Accident analysis of a gas turbine

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I. Overview of the Power Plant (1) Introduction to Equipment: A gas turbine thermal power plant was commissioned in 2001; it is equipped with one set each of gas turbine units, waste heat boilers, and steam turbine units. In addition, it has facilities such as a substation, natural gas compressors, and chemical water treatment systems. For a 1+1 steam-gas combined cycle unit, with a total installed capacity of 54MW. The gas turbine used is of the PG6551 type, with a rated power of 39.6 MW. The gas turbine control system is MARK V, the fuel is natural gas, and the equipment manufacturer is Nanjing Turbine Motor (Group) Co., Ltd. (2) Operation and management approach: The commercial operation of the gas turbine in this combined cycle power generation unit is carried out by the Gas Turbine Power Plant of Daqing Petroleum Administration Bureau’s Electric Power Corporation. The scope of responsibility includes the gas turbine island (gas turbine, natural gas pre-processing module, gas turbine cooling water filter, generator cooling water filter, auxiliary equipment room for the gas turbine and generator, and 125 V DC room for the gas turbine). Qinling Power Generation Co., Ltd. is responsible for the commercial operation of the steam turbines. Its scope of responsibilities includes: waste heat boilers, steam turbines, chemical water treatment systems, circulating cooling water pump rooms, gas engines and turbine cooling towers, as well as natural gas compressors. Qinling Power Generation Co., Ltd. is also responsible for the operation and production management of the power plant. (3) Operation status of the unit: The gas turbine equipment of this combined cycle power generation unit was installed and commissioned by Nanjing Turbine & Motor (Group) Co., Ltd. A 72-hour trial operation began at 20:00 on June 22, 2001, and the 72-hour trial operation concluded on June 25, 2001, after which the unit entered commercial operation. Before the unit was put into commercial operation, there were incidents of the exciter burning out and high temperatures between the rotors; no major equipment failures have occurred since it began operating commercially. During the winter of 2001 and the summer of 2002, there was an abnormal situation of a high pressure difference across the air intake filters for over 50 days, with the pressure difference reaching up to 3250 Pa. The exhaust pressure of the compressor decreased slightly, from 1.02 MPa to 0.994 MPa. After being put into operation, the unit generally operated at a basic load level. As of 19:00 on November 21, 2002, the gas turbine had accumulated 5,466.7 hours of operation; it was started a total of 63 times, with 54 starts being successful, and it experienced 12 shutdowns due to accidents. (4) Operating conditions of the unit prior to the accident-induced shutdown. The last time the gas turbine was started up and connected to the grid before the accident occurred was on October 31, 2002, and it operated continuously for 20 days until the accident happened, during which time its operation was very stable. The main operating parameters were as follows: the maximum operating load of the unit was 36.7 MW, the minimum operating load was 31.3 MW, and the average operating load was 31.97 MW; the exhaust temperature of the turbine was within normal ranges, varying depending on the load, with values between 510°C and 545°C – such variations were within the allowable limits. The average vibration of bearing 1 is 2.2 mm/s, while that of bearing 2 is 3.3 mm/s. The average vibration of the bearings at the front and back of the generator is 0.9 mm/s; the maximum vibration level of the entire unit is 3.6 mm/s ； There are no abnormalities in vibrations anywhere ； The temperatures of all bearings and the return oil temperature are normal. The pressure difference across the air intake filter is normal; the normal operating range for this value is 50–500 Pa. The compressor exhaust pressure is 1.0 MPa, and the exhaust temperature is around 330°C ； During normal operation of the unit, the pressure of the natural gas fuel is within normal ranges, averaging between 1.9 and 2.0 MPa, with no significant fluctuations; the pressure difference across the natural gas inlet filter is also normal. II. Course of the unit accident At 19:35 on November 21, 2002, the gas turbine operation supervisor suddenly heard a loud bang coming from the direction of the unit in the gas turbine control room; immediately thereafter, the following message appeared on the MARK-V control panel of the gas turbine: At 19:35:08, an alarm for “flame loss trip” was triggered ； At 19:35:08, an alarm for “loss of compressor exhaust pressure” was triggered ； At 19:35:08, an alarm for “vibration difference fault” was triggered ； 19:35:08 – “High vibration trip or shutdown” alarm ； At 19:35:09, an alarm for \"high exhaust temperature\" was triggered. At the same time, an alarm for \"vibration sensor failure\" was issued, as well as an alarm for \"hydraulic protection failure\". Another alarm for \"exhaust overtemperature trip\" appeared at 19:35:09. An alarm for \"high vibration\" was detected at 19:35:13, and an alarm for \"control failure of inlet guide vanes\" occurred at 19:35:21; a trip was also triggered