Corrosion of air preheater tubes of oil shale CFB boiler. Part II. Laboratory investigation of temperature impact.
IntroductionAs generally known, metal temperature of the air-preheater tubes depends on both temperatures: of the air flowing outside and flue gases flowing inside the tubes. Consequently the lower the temperature of the air entering the air-preheater, the lower the temperature of the wall of air-preheater tubes, that in turn increases the intensity of flue gas cooling. Decrease of flue gas temperature increases the efficiency of the boiler. Generally low-temperature corrosion starts at the dew point of sulphuric acid. It is well known by now that CFB boilers utilizing Estonian oil shale bind most of sulphur compounds during the combustion process, and the concentration of S[O.sub.2] and S[O.sub.3] in flue gases is very low. In this case low-temperature corrosion of air-preheater tubes is apparently caused by chlorine compounds. Corrosion rate of the tubes is dependent on the temperature of the tube wall. However, data about the effect of the tube wall temperature on corrosion of the airpreheater tubes of oil shale CFB boilers are lacking. Therefore the objective of the given work was to perform laboratory corrosion tests at different temperatures of the metal in order to find out the optimal temperature of tube walls for safe operation of the air preheater.
Experimental
Flat specimens for laboratory testing of corrosion (Fig. 1) had been made from carbon steel St 33 which is used for manufacturing of air-preheater tubes. The tests were carried out in the atmosphere of air and water steam in the presence of oil shale ash, taken from the air-preheater bin of the CFB boiler. 167-h and 500-h tests were conducted at 75, 90, 100 and 110[degrees]C. The starting temperature 75[degrees]C was chosen as the dew-point temperature of flue gases of PF oil shale boiler according to investigation [1].
The tests at 75, 90 and 100[degrees]C were performed in an exsiccator placed into an electrically heated oven (Fig. 2a). The exsiccator was partially filled with water. The specimen and oil shale ash were placed into a special glass capsule, the bottom of which was a filter that let the steam pass through the ash layer (Fig. 2b, 2c). The capsule was set on the perforated shelf of the exsiccator above the level of the water. Thus, the steam flowed to the specimen immersed into the oil shale ash in the capsule. The test temperature in the oven was maintained automatically with the accuracy of [+ or -] 2[degrees]C.
In the case of testing temperature of 110[degrees]C the test was performed in a container of the diameter of 60 mm, into which the capsule with testing specimen immersed into the oil shale ash had been placed. The container was connected to the steam boiler (steam sterilizer [LAMBDA]E-100-3m) that allowed maintaining the steam pressure in the range of 1.0-2.2 bars (Fig. 3a). During the test the steam pressure was initially set at 1.5 bars that corresponded to the saturated steam temperature of 110.8[degrees]C.
[FIGURE 1 OMITTED]
[FIGURE 2 OMITTED]
It was found that in the container oil shale ash in the presence of saturated steam had firmly hardened by 24 hours of testing. At the next stage, in order to avoid hardening of the ash, the operating steam pressure in the boiler was set at 1.0 bar. Steam was heated to the temperature of 110[degrees]C by means of an additional electrically heated pipe which connected the boiler and the container with the specimen (Fig. 3b). In this case the superheated steam passed through the ash containing the specimen, and the ash did not harden firmly. It has allowed to maintain testing temperature of the steam at the level of 110 [+ or -] 2[degrees]C and to carry out the test successfully without ash hardening.
[FIGURE 3 OMITTED]
Corrosion depth of the specimens was determined on the basis of mass change ([DELTA]m, g) by weighing the clean degreased specimens before and after testing. Prior to weighing of the tested specimen, corrosion products and oxide scale were completely removed from the surface of the specimen in the 10% solution of ammonium citrate. The specimens were weighed by means of balances with the accuracy of 0.0001 g. On the basis of the decrease in specimen mass specific material loss (q, g/[cm.sup.2]) was determined. Finally, according to [2], corrosion depth ([DELTA]S, mm) of the specimens was calculated using the following equation: [DELTA]S = 1.28.
