in the laboratory and the notch corrosion from which the fracture started was likely to be deeper than other corrosion observed at cross sections (not starting points of fracture), we conclude that cracks are likely to grow because of fatigue (or corrosion fatigue) starting from the tip of notch-formed corrosion.
The other view is that when notch-formed corrosion becomes deep, the stress intensity factor at the tip of notch exceeds the lower limit of stress corrosion cracking (K1, SCC
). Dowson, et al., 15) focused on the fact that the corrosion at the rotor blades and disc fitting part varies, depending on location, and thought that these variations arise from the catalyst scattered from the FCC unit. The catalyst includes S 27), Sb and Pb 28), 29), which degrade the mechanical characteristics of Ni-base alloy. For this reason, they conducted creep rupture tests for N07001 alloy, and found that when the creep rupture time becomes extremely short, intergranular cracking occurs in notches. From this result, they confirmed that the depth of the notch-formed corrosion meets the conditions for blade fracture, comparing K1,SCC
in the catalyst of N07001 alloy with the stress intensity factor at the tip of notch-formed corrosion obtained from the depth.
Regardless of whether the direct cause of fracture is fatigue (or corrosion fatigue) or embrittlement cracking, fracture starts from notch corrosion due to high temperature corrosion. In addition, high temperature corrosion with a lower crack growth rate than that of fatigue and embrittlement cracking must determine the rupture life time of the blade. Accordingly, we conclude that control of high temperature corrosion is the key to a longer lifetime of gas expander turbine blades.
Fig. 5-15 Diagram of an expected fracture process of gas expander blade
Table 5-3 18) shows a qualitative evaluation of characteristics of high temperature corrosion resistant coatings applied for gas expander turbine rotors. A gas expander turbine rotor requires coating on its rotor blades and disc fitting part. Although these have complex shapes, high dimensional accuracy is necessary. Accordingly, thermal spraying or the like is not suitable, because film thickness control is difficult. Furthermore, since rotor discs are large with diameters of 850-1400 mm, physical vapor deposition (PVD) is not economically feasible. Thus, chromium diffusion coating is used, since control of film thickness is relatively easy, even if the target has a complex shape and the treatment is applicable to large components 30).
Figure 5-16 shows an SEM image of a cross section of N07001 alloy with chromium diffusion coating 8), 30). A chromium layer and a chromium diffusion layer, which are slightly less than 10 µm, are observed from the surface toward the inside of the alloy. Figure 5-17 shows mass changes of materials with/without chromium diffusion coating affected by sulfidation. Compared with N07001 alloy without chromium diffusion coating, N07001 alloy with the coating shows excellent corrosion resistance in reducing environments (a) and (b), and an oxidizing environment (c). In a reducing environment (b), which have an oxygen partial pressure of about 10-18.5 Pa equal to the actual operating conditions, and oxidizing environment (c), increase in mass was rarely observed. This could be because the chromium diffusion layer can maintain its highly protective oxide film in low oxygen environments. In other words, it is suggested that even in plants operating in partial combustion mode, excellent corrosion resistance could be ensured in low oxygen actual operating conditions. Eventually, on blades with chromium diffusion coating that were actually used for about two years, the chromium layers have remained without conspicuous damage, which proves that this treatment shows excellent high temperature corrosion resistance, when used on gas expander blades 30).
