Experiences with high temperature corrosion at straw-firing power plants in Denmark

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1 Materials and Corrosion 2010, 61, No DOI: /maco Experiences with high temperature corrosion at straw-firing power plants in Denmark M. Montgomery*, S. A. Jensen, U. Borg, O. Biede and T. Vilhelmsen By the end of 2009, there will be eight biomass and five biomass co-firing plants in Denmark. Due to the steep increase of corrosion rate with respect to temperature in biomass plants, it is not viable to have similar steam data as fossil fuel plants. Thus for the newer plants, Maribo Sakskøbing, Avedøre 2 biomass boiler, Fyn 8 and Amager 1 (Fyn 8 and Amager 1 are under commissioning), the steam temperature of the final superheaters are approximately 540 8C and the steel type used is an stainless steel, (TP347H). However there is still a need to monitor corrosion rates, and to collate data to enable better lifetime prediction of vulnerable components in straw-firing plants since the corrosion rates are so much faster than in coal firing plants. Therefore, there are continued investigations in recently commissioned plants with test tubes installed into actual superheaters. In addition temperature is measured on the specific tube loops where there are test tube sections. Thus a corrosion rate can be coupled to a temperature histogram. This is important since although a superheater has a defined steam outlet temperature, there is variation in the tube bundle due to variations of heat flux from the flue gas. This paper will describe the corrosion investigations for tube sections removed from Maribo Sakskøbing and Avedøre 2 biomass boiler which have been exposed for up to h. In addition to monitoring the corrosion rates of actual components, there is a need to measure corrosion rates at higher temperatures to assess if there is a possibility to increase the outlet temperature of the plant, thus making the plant more cost effective. For this purpose Avedøre 2 biomass boiler has a test superheater loop fabricated in TP347H FG (the same material as the final superheaters). Some results from this test superheater will also be described. Effects of flue gas temperature and flue gas direction on corrosion rates are also discussed. 1 Introduction M. Montgomery Vattenfall Heat Nordic/DONG/DTU Mekanik, 2800 Lyngby (Denmark) S. A. Jensen DONG Energy, Copenhagen (Denmark) U. Borg DONG Energy, Frederici Q1 (Denmark) O. Biede Vattenfall Heat Nordic, Copenhagen (Denmark) T. Vilhelmsen Vattenfall Heat Nordic, Odense (Denmark) Biomass has had increasing use in Denmark since the 1990s as shown in Table 1. Biomass such as straw and woodchip is considered a carbon dioxide neutral fuel and does not result in an increase in CO 2 emissions over a short time period. Denmark has concentrated its efforts on straw-firing since it does not have large forest areas like the other Scandinavian countries. There are currently eight straw-fired plants in operation and one woodchip boiler. In addition there are also five co-firing plants (Table 1). Danish wheat straw has been used as fuel at Avedøre 2 bioboiler and Maribo Sakskøbing; a typical analysis of Danish wheat straw is given in Table 2 [1]. Many field investigations have been undertaken into corrosion due to straw combustion in Denmark over the past ß 2010 WILEY-VCH Verlag GmbH & Co. KGaA, Weinheim

2 2 Montgomery, Jensen, Borg, Biede and Vilhelmsen Materials and Corrosion 2010, 61, No Table 1. Biomass and co-firing plants in Denmark Plant description Type Steam temp. 8C Pressure MPa Size MW th Commissioned Haslev Grate-fired Slagelse Grate-fired Rudkøbing CHP 100% straw Grate-fired Masnedø CHP almost 100% straw Grate-fired Ensted CHP % straw boiler Grate-fired % woodchip Maribo Sakskøbing CHP: 100% straw (a) Grate-fired Avedøre 2 Grate fired Bioboiler: 100% straw (a) Fyn 8: 100% straw Grate fired Grenå 50% CFB straw, 50% coal CFB Studstrup suspension fired coal plant modified for coal þ 10% straw Suspension fired rebuilt Unit rebuilt Unit 3 Avedøre II Suspension fired main boiler: oil þ gas þ wood Herning Wood þ gas Grate-fired rebuilt to biomass Amager I multifuel straw pellets, coal, wood pellets, heavy fuel oil Suspension fired (a) Plants where data are described in this paper. 15 years, and details can be found in these publications [2 13]. This paper will describe more recent results from Maribo Sakskøbing (MSK) and Avedøre 2 bioboiler (AVV2 bio) and compare them to results from previous investigations. With respect to high temperature corrosion, the major problem from straw-firing and in many cases woodchip firing is the presence of chloride containing deposits. When straw is combusted, sulphur dioxide and potassium chloride are released resulting in KCl and K 2 SO 4 deposits on superheater components. Potassium chloride within the deposit reacts with oxides or SO 2 to release Cl 2. The released chlorine then migrates through the protective oxide to react with alloying constituents, preferentially with Cr due to chromium s high affinity for chlorine. With increasing temperatures it is assumed that Cr chlorides/ oxychlorides evaporate from the metallic surface resulting in a porous metallic structure and high corrosion rates which limit the outlet steam temperature of a plant to 540 8C [12]. 2 Experimental procedure In both Maribo Sakskøbing [15 18] and Avedøre 2 bioboiler [19 21], corrosion investigations have been planned during plant Table 2. Typical Danish wheat straw composition [1] Parameter Min Max Average Typical H 2 O (%) Ca (%, dry) K Na Cl S Si fabrication and sections of superheater have been measured before exposure. The sections investigated in MSK and AVV2 bio are TP347H (18%Cr, 10% Ni) coarse-grained (ASTM grain size no 6) and TP347H fine-grained (ASTM grain size no 8), respectively. In addition the outlet and inlet temperature of the tubes is monitored by thermcouples in the penthouse such that exact temperature profiles of the tubes where the measured specimens are located, can be documented. Most of the specimen sections had been machined at either end to give a less variable wall thickness for more accurate corrosion measurements and then measured with a micrometer screw. For AVV2 bio, there were control specimens which had been cut from the machined ends of the tube before the tubes were welded into the superheater loop. It is noted that especially slow corrosion processes and short corrosion times are affected greatly by cold deformation of the surface (machining) and this has been observed for steam oxidation[14]. However it is believed that because corrosion is so fast in these particular environments, the effect is not so significant; this assumption has been verified by comparing measured machined and measured non-machined specimens[17]. After various exposure periods, the specimens were removed and sectioned in the areas where there were preexposed measurements. The sections were prepared according to normal metallographic techniques however without the use of water. The residual metal thickness was measured after exposure in 24 positions clockwise around the specimen where 12:00 is the flue gas direction. Based on these measurements, the metal loss could be calculated (Fig. 1). The sound metal loss is a sum of actual material loss þ selective corrosion þ grain boundary attack. Selective internal attack can only be measured by microscopic analysis of a cross-sectioned specimen and can be up to 0.5 mm. For some results given for Avedøre 2 bioboiler, measurement of tube thickness with a micrometer is undertaken and this only gives results for material loss. ß 2010 WILEY-VCH Verlag GmbH & Co. KGaA, Weinheim