due to this control failure. After the unit tripped, inspectors, chief operators, and specialists from various departments rushed to the scene. Upon inspection, it was found that the opening angle of the inlet guide vanes was 80 degrees, whereas the MARK V display indicated an opening angle of 74.7 degrees – meaning the guide vanes had not closed properly as per the prescribed procedure. The display shows that among the 4 flame detectors A#, B#, C#, and D#, detector C# has detected flame. Check that the intake and exhaust ducts show no deformation; there are no leaks in the natural gas pre-module. The natural gas ratio valve and control valve are in the closed position, and the on-site pressure of natural gas is 2.45 MPa. A dull sound was emitted during the unit’s speed reduction, lasting for about 4 to 5 minutes. At 19:45, the speed of the gas turbine slowed down to zero, and the ratchet turning device was automatically activated according to the program. The unit stopped operating at 20:25 due to a turning gear failure. Check that the ratchet turntable is operating normally. No abnormalities were found in the control system upon inspection, and no issues were detected either in the oil circuit of the turning gear or in its lubricating oil filter. During this period, the ratchet turntable was manually started three times, and it failed to operate properly each time. Further inspection of the inlet guide vanes revealed that the drive gear of the vanes had fallen off. After the internal temperature of the equipment dropped, at 7:45 on November 22, access was gained to the flue; a preliminary inspection of the equipment visible inside the flue revealed no damage. At 7:50, after opening the access hatch for the inlet guide vanes, a foreign object was found at the bottom of the intake chamber. Upon entering the hatch for further inspection, it was discovered that the inlet guide vanes and the compressor blades were severely damaged. III. Inspection results after removing the cover (1) Inspection of the intake system: After shutting down the machine, the access hatch of the intake duct was opened for inspection; only some fragmented metal shavings that had been pushed back from the compressor’s flow path and scattered blades were found, with no other foreign objects detected. It was checked that all intake filters were securely fixed. It was found that the filter at the rear end of the intake chamber had suffered slight damage due to the backflow of air from the compressor. The rivets and gaskets on the side walls of the intake chamber were also confirmed to be properly secured. No foreign objects were detected in the flow passages after the rotor was removed, thus ruling out completely the possibility of any foreign objects entering the compressor. (2) Fuel system inspection: The filter of the natural gas pre-module was clean with no accumulation of fluid, the Y-filter before the fuel valve was also clean with no accumulation of fluid; the fuel control ratio valve and the control valve were closed. (3) Combustion chamber inspection: The combustion chamber was opened to check that the flame tube, transition section, nozzles, flame coupling tubes, guide sleeves and other key components were in good condition. A preliminary inspection revealed no signs of deformation or damage to the equipment. There was approximately 100 ml of water accumulated in nozzle No. 5, which was condensation fluid formed after shutdown; some nozzles showed slight carbon buildup, but there were no instances of detonation. (4) Inspection of high-temperature passages: Inspection of the first-stage turbine blades revealed some defects in their crowns; the second and third-stage turbine blades were in good condition. Some high-temperature melted metal debris was accumulated at the crowns of the second-stage blades. The nozzles, diaphragms, and shrouds at all stages were intact, but all flow-related components showed signs of damage caused by metal debris. (5) Inspection of inlet vanes and compressor blades: 21 inlet vanes were missing, and all the remaining vanes had notches in a counterclockwise direction at their roots. The compressor blades were severely damaged, with varying degrees of tearing or impact marks along their radial leading edges on both the moving and stationary blades. Four first-stage static blades in the upper cylinder of the compressor were lost, and one first-stage dynamic blade broke off at its root; the fracture site at the root of the blade showed clear signs of age on some of the fracture surfaces (as shown in Figures 1 and 2). IV. Accident Cause Analysis A detailed analysis of this accident was conducted based on the operational data before and after the unit tripped, the alarm and trip information, the shift records, and on-site investigations. 