| Method | Processed material | Sulfidatio resistance | Adhesiveness of coating layer | Adhesiveness of corrosion product | Applicability to gas expanders | Film thickness (μm) | Comprehensive evaluation | |
| Blade | Disc | |||||||
| Diffusion coating | Cr | ○ | ○ | ○ | ○ | ○ | 10 to 50 | ○ |
| Al | ○ | ○ | △ | ○ | ○ | 10 to 50 | △ | |
| Physical vapor deposition (PVD) | MCrAlY | ○ | △ | ○ | △ | × | 5 to 30 | × |
| Plasma spraying | △ | × | ○ | △ | △ | 100 to 400 | × | |
| Low-pressure plasma spraying + diffusion treatment | ○ | ○ | ○ | △ | △ | 100 to 400 | × | |
○: Suitable △: Acceptable ×: Not acceptable
Fig. 5-16 Cross section of N07001 alloy with chromium diffusion coating
Fig. 5-17 Corrosion mass change of N07001 alloy with chromium diffusion coating (873 K, 345.6 ks)<sup>18）</sup>
As shown in Figure 5-9, the rate of high temperature corrosion on FCC gas expander turbine blades decreases as the temperature drops. Therefore, corrosion can be reduced by application of steam with the working gas to lower the temperature on the rotor surface. Also, forming a steam barrier on the rotor surface by increasing the amount of steam may be taken as another method for preventing corrosive gases from contacting the rotor blades and disc fitting part 15).
Yakuwa, et al.,10）～14），31），32）found that a few percent of Ti and Al added to N07001 alloy have a large influence on the sulfidation corrosion behavior, after minutely examining the relationship between the high temperature sulfidation corrosion characteristics of N07001 alloy and alloy elements at 873 K. Figure 5-18 12), 14) shows influence by the alloy elements of Ni-20Cr-13.5Co-4Mo alloy on increase in mass due to sulfidation at 873 K/ PS2
=10-5.5 Pa. This indicates that sulfidation corrosion of Ni-20Cr-13.5Co-4Mo alloy is enhanced by added Ti and is suppressed by added Al. In short, it suggests that the sulfidation corrosion resistance of N07001 alloy can be improved by reducing Ti and increasing Al in the chemical composition of the alloy.
On the other hand, UNS N07001 is a γ’ precipitationhardening Ni-base alloy. It is also known that its high temperature strength characteristics depend on the precipitation amount of γ’ phase (Ni3 [Al, Ti]). Based on the above, Yakuwa, et al., 13), 14) have developed a sulfidation corrosion resistant alloy for gas expander turbine rotors with improved sulfidation corrosion resistance and strength characteristics equal to those of N07001 alloy. The key to success is decreasing the Ti content of N07001 alloy and increasing the Al content that is the equal amount of the decreased Ti in order to make theγ’ precipitation amount equal, as shown in Figure 5-19. Figure 5-20 shows high temperature tensile characteristics of a conventional N07001 alloy and the newly developed sulfidation corrosion resistant alloy (1.5Ti-3.0Al alloy called RK1000). The figure indicates that their characteristics (tensile strength, 0.2 % yield stress, elongation, and reduction of area) are almost the same as those of N07001 alloy. The predicted time to 1 % creep, estimated from stress relaxation tests (Figure 5-21) 12), also indicates that RK100 alloy has creep strength equal to or greater than that of N07001 alloy. On the other hand, Figure 5-22 13) shows a sulfidation corrosion behavior under stress loading conditions. Even under conditions where N07001 alloy is fractured in less than 20 hours and accompanied by severe grain boundary corrosion, in the case of RK1000 alloy, the depth of the produced grain boundary corrosion was 10 µm or less, and no fracture occurred in a 96-hour corrosion test. Furthermore, in a creep test in a catalyst conducted by Dowson 33), K1,SCC
of RK1000 alloy was about three times larger than that of N07001 alloy; therefore, the former has excellent resistance to embrittlement cracking in a catalyst.