3 Materials and Corrosion 2010, 61, No Experiences with high temperature corrosion 3 Figure 1. Schematic diagram and light optical micrograph of corrosion attack 3 Maribo Sakskøbing Maribo Sakskøbing combined heat and power plant is situated in Lolland, Denmark and was formerly owned by Energy E2 and is now owned by DONG Energy. Both superheaters 2 and 3 have been fabricated from TP347H coarse-grained. For superheater 2, the dimensions are outer diameter mm 2 thickness and for superheater 3, the dimensions are outer diameter mm 2 wall thickness. For the test sections, about 0.5 mm was removed from machining and then the machined specimens were accurately measured. For the central banks of both superheater sections, the steam inlet is the outer tubes closest to the rear wall and steam is led around the loop to the front wall (see Fig. 2). The steam is then pooled together and then distributed to the inner tubes close to the front wall and the outlet is the inner tubes close to the rear wall. Test sections were welded in superheater 2 and 3 in the inner tube at the rear wall close to the outlet when the plant was commissioned. Thus the outlet temperatures measured for these tubes in the penthouse where there is no heat flux is an acceptable temperature measurement for the steam for these sections. Sections have been removed after 1, 2, 4, and 6 years[15 18]. The exposure duration is defined as hours that the exit steam temperature from superheater 3 is above 500 8C. This is to accommodate the fact that the boiler may be kept warm at weekends where it is not actually in operation Temperature measurements It was observed from previous in situ exposures[7] that corrosion rate has a high variation especially above the 520 8C steam temperature range. Therefore to obtain reliable corrosion data, good temperature data are also required. Thus at Maribo Sakskøbing, there are thermocouples at the outlet of selected tubes (including on tubes where corrosion specimens are taken) such that temperature and corrosion rates can be directly correlated. For superheater 2 and 3, steam temperatures have been measured in the penthouse for different tubes in different banks. Superheater 2, consists of 8 banks with 15 tubes, where bank 4 and 5 are the middle banks directly over the combustion zone. The outermost tube is Tube 1 (inlet tube) and the innermost tube is tube 15 (outlet tube) and these incur the highest heat flux and can be designated as leading tubes where one side is not shielded. However tube 1 is an inlet tube and therefore the hottest tube in each bank is tube 15. For superheater 2, despite the similar inlet temperatures for the eight banks, the outlet temperatures for example for bank 4 (508 8C) and bank 2 (483 8C) can differ by 25 8C (Fig. 3). This is probably due to differences in flue gas temperature across the boiler and the fouling or the shielding of tubes. Superheater 3 consists of 8 banks of which banks 2 7 have 17 tubes, where tube 17 is the innermost outlet tube and therefore the hottest tube. For superheater 3, the outlet temperature differs by 10 8C from the middle (548 8C) to outer banks (538 8C) shown in Fig. 4. There is more control of the superheater 3 outlet temperature as the average temperature is regulated to be 540 8C. The outer tube of bank 6 where the test sections were located is shown as a dotted pink line. There is a higher variation in outlet temperature for superheater 2 as this is located in the first pass over the combustion zone. In addition tube 15 is only shielded on one side compared to tube 14 and therefore is more exposed to the effect of flue gas. From the data in Fig. 4 it is clear that the temperature is higher in bank 4 (548 8C) and probably also bank 5 than bank 6 (543 8C) where the test sections are located so it could be assumed that the corrosion rates would also be higher. Figure 5 and Fig. 6 are temperature profiles for the test sections shown in Fig. 2 showing a broader and more variable temperature range for superheater 2 than superheater 3 for the exposure times from 2000 to The peak temperature is used to correlate temperature to metal loss. It has also been observed that a higher flue gas temperature can affect the corrosion rate [7]. For this reason, the flue gas temperature is measured at the position marked in Fig. 2 and is depicted in Fig. 7. Variations in flue gas temperature span over 150 8C. To highlight the dynamics within a plant, a low superheater temperature in the 1st pass in (Fig. 5) presumably due to the low flue gas temperatures, i.e. lower heat uptake (Fig. 7) results in a slightly higher superheater temperature for superheater 3 (Fig. 6) Corrosion measurements Specimens from Maribo Sakskøbing had been machined and measured using a micrometer gauge in eight places before exposure. The residual metal thickness was measured after exposure in 24 positions clockwise around the specimen and the metal loss based on pre-exposure measurements are given in Fig. 8. (12:00 is the flue gas direction.) Likewise similar measurements have been compared for superheater 3 in Fig. 9. The purple dotted line shows a non-machined specimen which has only been measured. The difference in metal loss is similar as two machined specimens exposed for the same time period. ß 2010 WILEY-VCH Verlag GmbH & Co. KGaA, Weinheim

