Gas Turbine Engineering Handbook 2 Episode 14 pot

G:/GTE/FINAL (26-10-01)/CHAPTER 19.3D ± 635 ± [634±691/58] 1.11.2001 2:38PM Gas turbine instrumentation has expanded in the past few years from simple control systems to more complex diagnostic and monitoring systems that are designed to avert major catastrophes and operate a unit at its peak performance. Control Systems All gas turbines are provided with a control system by the manufacturer. The control system has three fundamental functions: startup and shutdown sequencing, steady-state control when the unit is in operation, and protec- tion of the gas turbine. Control systems can be an open loop or closed loop system. The open- loop system positions the manipulated variable either manually or on a programmed basis, without using any process measurements. A closed loop control system is one, which receives one or more measured process vari- ables and then uses it to move the manipulated variable to control a device. Most combined cycle power plants have a closed loop control system. Closed loop systems include either a feedback or feedforward, control loop or both to control the plant. In a feedback control loop, the controlled variable is compared to a set point. The difference between the controlled variable to the set point is the deviation for the controller to act on to minimize the deviation. A feedforward control system uses the measured load or set point to position the manipulated variable in such a manner to minimize any resulting deviation. In many cases the feedforward control is usually combined with a feed- back system to eliminate any offset resulting from inaccurate measurements and calculations. The feedback controller can either bias or multiply the feedforward calculation. A controller has tuning parameters related to proportional, integrated, derivative, lag, deadtime, and sampling functions. A negative control loop will oscillate if the controller gain is too high, but if it is too low it will be ineffective. The controller must be properly related to the process para- meters to ensure close-loop stability while still providing effective control. This is accomplished first by the proper selection of control modes to satisfy the requirements of the process, and second by the appropriate tuning of those modes. Figure 19-1 shows a typical block diagram for forward and feedback control. Computers have been used in the new systems to replace analog PID controllers, either by setting set points, or lower level set points in super- visory control, or by driving valves in direct digital control. Single-station digital controllers perform PID control in one or two loops, including Control Systems and Instrumentation 635 G:/GTE/FINAL (26-10-01)/CHAPTER 19.3D ± 636 ± [634±691/58] 1.11.2001 2:38PM computing functions such as mathematical operations, with digital logic and alarms. D-CS provide all the functions, with the digital processor shared among many control loops. A high level computer may be introduced to provide condition monitoring, optimization, and maintenance scheduling. The gas turbine control systems are fully automated, and ensure the save and proper startup of the gas turbine. The gas turbine control system is complex and has a number of safety interlocks to ensure the safe startup of the turbine. The startup speed and temperature acceleration curves as shown in Figure 19-2 are one such safety measure. If the temperature or speed are not reached in a certain time span from ignition, the turbine will be shutdown. In the early days when these acceleration and temperature curves were not used, the fuel, which was not ignited, was carried from the combustor and then deposited at the first or second turbine nozzle, where the fuel com- busted which resulted in the burnout of the turbine nozzles. After an aborted start the turbine must be fully purged of any fuel before the next start is attempted. To achieve the purge of any fuel residual from the turbine, there must be about seven times the turbine volume of air that must be exhausted before combustion is once again attempted. The gas turbine is a complex system. A typical control system with hier- archic levels of automation is shown in Figure 19-3. The control system at the plant level consists of a D-CS system, which in many new installations is connected to a condition monitoring system and an optimization system. The D-CS system is what is considered to be a plant level system and is connected to the three machine level systems. It can, in some cases, also be connected to functional level systems such as lubrication systems and fuel handling systems. In those cases, it would give a signal of readiness from those systems to the machine level systems. The condition monitoring system Power Plant Load Error Set Point Feedback Loop Feedforward Controller Feedback Controller Manipulated Variable Controlled Variable Figure 19-1. Forward and feed back control loop. 636 Gas Turbine Engineering Handbook G:/GTE/FINAL (26-10-01)/CHAPTER 19.3D ± 637 ± [634±691/58] 1.11.2001 2:38PM Temperature Speed TIME Ignition Tempe rature Speed Figure 19-2. Startup characteristics of a gas turbine. LOAD Plant Level Optimization System Condition Monitoring System Distributed Control System Machine Level Gas Turbine 1 Gas Turbine 2 Functional Level Lube Oil system Lube Oil system Fuel Skid System Fuel Skid System Drive Level Motor Pump Drive Motor Pump Drive Motor Pump Drive Motor Pump Drive Figure 19-3. Hierarchic levels of automation. Control Systems and