1. Analysis of operational parameters before and after unit tripping: After the unit tripped, the MARK V control system automatically recorded historical data for three seconds after the trip, as well as data taken at intervals of one second, ten seconds, one minute, and one hour before the trip (over the first four hours). From these data records, it can be seen that *DWATT represents the active load of the generator, in MW units. It stabilized at around 32 MW before tripping, and the values three seconds after tripping were -23.8 MW, -4.7 MW, and OMW respectively. After the unit tripped, the generator outlet circuit breaker 101 did not open immediately, which triggered the reverse power protection; breaker 101 opened after a 2-second delay. The phenomenon is normal. *NH gas turbine speed. It was 100.05% before tripping, and 100.11%, 100.11%, and 99.79% respectively three seconds after tripping, which is normal. *FSR fuel stroke reference. It was 60.9% before tripping and 0.0% after tripping, which is normal. *CTIM compressor inlet temperature. It was 7°C before and after tripping, which is normal. *CTDA compressor exhaust temperature. It was 334°C before tripping, and 335°C, 354°C, and 359°C respectively three seconds after tripping. The exhaust temperature increased by 25°C; after the unit tripped, the compressor exhaust temperature should show a downward trend, so such an increase in temperature is abnormal. *CPD compressor discharge pressure. It was 1.008 MPa before tripping, and three seconds after tripping it was 0.410 MPa, 0.182 MPa, and 0.180 MPa respectively. Based on the normal shutdown analysis for the unit, this value remains relatively stable within three seconds after shutdown and then gradually decreases. However, in this case, the exhaust pressure of the compressor dropped rapidly from 1 MPa to 0.182 MPa within just two seconds, indicating a serious fault in the compressor’s supply or flow mechanism. This phenomenon is extremely abnormal. *TTXD1-TTXDl8 turbine exhaust temperature. Taking TTXD1 as an example, the temperature was 506°C before tripping; three seconds after tripping, it was 506°C, 565°C, and 563°C respectively. The exhaust temperature increased, and the temperature trends of the exhaust gases from the other turbines were similar to those of TTXD1. After the unit tripped, the fuel valve closed, and the exhaust temperature should have shown a downward trend; however, the exhaust temperature increased during this trip, which is abnormal. *Pressure between the FPG2 fuel speed ratio valve and the control valve. It was 1.678 MPa before tripping, and 0.795 MPa, 0.681 MPa, and 0.635 MPa respectively three seconds after tripping. After tripping, the speed ratio valve and control valve close, and the pressure between the valves is released through the vent solenoid valve 20VG; the pressure gradually decreases, indicating normal operation. *FSGR speed ratio valve position feedback. It was 26.16% before tripping and -2.67% after tripping, which is normal. *FAGR speed ratio valve position feedback current. It was 33.85% before tripping and 7.65% after tripping, which is normal. *FSG control valve position feedback. It was 60.52% before tripping and -3.62% after tripping, which is normal. *The FAG control valve provides position feedback current. It was -3.15% before tripping and 36.04% after tripping, which is normal. *CSGV inlet guide vane opening. It was 86.9 degrees before tripping, and the on-site reading after tripping was 80 degrees. As required by the design, after the unit trips and stops, the inlet guide vanes should be closed to 34 degrees. The guide vane is not closed, which is abnormal. *Vibration of bearing No. 1 in BB1 and BB2. Before tripping, they were 2.6 mm/s and 2.9 mm/s respectively, while after tripping they were 50.5 mm/s and -203.2 mm/s. The vibration level is abnormally high; a negative value on BB2 indicates that the vibration probe is damaged or open-circuited, which is abnormal. *Vibration of bearing No. 2 in BB4 and BB5. Before tripping, they were 3.6 mm/s and 3.6 mm/s respectively, while after tripping they were 53.6 mm/s and 62.9 mm/s respectively. Vibration is abnormally high; it’s not normal. *BB10, BB11, BB12: Generator vibration. Before tripping, the values were 0.8 mm/s, 1.0 mm/s, and 1.0 mm/s respectively; after tripping, they were 10.9 mm/s, 11.3 mm/s, and 7.2 mm/s respectively. The vibration levels increased significantly, but did not reach the vibration alarm thresholds. The increase in generator vibration is caused by high vibration in the gas turbine bearings. 2. Analysis of historical alarms before and after unit tripping: No abnormal alarms occurred before the unit tripped. The alarms that appeared after the tripping are analyzed as follows: (1) LOSS OF FLAME TRIP. This unit is equipped with four basic protections: over-temperature, overspeed, vibration, and flame out. The flame out protection is one of these; the gas turbine has a total of 10 counterflow burners, and UV flame detectors labeled A, B, C, and D are installed in burners #2, #3, #7, and #8 respectively to monitor the flame condition in those burners. According to the programming, during operation of the unit, if three flame detectors fail to detect any flame at the same time, a trip signal is sent to the control system to shut down the unit. There may be several reasons for a shutdown of a unit that is currently in operation: flame detector failure ； Control system failure ； Stall due to low fuel ； Rich fuel stall ； Fuel quality reasons ； ①Flame detector fault: According to the unit’s programming, if one or more of the flame detectors in an operating unit fail to detect flames, a “flame detector fault” alarm will be triggered. If no such alarm appears before the unit stops operating, it indicates that the flame detectors are functioning properly. As mentioned above, when the unit