4 4 Montgomery, Jensen, Borg, Biede and Vilhelmsen Materials and Corrosion 2010, 61, No Figure 2. Schematic of Maribo Sakskøbing showing steam flow through superheaters and location of test sections. Bank 1 and 8 in superheater 3 have a different steam flow compared to the other banks and are not depicted in this diagram 4 Avedøre 2 biokedel Avedøre 2 CHP (combined heat and power) plant located on the island of Sjælland in Denmark was commissioned in 2001, and was formerly owned by Energy E2 and Vattenfall but is now owned by DONG Energy. Avedøre 2 comprises of three modules a large USC (ultra super critical) plant, a parallel-powered gas turbine and a biomass plant. The steam pressure of the biomass boiler is 310 bar and it has been fuelled with straw only. Test sections were welded into the actual superheaters of Avedøre 2 bioboiler as shown in Fig. 10. These test sections are in tube 1 of bank 12 of superheater 2 and 3, i.e. in the middle of the plant where the flue gas should be hottest. In addition there are three test superheater loops in the superheater 2 and 3 areas. They are designated HAH94, HAH95, and HAH96 and are located between 23 permanent banks: HAH94 is located between banks 4 and 5, HAH95 between 11 and 12 (directly over the combustion zone for superheater 2) and HAH96 between banks 19 and 20. Various sections have been investigated from superheaters 2 and 3, both from the test superheater loops and the permanent superheater[19, 20, 21]. Some of the results will be presented for comparison purposes with Maribo Sakskøbing. AVV2 bio has a more complicated steam flow where both tubes 1 and 7 are sometimes not shielded by other tubes either on the inner or outer side as shown in Fig.10a. In contrast to Maribo Sakskøbing, the steam is not pooled in superheater 2 so after traversing ß 2010 WILEY-VCH Verlag GmbH & Co. KGaA, Weinheim

5 Materials and Corrosion 2010, 61, No Experiences with high temperature corrosion 5 Inlet bank 2, tube 14 outlet bank 2, tube 15 outlet bank 4, tube 14 outlet bank 4, tube 15 outlet 1000 Frequency in hours Temperature C Figure 3. Temperature profiles measured for superheater 2 for a 1-year period at Maribo Sakskøbing Frequency in hours bank 2, 9 outlet Inlet bank 4, 16 outlet bank 6, 17 outlet (test section) Temperature C bank 2, 17 outlet bank 4, 9 outlet bank 4, 17 outlet Figure 4. Temperature profiles measured for superheater 3 for a 1-year period at Maribo Sakskøbing around the outer part of the loop, the same steam flows through a specific tube although the tube numbers change, i.e. inlet-tube 15!tube 14!tube 1!outlet, and inlet-tube 21! tube 8! tube 7!outlet. For superheater 3 there are 24 tubes, after the first journey around the loop in the outer tubes, the steam is pooled, and then is divided to the middle set of tubes and then continues to the inner set. The inlet is close to the front of the boiler and outlet is at the rear. The test superheater loops are single loops where the inlet is at the front of the boiler and the outlet is the rear wall of the 1st and 2nd pass, respectively. After the initial exposure in (6864 h), it was found that superheater 2 had a higher corrosion rate than anticipated. Consequently tube 1 and tube 7 were shortened to reduce heat uptake. Frequency in hours Superheater 2: bank 6 - outlet tube Temperature in C Figure 5. Comparison of temperature profiles over 6 years from bank 6, superheater 2 (where test sections are located) at MSK ß 2010 WILEY-VCH Verlag GmbH & Co. KGaA, Weinheim

6 6 Montgomery, Jensen, Borg, Biede and Vilhelmsen Materials and Corrosion 2010, 61, No Frequency in hours Superheater 3: bank 6 - outlet tube Temperature in C Figure 6. Comparison of temperature profiles over 6 years from bank 6, superheater 3 (where test sections are located) at MSK Metal loss in mm hrs 9284 hrs hrs not machined hrs hrs hrs 12:00 01:30 03:00 04:30 06:00 Location on tube 07:30 09:00 10:30 Figure 9. Metal loss for superheater 3 sections from Maribo Sakskøbing based on pre-exposure measurements Frequency in hours Comparison of flue gas temperature in combustion chamber Temperature C 4.1. Temperature measurements 1200 Figure 7. Temperature of the flue gas in the first pass of Maribo Sakskøbing measured over six consecutive years 1300 Similar to MSK, there are online temperature measurements in the penthouse for various tubes in the superheaters. However there is no flue gas temperature measurement in the 1st pass. The flue gas temperature is measured after superheater 3 and is in the region of C. The flue gas temperature measured by FTIR measurements [22] was C (compared to the Cat MSK approximately in the same place[23]). This decreased to C within the superheater regions for AVV2 bio. The steam temperature for superheater 2 for tubes 1 and 7 are revealed in Fig. 11. It is clear that for superheater 2, it is tube 7 that is hottest ( C). This tube has been the outer tube which has the highest surface area and is directly in contact with the high heat flux from the flue gas. In comparison tube 1 ( C) is an unshielded tube on the inner side of the bank. After commissioning it was clear that the heat uptake for superheater 2 was too high as can be seen from the temperature measurements. This led to a replacement of tube 1 and tube 7 with shorter tubes so that their heat uptake was reduced. As can be seen, this reduced the temperature in superheater 2 to C from 2003 however tube 7 is still marginally hotter than tube 1. Removal of the tubes 1 and 7 meant that the test sections were also removed. For superheater 3 (Fig. 12), the temperature difference of tube 1 ( C) and 7 ( C) is not so large. In superheater 3, the steam is pooled after the journey through the outer loop, and the steam temperature is the same for the inlet in all of the middle tubes. Thus tube 1, the half unshielded tube in the inner loop has the highest temperature Corrosion measurements Metal loss in mm : hrs 9284 hrs hrs hrs hrs 01:30 03:00 04:30 06:00 Location on tube 07:30 09:00 10:30 Figure 8. Metal loss for superheater 2 sections from Maribo Sakskøbing based on pre-exposure measurements Sections in the actual superheater The corrosion morphology observed is similar to that for previous investigations of straw fired plants [12]. Sections were removed from superheater 2 and superheater 3 and the metal loss was measured. The results are compared with results from Maribo Sakskøbing in the discussion. High corrosion rates were observed for tube 1 and 7 in superheater 2 in due to the high temperatures. The external diameter of the loops of tube 1 and tube 7 from bank 12, superheater 2 revealed that the tube decreased gradually and was the highest at the outlet which would have had the highest steam temperature (Fig. 13). Tube 7 had approx. 2 mm greater metal loss in external diameter compared to tube 1. This can be explained by the higher steam temperature measured for tube 7. ß 2010 WILEY-VCH Verlag GmbH & Co. KGaA, Weinheim