Instrumentation 637 G:/GTE/FINAL (26-10-01)/CHAPTER 19.3D ± 638 ± [634±691/58] 1.11.2001 2:38PM receives all its inputs from the D-CS system, and from the steam and gas turbine controllers. The signals are checked initially for their accuracy and then a full machinery performance analysis is provided. The new perform- ance curves produced by the condition monitoring system are then provided to the optimization system. The optimization system, usually used where multiple turbines are used, receives the load and then sends a signal to the D-CS system, which in turn sends the signal to the gas turbine for the best settings of the gas turbine to meet the load. The gas turbine has a number of systems, it controls such as the: 1. Lubrication skid. The gas turbine lubrication skid is usually independ- ent of the steam turbine skid as the lubrication oil is usually synthetic due to the high temperatures in the gas turbine. Another reason is due to water contamination of the lubrication oil from the steam turbine. It is advisable to have the lubrication system be totally independent. The gas turbine lubrication skid would report to the gas turbine controller. Since the lubrication system is also used for providing cooling, it is usually operated for about 20 minutes after the gas turbine is shutdown. The lubrication skid contains at least three pumps, two pumps in which each can provide the head required and a third pump, which is usually recommended to be a DC drive for emergency use. These pumps and their control fall under the drive level hierarchy. 2. The fuel skid. This could contain a gas compressor if the fuel gas pressure is low and a knockout drum for any liquid contamination that the gas may have. The requirement of fuel gas pressure is that it should be operated at a minimum of 50  ±70 psi (3.5  ±4.83 Bar) above the compressor discharge pressure. The compressor and its motor drive fall under the drive level hierarchy. In the case of liquid fuels, the skid may also contain a fuel treatment plant, which would have centrifuges, electrostatic precipitators, fuel additive pumps, and other equipment. These could be directly controlled by the D-CS system, which would then report its readiness to the gas turbine controller. The control system requires inputs for speed determination, temperature control, flame detection, and vibration. The speed monitoring system receives an input from magnetic transducers in the form of an AC voltage with a frequency proportional to the rotational speed of the shaft. A fre- quency-to-voltage converter provides a voltage proportioned to speed, which is then compared to a set value. If the measured voltage is different from the reference voltage, a speed change is made. Typically, the desired speed can be manually set to a range between 80% and 105% of design speed. 638 Gas Turbine Engineering Handbook G:/GTE/FINAL (26-10-01)/CHAPTER 19.3D ± 639 ± [634±691/58] 1.11.2001 2:38PM The temperature control receives its signals from a series of thermocouples mounted in the exhaust. The thermocouples are normally iron-constantan or chromel-alumel fully enclosed in magnesium oxide sheaths to prevent erosion. The thermocouples are frequently mounted with one for each combustion can. The output of the thermocouples is generally averaged into two independent systems with half of the thermocouples in each group. The output of the two systems is compared and used for decisions requiring a temperature input. This redundancy protects the system against tripping if a thermocouple fails. The protective system is independent of the control system and provides protection from over-speed, over-temperature, vibration, loss of flame, and loss of lubrication. The over-speed protection system generally has a trans- ducer mounted on the accessory gear or shaft, and trips the gas turbine at approximately 10% of maximum design speed. The over-temperature sys- tem has thermocouples similar to the normal temperature controls with a similar redundant system. The flame detection system consists of at least two ultraviolet flame detectors to sense a flame in the combustion cans. In gas turbines with multiple cans, the detectors are mounted in cans not equipped with spark plugs to assure flame propagation between cans during startup. Once the unit is running, more than one indicator must indicate a loss of flame to trip the machine, although the loss of flame in only one can is indicated on the annunciator panel. Vibration protection can be based on either of the three measurement modesÐacceleration, velocity, or displacementÐbut velocity is frequently used to provide constant trip levels throughout the operating speed range. Due to the problems encountered by velocimeters, many manufacturers, especially in aero-engines, have started using accelerometers. Two transdu- cers are normally located on the gas turbine with additional transducers on the driven component. Vibration monitors are set to provide a warning at one vibration level with a trip at a higher level. Normally, the control system is designed to provide a warning in the event of an open-circuit, ground, or short circuit. The gas turbine control loop controls the Inlet Guide Vanes (IGV) and the Gas Turbine Inlet Temperature (TIT). The TIT is defined as the temperature at the inlet of the first stage turbine nozzle. Presently, in 99% of the units, the inlet temperature is controlled by an algorithm, which relates the turbine exhaust temperature, or the turbine temperature after the gasifier turbine, the