Results and conclusions
The results of laboratory corrosion tests are presented in Table 1 and Fig. 4. For comparison of testing results a well-known factor has been used, namely corrosion rate V, mm/year. As one can see, the maximum corrosion rate is at the temperature of 90[degrees]C. The subsequent increase in the testing temperature leads to the decrease of corrosion rate, and at the temperature of 110[degrees]C the tested specimens practically do not suffer from corrosion. The specimens taken after corrosion testing at the temperatures of 75 and 110[degrees]C are presented in Fig. 5.
[FIGURE 4 OMITTED]
[FIGURE 5 OMITTED]
Thus, the results of the laboratory corrosion testing of carbon steel St 33 at different temperatures allow to recommend the metal temperature of the tubes located in the area of the air inlet into the air-preheater of the oil shale CFB boilers to be held at the level of 105-110[degrees]C. However, it should be noted that in the conducted experiments oil shale ash from the air-preheater bin of the CFB boiler was used, while the ash deposits on the surface of the air-preheater tubes could consist of finer particles. Such deposits are able to bind chlorine from flue gases and hence to cause more intensive corrosion of the tubes than can the coarser grained ash from the air-preheater bin [3].
Presented by M. Uus Received August 26, 2008
REFERENCES
[1.] Ots, A., Gavrilov, A., Randmann, R. A study of fouling of low-temperature heating surfaces in burning Estonian oil shale // Teploenergetika. 1972. No. 11. P. 76-78 [in Russian].
[2.] RTM 108.030.116-78 Standards for Determination of Corrosive Resistance of Boiler Alloys at Elevated Temperatures [in Russian].
[3.] Arro, H., Prikk, A., Kasemetsa, J. Grain composition and corrosive activity of ash from CFB oil shale boiler // Oil Shale. 1997. Vol. 14, No. 3 Special. P. 225-235.
H. TALLERMO, I. KLEVTSOV, A. DEDOV *
Department of Thermal Engineering Tallinn University of Technology 116 Kopli St., 11712 Tallinn, Estonia
* Corresponding author: e-mail dedov@staff.ttu.ee
Table 1. Results of laboratory corrosion tests of steel St 33
t, [tau], h [DELTA]m, g q, g/
[degrees]C [cm.sup.2]
75 167 0.14 0.016
75 167 0.14 0.016
75 167 0.21 0.023
75 167 0.25 0.028
75 500 0.63 0.074
75 500 0.55 0.066
90 167 0.477 0.053
90 167 0.500 0.055
90 500 0.709 0.079
90 500 0.663 0.073
100 167 0.033 0.004
100 167 0.032 0.004
100 500 0.101 0.011
100 500 0.088 0.010
110 500 0.000 0.000
110 500 0.001 0.000
t, [DELTA]S, mm V, mm/year
[degrees]C
75 0.020 1.059
75 0.021 1.087
75 0.030 1.550
75 0.035 1.847
75 0.094 1.653
75 0.084 1.472
90 0.068 3.582
90 0.070 3.661
90 0.101 1.777
90 0.094 1.643
100 0.005 0.248
100 0.005 0.237
100 0.015 0.255
100 0.013 0.224
110 0.000 0.000
110 0.000 0.002
t--testing temperature, [degrees]C
[tau]--test duration, h
[DELTA]m--change of specimen mass, g
q--change of specimen mass per unit of area, g/[cm.sup.2]
[DELTA]S--corrosion depth, mm
V--corrosion rate, mm/year
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| Title Annotation: | circulating fluidized bed |
|---|---|
| Author: | Tallermo, H.; Klevtsov, I.; Dedov, A. |
| Publication: | Oil Shale |
| Article Type: | Report |
| Geographic Code: | 1USA |
| Date: | Mar 1, 2009 |
| Words: | 1335 |
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