7 Materials and Corrosion 2010, 61, No Experiences with high temperature corrosion 7 Figure 10. Schematic diagrams of Avedøre 2 bioboiler showing steam flow through superheaters and position of test superheaters (TSH) Two of the test sections from tube 1 superheater 2 were investigated together with sections from tube 1 superheater 3. Figure 14 reveals the material loss of the tube wall based on preexposure measurements with a micrometer screw and post exposure measurements with microscopy. Superheater 2 wall thickness had a material loss of up to 1.5 mm and based on Fig. 13 where the metal loss from the external diameter of tube 7 is 2 mm more than tube 1, the metal loss for tube 7 wall thickness is estimated to be up to 2.5 mm in 6864 h (1 mm extra metal loss in tube wall thickness which corresponds to a corrosion rate of 0.36 mm/1000 h). It is also clear that for superheater 2, the highest metal loss is in the 3:00 position, i.e. not in the flue gas direction but on one of the sides of the superheater 2. For superheater 3, high metal loss is observed in the 12 3 o clock positions Failed test loop at Avedøre The test loop HAH96, which had significant fluctuations in temperature and in had a temperature around 600 -C, failed in Figure 15 shows the pieces received, and where there were both failures at the bottom of test superheater 2 and in the first leg of test superheater 3. Figure 16 illustrates the outer diameter measurement of the failed sections from test superheater 2 and 3. The measurements indicate that test superheater 3 failed first due to its decrease in outer diameter to 25 mm (original outer diameter specification 31.8 mm). Measurements of wall thickness for the failed section (Fig. 17) reveal the large variation in corrosion rates around the circumference where the tube has failed. Tube 4 and the adjacent section of tube 3 from test superheater 3 has a worst case wall thickness between 1 and 2 mm along a 1 m stretch (at least) and failure could have occurred in any part of this area. For test superheater 2 there is a small area of cm where there has been a high corrosion rate before failure. It is assumed that once there has been a leak in test superheater 3, this leads to lack of cooling for test superheater 2 which then quickly leads to failure in the area where there is the highest flue gas temperature. It is also interesting to note that failure does not occur at the outlet in test superheater 3 which ß 2010 WILEY-VCH Verlag GmbH & Co. KGaA, Weinheim

8 8 Montgomery, Jensen, Borg, Biede and Vilhelmsen Materials and Corrosion 2010, 61, No SH2 Bank 12 Tube SH2 Bank 12 Tube SH2 bank 12 Tube SH2 bank 12 Tube Number of Hours < 450 C C C C C C C C C C C C Temperature C C C C Figure 11. Temperatures measurement for and for superheater 2 at AVV 2 bio C C C C C should have the highest steam temperature but in the middle of the tube where heat flux is probably higher than at the outlet. There is a marked difference in wall thickness around the circumference as revealed when comparing average wall thickness with worst case wall thickness Fig. 17. This indicates that one side of the tube has been more corroded than the other side, probably due to the variations in flue gas flow and heat flux. This is shown clearly in Fig. 18 which is from the specimen closest to the failure in superheater 3. It is believed that the orientation is correct, however it is difficult to verify this, as tubes had been twisted due to the failure and the high pressure steam leakage. The test sections located close to the outlet were investigated for test superheater 3 and the average worst case residual metal thickness is 3.1 mm for the test sections in HAH96 compared to mm for the failed section. Thus the area of failure has been subjected to higher surface metal temperatures SH3 Bank 12 Tube SH3 Bank 12 Tube SH3 Bank 12 Tube SH3 Bank 12 Tube Number of hours < 450 C C C C C C C C C C C C C Temperature C C C Figure 12. Temperatures measured in from and for superheater 3 at AVV 2 bio C C C C C C ß 2010 WILEY-VCH Verlag GmbH & Co. KGaA, Weinheim