compressor pressure ratio, the compressor exit temperature, and the air mass flow to the turbine inlet temperature. New technologies are being developed to measure the TIT directly by the use of pyrometers and other specialized probes, which could last in these harsh environments. The TIT is controlled by the fuel flow and the IGV, which controls the total air mass Control Systems and Instrumentation 639 G:/GTE/FINAL (26-10-01)/CHAPTER 19.3D ± 640 ± [634±691/58] 1.11.2001 2:38PM flow to the gas turbine. In a Combined Cycle Power Plant application, the turbine exhaust temperature is maintained at or near a constant down to about 40% of the load. All power plants are synchronized to the overall grid and thus the opera- tion of the plant at the given frequency is very important. The grid cannot stand many fluctuations of the plant frequency. It is, therefore, very import- ant to operate the plant at its assigned frequency, which is 60 Hz in the United States and the Americas as well as many countries in the mideast. Europe and most of Asia are operating at a 50 Hz frequency. If there is a frequency change, this must be taken care of in seconds. Frequency response will be needed outside a dead band of =À0:1 Hz. The dead band is essential for stable operation of a plant otherwise the plant could oscillate and plant failures have occurred due to a lack of a dead band. Frequency droop is a major problem in plants due to machinery degrada- tion. The standard droop setting is about 5%, which means that a grid frequency drop of 5% would cause an increase of the load by 100%. Gas turbines can easily take swings of 20  ±30% but large swings cause changes in firing temperature, which places a large strain on the hot section of the turbine. Gas turbines are rated for peak operation to about 10  ±15% of their base load. It is therefore suggested that the gas turbine be operated at about 95% of the base load so that there is room for adjustment. Figure 19-4 shows the behavior of the gas turbine for changes in frequency as a stand-alone and also for changes as part of a combined cycle plant. The figure shows changes in the Gas Turbine plant (GT), the Steam Turbine plant (ST) and the Gas Turbine (GTC) and the steam turbine (STC) as part of a steam turbine plant. In a Combined Cycle Power Plant, the falling FREQUENCY DROOP (%) –100 –80 –60 –40 –20 0 20 40 60 80 100 –5 –4 –3 –2 –1 0 1 2 3 4 5 GT&ST ST GT&GTC GTC STC LOAD CHANGE (%) Figure 19-4. Droop curves for Combined Cycle Power Plants. 640 Gas Turbine Engineering Handbook G:/GTE/FINAL (26-10-01)/CHAPTER 19.3D ± 641 ± [634±691/58] 1.11.2001 2:38PM frequency is usually taken up by the GTC, by a fast change in increasing the load, since the steam turbine cannot respond fast enough. For an increasing frequency, the gas turbine and the steam turbine both can respond, thus, as shown in the figure, the gas turbine (60% load) and the steam turbine (40% load) take their appropriate change in load. The startup and shutdown of a typical gas turbine is shown in figures 19-5 and 19-6, respectively. The time and percentages are approximate values and will vary depending upon the turbine design. The gas turbine during the start-up is on an auxiliary drive, initially it is brought to a speed of about 1200  ±1500 RPM when ignition takes place and the turbine speed and temperature rise very rapidly. The bleed valves are open to prevent the compressor from surging. As the speed reaches about 2300  ±2500 rpm, the turbine is declutched from its start-up motor, the first set of bleed valves are closed, and then as the turbine has reached near full speed, the second set of bleed valves are closed. If the turbine is a two or three shaft turbine as is the case with aero-derivative turbines, the power turbine shaft will ``break loose'' at a speed of about 60% of the rated speed of the turbine. The turbine temperature, flow, and speed increases in a very short time of about three to five minutes to the full rated parameters. There is usually a short period of time where the temperature may overshoot. If supplementary firing or steam injection for power augmentation is part of the plant system, these should be turned on only after the gas turbine has reached full flow. The injection of steam for power augmentation, if done before full load, could cause the gas turbine compressor to surge. The shutdown of a gas turbine first requires the shutdown of the steam injec- tion and then the opening of the bleed valves to prevent the compressor from 0 20 40 60 80 100 120 0 2 4 6 8 10 12 Time in Minutes Load Speed Firing Temperature Percent change of parametres(%) Figure 19-5. A typical startup curve for a gas turbine. Control Systems and Instrumentation 641 G:/GTE/FINAL (26-10-01)/CHAPTER 19.3D ± 642 ± [634±691/58] 1.11.2001 2:38PM surging as the speed is reduced. The gas turbine, especially for frame type units, must be put on a turning gear to ensure that the turbine rotor does not bow. The lubrication systems must be on so that the lubrication can cool of the various components, this usually takes about 30  ±60 minutes. Startup Sequence One of the major functions of the combined control-protection system is to perform the startup sequence. This sequence ensures that all subsystems of the gas turbine perform satisfactorily, and the turbine does not heat too rapidly or overheat during startup. The exact sequence will vary for each manufacturer's engine, and the owner's and operator's manual should be consulted for details. The gas turbine control is designed for remote operations to start from rest, accelerate to synchronous speed, automatically synchronize with the system, and be loaded in accordance with the start selector button depressed. The control is designed to automatically supervise and check as the unit proceeds through the starting sequence to load condition. A typical startup sequence for a large gas turbine follows: Starting preparations. The steps necessary to prepare the services and apparatus for a typical startup are as follows: 1. Close all associated control and service breakers. 