is operating, if three flame detectors fail to detect any flame at the same time, a trip signal is sent to the control system to shut down the unit. Moreover, the probability of the unit being shut down due to at least three flame detectors failing simultaneously is extremely low. Therefore, a “flame detector failure” will not cause this “flame loss trip”. ②Control system failure: After the shutdown, the MARK V control system and the logic related to the stall protection were checked; no abnormalities were found, indicating that the stall protection activation was not caused by a control system failure. ③Fuel quality issues: If a gas turbine uses a gas fuel with a low calorific value, flameout can occur easily when the fuel contains a high amount of liquid water. Natural gas has a very high calorific value, over 8,000 kcal, so it will not experience flameout for the reasons mentioned above. Furthermore, when natural gas contains other impurities, such as light hydrocarbons, it can cause localized overheating of high-temperature components, leading to changes in the exhaust temperature. If lubricating oil is present, the oil droplets cannot be effectively atomized, which may lead to carbon buildup on high-temperature components or clogging of the fuel nozzles. This in turn causes variations in exhaust temperature and results in combustion problems in the engine. None of the above reasons can cause the combustion chamber to shut down. ④Lean burn shutdown: During normal operation of the unit, if the speed remains constant and the opening of the inlet guide vanes stays unchanged, then there will be no significant change in the air flow supplied to the combustion chamber. A lean burn shutdown can occur due to fuel control failures or insufficient natural gas supply. However, various records prior to the shutdown showed that the fuel control valve, the feedback from the fuel ratio valve, and the servo current were all normal; the fuel stroke reference FSR was also normal, there were no fluctuations in the unit’s load, and the pressure of the natural gas supply as well as the pressure between the valves were within normal ranges. Therefore, a lean burn shutdown is not possible under such conditions. ⑤Rich fuel shutdown: Since the unit is equipped with over-temperature protection, that is, the control system regulates the fuel supply to prevent overheating, rich fuel shutdown does not occur under normal conditions. However, when the unit is operating normally, especially under high load when the fuel valves are open to a greater extent, any serious malfunction in the compressor’s flow path – such as the sudden closure of the compressor inlet vanes, compressor surge, or blade damage – can result in insufficient air being supplied to the combustion chamber, thereby causing rich fuel shutdown. During this unit shutdown due to an accident, the inlet guide vanes were not closed, and the conditions for compressor surge did not occur; therefore, the shutdown protection that took effect in this case was likely caused by an excessive oil supply resulting from a serious fault in the compressor’s flow path. (2) LOSS OF COMPRESSOR DISCHARGE PRESS BIAS: According to the design specifications, when the unit is operating normally, if the compressor discharge pressure drops below 0.56 MPa (80 PSI), the control system issues this alarm signal. At the moment the unit trips, the compressor’s rotation speed remains unchanged, as does the opening degree of the inlet guide vanes; therefore, this alarm should not occur under normal conditions. It indicates a fault in the compressor’s flow passage. It should be noted that the compressor discharge pressure signal is transmitted via a pressure tube (about 10 meters long) located at the back of the compressor, to the pressure transmitter 96CD-1 on the instrument panel in the auxiliary equipment room, from where the signal is then sent to the control system. This setup inevitably results in a delay in the signal transmission. As can be seen from the alarm information table, there is a time difference of 0.218 s between \"Flame loss trip\" and \"Compressor exhaust pressure offset loss\"; therefore, when the \"Compressor exhaust pressure offset loss\" alarm occurs, the fault has already taken place, and it likely occurred before the flameout protection mechanism activated. (3) VIBRATION DIFFERENCE FAULT: This alarm is triggered according to the programming when there is a significant difference in the vibration signals detected by two vibration sensors located at the same position; the occurrence of this alarm indicates that one of the vibration sensors may be faulty. (4) HIGH VIBRATION TRIP OR SHUTDOWN: As programmed, when the unit is operating normally, if the vibration level detected by a certain vibration sensor reaches 25.4 mm/s, a signal is sent to shut down the unit. At the time of this unit trip, the maximum vibration of the unit reached 50 mm/s. (5) HIGH EXHAUST TEMPERATURE: After the unit trips, the fuel valve is closed, and the exhaust temperature should not rise. The increase in exhaust temperature following this trip indicates that the compressor is not providing enough air flow, which leads to an increase in the exhaust temperature of the gas turbine. The exhaust temperature thermocouple is installed on the exhaust side, and there is a certain delay in the temperature signals it detects; as a result, overheating occurs at the combustion chamber outlet before this alarm is triggered. 