9 Materials and Corrosion 2010, 61, No Experiences with high temperature corrosion 9 AVV2 bio SH2 bank 12 Tube 1 and penthouse at outlet close to inlet External diameter in mm Tube 1 Tube Distance from the outlet in cm Figure 13. Measurements of external diameter from tube 7 and tube 1, bank 12 from superheater 2, AVV2 bio Metal loss in mm :00 AVV2 material loss 03:00 06:00 Position 09:00 OH2 tube 1 OH3 tube 1 Figure 14. Metal loss of wall thickness of sections removed from AVV2 bio after exposure for leading to higher corrosion rates compared to the outlet section which should have higher steam temperatures. It can be seen that for the superheaters and test superheaters in AVV2 bio, the position of most corrosion is not always around 12:00 as observed for superheater 3 in MSK. The test superheater is a single superheater loop (not shielded by the bulk of the superheater bank) and may have a different ash may be deposited on it in different locations than on the tubes in the actual superheater banks. Also different boilers will have different flow dynamics which could ultimately influence ash deposition and corrosion rates. 5 Discussion HAH96 SH2 HAH96 SH3 The corrosion morphology observed is similar to previous results[5, 6, 12]. Accelerated corrosion attack and selective corrosion occurs presumably due to the presence of potassium chloride. A non-protective oxide forms on the surface of the alloy consisting of iron, chromium, and nickel. Below this selective chromium depletion and grain boundary Q2 attack occurs as shown in Fig, 1. In this work, corrosion of TP347H coarsegrained and TP347H fine-grained is compared. These two materials have very different steam oxidation rates [14] however where the two materials have been included in the same tests they have revealed similar corrosion rates in straw-firing boilers [17]. It is suggested that although initial corrosion rates may be different, with the fast corrosion rates measured in the boilers discussed in this paper, the two materials are comparable Effect of steam temperature Figure 15. Test superheater HAH96 failed in December 2006 from AVV2 bio The corrosion rates and extrapolation for h exposure are given in Fig. 19 for AVV2 bio and MSK data. Thus the 5 8C difference for AVV2 bio SH3 and MSK SH3 results in a greater increase in corrosion rate compared to the increase of 33 8C from MSK SH2 and MSK SH3. After h, the metal loss is ß 2010 WILEY-VCH Verlag GmbH & Co. KGaA, Weinheim

10 10 Montgomery, Jensen, Borg, Biede and Vilhelmsen Materials and Corrosion 2010, 61, No a) b) 34 External diameter in mm Tube 9 Tube 10 External diameter in mm Tube 4 Tube Distance in cm from fracture Test Superheater Distance in cm from fracture Test superheater 3 Figure 16. Measurement of outer diameter in the failed sections of test superheater HAH96, AVV2 bio Wall thickness in mm Tube 4-50 Failed test loop HAH96 Superheater 3 Tube Distance from fracture (cm) 100 Average worst case Worst case Average Figure 17. Measurement of wall thickness in the failed section of HAH96 test superheater 3 from AVV2 bio Wall Thickness in mm :00 01:00 02:00 03:00 04:00 05:00 06:00 07:00 08:00 09:00 10:00 11:00 Position around the circumference 150 E1B053 TSH3 HAH96 Sound metal orignal thickness Figure 18. Variation in corrosion rate around the circumference of the tube for HAH96 test superheater 3 close to failure from AVV2 bio Metal loss in mm AVV2 SH2 Steam Temp approx 538 C Exposure time in hours AVV2 SH3 Steam Temp 548 C MSK SH3 Steam Temp 543 C AVV2 OH2 AVV2 OH3 MSK OH2 MSK OH3 MSK SH2 Steam Temp approx 510 C Figure 19. Metal loss for Avedøre 2 bio and Maribo Sakskøbing estimated to be 3.9 mm in superheater 3 and 1.3 mm in superheater 2 for MSK compared to 6.3 mm in AVV2 bio SH3. Thus slight increases in temperature in the steam temperature range of 540 8C are more significant than those at lower temperatures. Corrosion results for TP347H (fine-grained and coarsegrained) from actual plants are compared with other data (Fig. 20) which are from test superheaters and corrosion probes, where in many cases the temperature has been difficult to control and calculate/measure. Sometimes a broad range of temperatures is measured so that a peak temperature may not correctly describe the actual temperature where there is most corrosion. Considering the temperature profiles for superheater 2 and 3 in for AVV2 bio (Fig. 21), it is clear from the peak temperature that superheater 3 should corrode more than superheater 2, which is not the case. Superheater 2 in AVV2 bio had a broad temperature histogram also up to 590 8C, and the metal loss that occurs at these temperatures will be higher than at the lower temperatures, thus just using the peak temperature for such a curve does not accurately reflect the correlation of metal loss to temperature. To give better lifetime prediction from such data, a method to weight the higher temperatures is required as more corrosion occurs at the higher temperatures. The data where the temperature did not vary extensively are depicted in Fig. 22. This suggests that the corrosion rate increases drastically after 540 8C which has been experienced for different test superheaters and probes in the plants[6, 12]. It must be noted that the points at high temperatures are only single measurements so further data are required to substantiate this tendency. The fact that metal loss is significantly higher for the SH2 tubes exposed in as shown in Fig. 21 indicates that the corrosion rate drastically increases with a slightly higher temperature. This drastic increase in corrosion with respect to temperature is probably due to the increased volatility of metal chlorides. Figure 22 should however be interpreted with some caution, as the data are from three different plants, and the AVV2 bioboiler is larger than the other two and the flue gas temperature in AVV2 bio superheater region is higher than Maribo Sakskøbing. More data are required to positively conclude that corrosion rates increase drastically when the steam temperature increases over approximately 550 8C and ß 2010 WILEY-VCH Verlag GmbH & Co. KGaA, Weinheim