Yakuwa, et al., 13), 34) believe that the excellent grain boundary sulfidation corrosion resistance of RK1000 can be attributed to precipitation characteristics of grain boundary carbide. Figure 5-23 34) shows grain boundary corrosion of N07001 alloy observed by transmission electron microscope (TEM). Cr23C6 carbide was continuously precipitated on the grain boundary of the alloy; the carbide was sulfidized to form Cr3S4. Resulting from research on the number of occurrences of grain boundary sulfidation corrosion of the solution treatment materials and aged materials of N07001 and RK1000 alloys at different solution treatment temperatures, as shown in Figure 5-24 13), it is found that much grain boundary corrosion occurs, if N07001 and RK1000 alloys are aged after solution treatment at 1313 K and 1353 K (higher temperature for RK1000), respectively. This corresponds to the fact that, after carbide precipitated during forging was dissolved in the alloy substrate, it continuously precipitates again on the grain boundary of the alloy during aging 13). That is to say, compared with N07001 alloy, RK1000 produces less carbide dissolved in the alloy substrate at a high solid solution temperature of Cr23C6 carbide during solution treatment. For this reason, less carbide would be precipitated again on the grain boundary during aging. Thus, the grain boundary sulfidation corrosion behaviors of RK1000 and N07001 alloys can be explained schematically, as shown in Figure 5-25 13). For example, if N07001 alloy is subject to solution heat treatment at 1313 K, much solid solution of carbide precipitated during forging is produced and then continuous M23C6 carbide is precipitated on the grain boundary during aging. When it is exposed to a sulfidizing atmosphere, grain boundary corrosion will be promoted by preferential sulfidation of carbide. In the case of RK1000, since the solid solution temperature of carbide is higher than that of N07001 alloy, less solid solution of carbide precipitated during forging is produced and less carbide is precipitated on the grain boundary during aging. Therefore, it is difficult for carbide to exist on the grain boundary continuously; grain boundary corrosion is not likely to be produced by preferential sulfidation of carbide.
As described above, RK1000 developed for FCC gas expander turbine blades has mechanical characteristics equivalent to those of N07001 alloy and provides excellent grain boundary sulfidation corrosion resistance. It has already been used in gas expander turbines as an alternative to N07001 alloy.
Fig. 5-18 Influence by the alloy elements of Ni-20Cr-13.5Co-4Mo alloy on increase in mass <sup>14）</sup> (873 K, in H<sub>2</sub>S-H<sub>2</sub> （<em>P<sub>S2</sub></em>＝10<sup>-5.5</sup> Pa）, 176.4 ks)
Fig. 5-19 Concept of development of sulfidation corrosion resistant alloy for gas expander turbine rotors
Fig. 5-20 High temperature tensile characteristics of UNS N07001 and RK1000 alloys (811 K, in air)
Fig. 5-21 Larson-Miller master curves of predicted time to 1 % creep of N07001 and RK1000 alloys from stress relaxation tests <sup>12）</sup>
Fig. 5-22 Cross sections of notches of N07001 and RK1000 alloy test specimens corroded under a stress load (aged materials, σ = 588 MPa, in N<sub>2</sub>-3%H<sub>2</sub>-0.1%H<sub>2</sub>S gas, 873 K, 345.6 ks) <sup>13）</sup>
Fig. 5-23 TEM/EDS analysis of the tip of grain boundary corrosion of N07001 alloy <sup>34）</sup> (1313 K→ aging, <em>P<sub>S2</sub></em>＝10<sup>-3.6</sup> Pa, 873 K, 345.6 ks, σ = 588 MPa)
Fig. 5-24 Number of grain boundary corrosion formed on N07001 and RK1000 alloys <sup>13）</sup> <em>P<sub>S2</sub></em>＝10<sup>-3.6</sup> Pa, 873 K, 345.6 ks, no load
Fig. 5-25 Grain boundary sulfidation corrosion models of N07001 and RK1000 alloys <sup>13）</sup>
This paper outlines high temperature sulfidation corrosion and corrosion protection for a gas expander turbine rotor to recover the power of the FCC unit in oil refinery equipment, mainly using examples from Ebara. It is a summary of a series of studies under the tutelage of Toshio Narita, an honorary professor at Hokkaido University. We used information about actual machines provided by gas expander users in oil refinery companies and as well as benefitting from much advice from them. In addition, Metallurgical Research Laboratory and Yasugi Works of Hitach Metals, Ltd., provided us with full support for the development of sulfidation corrosion resistant alloy (RK1000). We are grateful to everyone who cooperated with us.
As described in this paper, corrosion behaviors have almost been greatly clarified and effective corrosion protection has been instituted. However, in the future, new issues may appear because of changes in fuel, process, or catalyst. We hope that this paper will help the further development of corrosion protection and further improvement of reliability of machinery.
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