3. Analysis of the preliminary on-site investigation findings: Based on the reports provided by the personnel on duty at the time of the accident, as well as the on-site investigations conducted after the accident, it was determined that a deflagration occurred during the incident. The evidence for this is as follows: *The operators in the control room heard a loud, sharp ‘bang’ sound. *Both the plant duty police officer and the DCS control room staff heard the sound, and those in the DCS control room also felt vibrations. Mechanical failures do not produce this vibration sensation. *During the on-site inspection of the inlet, metal debris was found at the bottom of the inlet, and metal fragments were also detected in front of the filter above the inlet. This indicates that these debris were carried there by the air currents during the explosion; otherwise, there should not be such a large amount of metal debris in that area. Based on the on-site investigation, it is believed that the intensity of this deflagration was not significant, as follows: *The main equipment in the exhaust system was found to be in good condition, and the flue ducts showed no signs of deformation. *Check that the intake duct is not deformed. *Check that the combustion chamber in the engine room and all pipelines are properly secured, and verify that the partition of the exhaust cylinder is in good condition. Analysis of the cause of deflagration: Natural gas is a flammable and explosive gas, with an explosion limit ranging from 5% to 15%. When the concentration of natural gas in air is below 5%, no combustion or explosion occurs ； When the mixture concentration of natural gas and air is between 5% and 15%, combustion or explosion can occur ； When the mixture concentration of natural gas and air is higher than 15%, combustion can occur, but no explosion will take place. Conditions for a natural gas explosion: The concentration of natural gas in the air is within its explosive range; an explosion occurs when it comes into contact with an open flame or reaches its auto-ignition temperature, which is between 400°C and 700°C. Normally, if the natural gas is not properly purged during the startup process of the unit, deflagration can easily occur when the unit is ignited. If the fuel valve does not close properly after the unit is shut down, the concentration of natural gas leaking into the unit’s combustion chamber reaches the explosive limit, resulting in a deflagration when it comes into contact with hot components. If the engine shuts down due to insufficient natural gas pressure, there is very little residual natural gas left, and when mixed with air it does not reach the explosive range; therefore, no deflagration will occur in the engine. If oil enrichment leads to flameout for some reason, the remaining \"enriched gas\" mixes with air, reaching the explosive range and causing detonation within the engine (for example, in Unit 1 of the Daqing Gas Turbine Power Plant, a fault in the inlet guide vanes caused them to close suddenly during normal operation; the engine did not trip, but the compressor flow rate dropped rapidly, resulting in oil enrichment flameout. A detonation occurred at the rear of the turbine, which led to the detachment of the exhaust silencer, deformation of the exhaust duct, tearing of the partition in the exhaust cylinder, detachment of the doors in the turbine room, and deformation of the intake duct, although no damage was caused to the flow components of the gas turbine). When the gas turbine is operating normally, the fuel control system functions properly, the natural gas supply is adequate, combustion takes place normally, and no detonation occurs in the combustion system. 4. Accident cause determination: Based on the above operational data, reasons for the alarms, and on-site investigation and analysis, the causes and sequence of the accident are preliminarily determined as shown in Figure 3. In summary, it is preliminarily determined that the fallen leaf was the direct cause of this accident. Due to a quality defect in the blade at the time it left the factory, the internal cracks continued to propagate and expand under the effects of centrifugal force and the reactive force of the compressed gas; once they reached a certain size, the blade suddenly broke under the intense centrifugal force. On one hand, the broken blades will fly radially outward under the effect of centrifugal force ； On the other hand, it will move upstream in the direction of the gas flow due to the reaction force of the compressed gas; ultimately, it will collide with the inlet vanes, causing the 21 adjacent vanes to fall off. The broken moving and stationary blade fragments move downstream driven by the airflow, thereby causing further tearing, twisting, and deformation of the blades. The compressor also causes the air flow into the combustion chamber to decrease rapidly due to damage to its flow passages; this results in an excessive excess air ratio, leading to fuel-rich shutdown of the unit. The remaining natural gas mixes with air to reach the explosive limit, and upon encountering the high-temperature components in the system, an explosion occurs.