11 Materials and Corrosion 2010, 61, No Experiences with high temperature corrosion 11 1 TP347H collation Metal Temperature 560 C 540 C 520 C 490 C 470 C ln (corrosion rate mm/1000h) y = x /T in Kelvin metal temperature RKV SH2 MKV SH3 EKV SH3 EKV SH2 MKV SH2 MSK SH3 MSK SH2 AVV2 OH3 AVV2 OH2 probes/test superheaters Linear (actual plants) Figure 20. Comparison of all corrosion data for TP347H straw-firing and actual plant data 2000 Metal loss 0.5 mm SH2 Bank 12 Tube SH3 Bank 12 Tube Hours 1000 Metal loss 1.3 mm < 450 C C C C C C C C C C C C C C C C C C C C C Temperature Figure 21. Comparison of temperature and metal loss for superhater 2 and superheater 3 in for AVV2 bio exposures are still underway in test superheater loops at AVV2 bio to generate this data. 5.3 Effect of flue gas temperature From this work and previous exposures, it has become more evident that flue gas temperature plays a more significant contribution to the corrosion rate although metal temperature is the main parameter. The effect of flue gas is clearly observed from the temperature measurements, where the partially shielded loops have a higher temperature than the fully shielded loops. Thermal gradient laboratory experiments have clearly illustrated that the flue gas temperature is an important factor for deposit corrosion[25, 26]. From the Maribo Sakskøbing data, a preferential corrosion on flue gas direction of the tube is observed but only on superheater 3. From the test superheater exposed in the first pass at Masnedø[7], it was apparent that flue gas direction had a marked effect on corrosion rate. In this publication, there were many assumptions as to flue gas temperature, for example that flue gas temperature at the top of the pass is lower than in the middle - and although these are reasonable, actual documentation for this is lacking. Therefore flue gas temperatures were measured at various locations at Maribo Sakskøbing[23]. The measurements reveal ß 2010 WILEY-VCH Verlag GmbH & Co. KGaA, Weinheim

12 12 Montgomery, Jensen, Borg, Biede and Vilhelmsen Materials and Corrosion 2010, 61, No Corrosion rate mm/1000h AVV TSH (1 specimen) MSK SH3 (9 specimens) AVV2 SH3 (7 specimens) MSK SH2 (9 specimens) MKV SH2 (2 specimens) Only results where the temp does not vary Steam Temperature Figure 22. Corrosion rate with respect to temperature where the temperature does not vary extensively Figure 23. Thermographic picture taken from S. Clausens report showing superheater with deposit for MSK. White lines show inner loop of superheater fluctuation of up to 200 8C from the average temperature. Another important result is that the temperature close to the boiler wall up to 0.5 m into the boiler is significantly lower than that in the middle of the boiler pass. Thus if one considers a superheater loop where the inlet temperature is 80 8C lower than the outlet temperature, then the temperature of the loop will not increase linearly with distance from the inlet. There will probably be a difference between a horizontal or pendant superheater (those described in this paper). In addition taking specimens Table 3. Calculated outer surface temperatures on superheater tubes with variation of steam temperature and heat flux. SH2 steam temperature 486 8C Flux (W/m 2 ) Surface metal temperature 8C SH3 steam temperature 541 8C Flux (W/m 2 ) Surface metal temperature 8C close to the outlet could give misleading results. It must be noted that the test sections from Maribo Sakskøbing were positioned 1 m below the top of the superheater loop. Another important result is that there is a much higher surface temperature where there is deposit on the superheater and that the deposit at temperatures over 950 8C is seen to run off the superheater (Fig. 23). The amount and composition of the deposit on the superheater also have an effect on the surface temperature of the superheater, and this can change during long exposure times. Thus it is difficult to give a single flue gas temperature reading because of the great fluctuations. Based on the IR temperature measurements at Maribo Sakskøbing, it is attempted to see if some correlations between flue gas temperature and corrosion rates can be found. Flue gas temperature in the first pass will influence the steam temperature especially for superheater 2. Figure 24a depicts the peak steam temperature of the superheaters with respect to peak flue gas temperature measured for each year (based on data from Fig. 7). The temperature for superheater 3 shows little change with respect to flue gas temperature since the total outlet steam temperature from superheater 3 is controlled to 540 8C. There is more variation for superheater 2, however apart from the lowest superheater temperature at the lowest flue gas temperature, no clear correlation can be seen. Figure 24b portrays corrosion rate with respect to flue gas temperature. There is a general tendency that at a lower flue gas temperature, there is a relative lower corrosion rate. Calculations were undertaken to estimate the change in metal temperature as a function of heat flux based on the operation conditions of the actual superheaters investigated. The parameters and assumptions used for this calculation are described in ref. [24]. Some of the worst case results of these calculations are shown in Table 3. For superheater 2, there is a a) 550 b) Peak temperature 540 OH2 Superheater steam temperature ( C) Flue gas temperature in 1st pass ( C) Peak temperature OH3 Corrosion rate mm/1000h Superheater 2 Superheater 3 Figure 24. Flue gas temperature with respect to a) superheater steam temperatures b) corrosion rate MSK Peak flue gas temperature ºC in 1st pass ß 2010 WILEY-VCH Verlag GmbH & Co. KGaA, Weinheim

13 Materials and Corrosion 2010, 61, No Experiences with high temperature corrosion 13 higher heat flux due to higher flue gas temperature. A doubling of heat flux increases the surface metal temperature by 9 8C. In superheater 3, a doubling of heat flux from 6800 to W/m 2 leads to a temperature increase of 6 8C. From the results from Maribo Sakskøbing, more corrosion on the flue gas side was only present on superheater 3 compared with superheater 2. The flue gas temperature is higher in the superheater 2 area, and it would be expected that this had a greater consequence, however the actual steam temperature is higher in superheater 3, and as shown in Fig. 19 and Fig. 22, around 540 8C and above, a slight increase in temperature has a more significant effect on the corrosion rate. Flue gas temperature can influence corrosion rates in other ways such as influencing the compostion and morphology of the deposit (melted or not melted), or degree of sulphation of the deposit. The effect of flue gas flow is clearly observed in the difference between shielded and unshielded loops, and perhaps potassium chloride richer deposit is present on unshielded sides of the tube. It has been observed at both Masnedø and Maribo Sakskøbing that the deposit on superheater 2 in the 1st pass was thinner than from superheater 3[17]. At higher flue gas temperatures, corrosive species such as potassium chloride will remain in the flue gas thus deposits formed in areas of high flue gas temperature have had a lower chlorine content[27] (resulting in lower corrosion rates). A thick deposit can shield part of the tube from the flue gas and therefore result in a greater variation in corrosion rates around the circumference of the tube. These two factors could also contribute to the variation in corrosion attack for superheater 3 compared to superheater 2 for MSK. The deposit morphology can also influence corrosion as revealed from laboratory tests with potassium chloride [28]. It was observed that there is an optimum deposit thickness (0.7 2 mm) which results in the thickest corrosion products and presumably more corrosion. There were also indications that cracks in the deposits enhanced attack. In plants the deposit morphology is fluctuation and the deposit thickness will have changed many times during a h exposure, especially if the plant has many shutdowns. It is also evident that it is not always in the flue gas direction that the highest corrosion rate occurs. While this is the case for the built in superheaters at MSK, for the AVV2 bio, the orientation of highest material loss is variable. With flue gas direction also comes deposition, and the deposition can be viewed as a positive or negative factor with respect to corrosion. Deposit will give a thicker deposit which could be protective, resulting in less heat transfer on that side. However it could also give a deposit richer in corrosive species, which at a high flue gas temperature could lead to higher sulphation rates. Thus corrosion rates are related predominantly to metal temperature, but also to flue gas variations within the plant. Thus for lifetime prediction, data from actual plants are invaluable. 6 Conclusions The following conclusions can be drawn: (i) Corrosion rates have been measured for approximately h at Maribo Sakskøbing and Avedøre 2 bioboiler and reveal that the corrosion rate increases with metal temperature and is accelerated above steam temperatures of 540 8C. (ii) The influence of flue gas flow is observed in superheater 3 at MSK, in superheater 2 at AVV2bio and the test superheater HAH96 at AVV2bio, resulting in higher corrosion rates, however the exact effect of flue gas is difficult to quantify. The highest corrosion rate is not necessarily in the flue gas direction. Local flue gas temperature governs the chemistry of the deposit while flue gas flow will affect the deposit morphology and thus govern the heat transfer and the corrosion rate around the tube. (iii) It is important to have plant data (both flue gas and steam temperature profiles coupled with tube thickness measurements) in order to calculate the corrosion rate and define a lifetime prediction. However there will always be a spread in the data due to the dynamics of the plant. Acknowledgements: This work is a collaboration between DTU Mechanical Engineering, DONG Energy, and Vattenfall Heat Nordic. The results obtained from PSO projects 6510 and 6511 have been used in this paper. These two PSO (public service obligations) projects have been financed by Energinet.dk 7 References [1] J. Knudsen, et al., Proceedings from 14th European Biomass Conference 17-20th October Q3 2005, Paris. [2] O. H. Larsen, N. Henriksen, Proc. Power Plant Technology, Kolding Q4 4-6 Sept. pp [3] N. Henriksen, O. H. Larsen, R. Blum, S. Inselmann, VGB Conference Corrosion and Corrosion Protection in Power Plants Q5, Essen, Germany [4] N. Henriksen, O. H. Larsen, Mater. High Temp. 1997, 14, p227. [5] M. Montgomery, A. Karlsson, Mater. Corros. 1999, 50, 579. [6] M. Montgomery, A. Karlsson, O. H. Larsen, Mater. Corros. 2002, 53, p 121. [7] M. Montgomery, O. Biede, O. H. Larsen, proceedings:materials for Advanced Power Engineering, Liege, Belgium 2002, pp [8] M. Montgomery, B. Carlsen, O. Biede, O. H. Larsen, Proc. NACE Conference CORROSION, Denver Q6 USA 2002, paper [9] N. Henriksen, M. Montgomery, O. H. Larsen, VDI-. Berichte 1680, VDI Verlag GmbH Q7 Düsseldorf, pp , [10] M. Montgomery, O. H. Larsen, Mater. Corros. 2002, 53, 185. [11] M. Montgomery, O. Biede, O. H. Larsen, Mater. Sci. Forum 2006, , 523. [12] O. H. Larsen, M. Montgomery, Energy Mater. 2006, 1, 227. [13] M. Montgomery, S. A. Jensen, T. Vilhelmsen, Mater. Corros. 2008, 59, 783. [14] M. Montgomery, O. H. Larsen, S. A. Jensen, O. Biede, Mater. Sci. Forum 2004, , [15] M. Montgomery, O. Biede, O. H. Larsen, Corrosion Investigations at Maribo Sakskøbing Combined Heat and Power Plant Part I December Q8 2001, PSO project [16] M. Montgomery, O. Biede, O. H. Larsen, Corrosion Investigations at Maribo Sakskøbing Combined Heat and Power Plant Part II December 2002, PSO project ß 2010 WILEY-VCH Verlag GmbH & Co. KGaA, Weinheim

14 14 Montgomery, Jensen, Borg, Biede and Vilhelmsen Materials and Corrosion 2010, 61, No [17] M. Montgomery, O. Biede, O. H. Larsen, F. Frandsen, Corrosion Investigations at Maribo Sakskøbing Combined Heat and Power Plant Part III June 2005, PSO project [18] M. Montgomery, O. Biede, S. A. Jensen, O. H. Larsen, Corrosion Investigations at Maribo Sakskøbing Combined Heat and Power Plant Part IV April 2007, PSO project [19] M. Montgomery, O. Biede, Corrosion Investigations at Avedøre 2 Biomass-fired boiler December 2004, PSO project 6511 [20] M. Montgomery, S. A. Jensen, U. Borg, Corrosion Investigations at Avedøre 2 Biomass-fired boiler Part II December 2008, PSO Project [21] M. Montgomery, S. A. Jensen, U. Borg, Corrosion Investigations at Avedøre 2 Biomass-fired boiler Part III September 2009, PSO Project [22] S. Clausen, Infrarøde temperaturmåling Avedøre biokedel. Risø-R-1511 (DA) July [23] S. Clausen, Temperaturmålinger Sakskøbing Kraftvarmeværk Maj Q [24] N. Henriksen, O. H. Larsen, R. Blum, Proc. Power Plant Technology, Kolding 4-6 Sept. pp [25] Y. Kawahara, M. Kira, M. Ike, Sci. Rev.: High Temp. Corros. Prot. 2000, p [26] M. Montgomery, Proc. Materials for Advanced Power Engineering Oct 1998, 6th Liege Conference [27] P. A. Jensen, F. J. Frandsen, J. Hansen, K. Dam-Johensen, Energy Fuels 2004, 18, 378. [28] P. Andersson, M. Norell, R. Gautheron, Mater. Sci. Forum 2004, , (Received: July 13, 2010) (Accepted: August 25, 2010) W5856 ß 2010 WILEY-VCH Verlag GmbH & Co. KGaA, Weinheim

15 Materials and Corrosion 2010, 61, No Experiences with high temperature corrosion 15 Keywords: lifetime prediction straw-firing TP347H Q1: : Please provide complete affiliation. Q2: : Sense of the text not clear. Please check. Q3: : Please check the presentation of reference 1 and 2. Q4: : References are not in sequence. Please check. Q5: : Please provide publisher name. Q6: : Please provide publisher name. Q7: : Please provide publisher location. Q8: : Please check the presentation. Q9: : Please check the presentation. ß 2010 WILEY-VCH Verlag GmbH & Co. KGaA, Weinheim

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18 Avedøre 2 Halmkedel Korrosionsundersøgelser November 2003 ENERGI E2 F&U ELKRAFTsystem FUD-2.C Højtemperatur korrosionsundersøgelser på BIOAVV2

19 Indholdsfortegnelse Indholdsfortegnelse Indledning Testoverhedersystemet Testrør Status frem til revisionen Diametermålinger af teststykkerne vha. en digital mikrometerskrue Diametermålinger i kedlen i øvrigt vha. en digital mikrometerskrue Konklusion Bilag 1 Testoverheder, målinger Før idriftsættelse, 2001, 2002 og Bilag 2 Testoverhedere Godstykkelsesreduktioner Bilag 3 Godstykkelsesmålinger Bilag 4 Godstykkelsesmålinger Bilag 5: Godstykkelsesreduktioner

20 1. Indledning I det af ELKRAFTsystem støttede PSO-projekt FUD-2.C.99-37, BRO Højtemperatur korrosionsundersøgelser på AVV2bio er der på Avedøreværket blok 2 s halmkedel (AVV2bio) indsat testoverhedere med nøje opmålte teststykker, ligesom der i udvalgte permanente overhedere er indsat teststykker. På en lang række overhederrør samt på testoverhederrørene er der i det døde rum monteret termoelemeneter. Der foretages temperaturmålinger på rørstykkerne, og temperaturerne bearbejdes løbende. Forskellige steder i kedlen er der i udvalgte positioner foretaget manuelle godstykkelsesmålinger vha. mikrometerskrue. Nærværende notat beskriver testoverhederne, deres placering og resultater fra de manuelle målinger. Nøjere undersøgelser af teststykker udskåret fra kedlen er rapporteret af Melanie Montgomery, IPL-DTU. 3

21 2. Testoverhedersystemet Testoverhedersystemet er leveret og monteret af Austrian Energy som en selvstændig ordre i forbindelse med konsortiets kedelordre. Systemet er vist skematisk i Q-diagram AVV I55 HAH/Q006, gengivet som Fig. 1. Figur 1: Q-diagram AVV I55 HAH/Q006, der viser testoverhederne 4

22 Damp udtages efter 1. indsprøjtningsventil og ledes frem til 4 strenge, hvoraf de tre strenge er principielt identiske, mens den fjerde streng er en bypass ledning forsynet med selvstændig reguleringsventil. Intentionen med systemet er at holde en højere temperatur i de tre teststrenge end i de permanente overhedere og derved kunne følge korrosionsraten ved en overtemperatur. Eksempelvis kunne temperaturen være henholdsvis 10, 20 og 30 C s højere, hvilket reguleres vha. reguleringsventilerne. Den samlede damptemperatur ud af de tre teststrenge vil derved være højere end damptemperaturen efter de permanente overhedere, og der er derfor etableret en bypass ledning, således at man ved regulering af flow et i denne kan opnå en samlet temperatur efter testoverhedersystemet lig med damptemperaturen efter de permanente overhedere. Placering af de tre teststrenge ved skot 4, 11 og 19 er illustreret i Fig. 2, som er uddrag af tegning AVV 55 HA/A330. Figur 2: Testoverhedernes placering mellem overhederskottene. Testoverhederne er placeret ens ved overheder 2 og overheder 3. De tre ens strenge er forsynet med en reguleringsventil og en flowmåler, før røret føres ned langs overheder 2 i fyrrummet, som illustreret i Fig.3. og igen op i det døde rum, hvor der er placeret en temperaturmåler. Herefter føres røret ned langs overheder 3 og op igen i det døde rum, hvor der er placeret to temperaturmålere. Hver af de tre strenge kan isoleres vha. dobbelte afspærringsventiler. Herefter samles de fire strenge igen, inden de ledes til hoveddampstrengen efter overheder 3. 5

23 Figur 3: Testoverhedernes forløb langs overheder 2 i fyrrummet og overheder 3 i tværtrækket. Testoverhedernes placering er ligeledes vist i Fig. 4. I forgrundes ses et af testoverhederrørene ned langs overheder 2, og op igen langs overheder 2 og i baggrunden ses røret igen ned langs overheder 3. Ligeledes ses testrørene, der beskrives efterfølgende, både placeret i testoverhederne midt i billedet og i en af de permanente overhedere til højre i billedet. Figur 4: Testoverheder langs overheder 2 og i baggrunden langs overheder 3. Ligeledes ses placering af de afdrejede testrør. 6

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