2. If the computer has been de-energized, close the computer breaker, start the computer, and enter time of day. Under normal conditions, the computer is left running continuously. 0 20 40 60 80 100 120 0 2 4 6 8 10 12 14 Time in Minutes Percent of Parameters (%) Flow Power Firing Temperature Speed Figure 19-6. A typical shutdown curve for a gas turbine. 642 Gas Turbine Engineering Handbook G:/GTE/FINAL (26-10-01)/CHAPTER 19.3D ± 643 ± [634±691/58] 1.11.2001 2:38PM 3. Place maintenance switches to ``Auto.'' 4. Acknowledge any alarm condition. 5. Check that all lockout relays are reset. 6. Position ``Remote-Local'' switch to desired position. Startup description. When the unit is prepared to start, the ``Ready to Start'' lamp will be lit. With local control, operating one of the following push buttons will initiate a start: 1. Load minimum start. 2. Load base-start. 3. Load peak-start. The master contactor function will accomplish: 1. Secondary auxiliary lube pump starter energized. 2. Instrument air solenoid valve energized. 3. Combustor-shell pressure transducer line drain solenoid valve energized. When the auxiliary lube pump builds up sufficient pressure, the circuit to close the turbine gear starter will be completed. Thirty seconds are allowed for the lube pressure to build up, or the unit will shutdown. With the signal that the turning-gear line-starter is picked up, the sequence will continue. Next, the starting-device circuit is energized if lube oil pressure is sufficient. The turning-gear motor will be turned off at about 15% speed. When the turbine has reached firing speed, the turbine overspeed trip solenoid and vent solenoid will be energized to reset. With the build up of overspeed trip oil pressure, the ignition circuit is energized. The ignition will energize or initiate: 1. Ignition transformers. 2. Ignition time function (30 seconds allowed for establishing flame on both detectors or the unit will be shut down after several tries). 3. Appropriate fuel circuits (as determined from mode of fuel selected). 4. Atomizing air. 5. Ignition time function (to de-energize ignition at the proper time). At approximately 50% speed, as sensed by the speed channel, the start- ing device is stopped. The bleed valves are closed near synchronous speed, each at a particular combustor-shell pressure. After fuel is introduced and Control Systems and Instrumentation 643 G:/GTE/FINAL (26-10-01)/CHAPTER 19.3D ± 644 ± [634±691/58] 1.11.2001 2:38PM ignition confirmed, the speed reference is increased at a preset variable rate and will determine the fuel valve position set point. The characterized speed reference and compressor inlet temperature will provide a feed- forward signal that will approximately position the fuel valves to maintain the desired acceleration. The speed reference will be compared with the shaft-speed signal, and any error provides a calibration signal to ensure that the desired acceleration is maintained. This mode of control will be limited by maximum blade path and exhaust temperatures corresponding to the desired turbine inlet temperatures. If desired acceleration is not maintained, the unit must be shut down. This control avoids many major turbine failures. With the advance of the turbine to idle speed, the turbine is ready to synchronize, and control is considered in synchronization. Both manual and automatic synchronizing are available locally. The unit is synchronized, and the main breaker closed. The speed reference will be switched to become a load reference. The speed/load reference will be automatically increased at a predetermined rate so that the fuel valve will be at the approximate position required for the desired load. For maintenance scheduling, the computer will count the number of normal starts and accumulate the number of hours at the various load levels. Shutdown. Normal shutdown shall proceed in an orderly fashion. Either a local or remote request for shutdown will first reduce the fuel at a predetermined rate until minimum load is reached. The main and field breakers and the fuel valves will be tripped. In an emergency shutdown, the main and field breakers and fuel valves will be tripped immediately without waiting for the load to be reduced to minimum. All trouble shutdowns are emergency shutdowns. The turbine will coast down and as the oil pressure from the motor-driven pump drops, the DC auxiliary lube oil pump will come on. At about 15% speed, the turning-gear motor will be restarted, and when the unit coasts to turning-gear speed (about five rpm), the turning-gear over-running clutch will engage, allowing the turning-gear motor to rotate the turbine slowly. Below ignition speed, the unit may be restarted; however, the unit must be purged completely of any fuel. This is accomplished by moving through the turbine at least five times its total volume flow. If left on turning gear, it will continue until the turbine exhaust temper- ature decreases to 150  F (66  C), and a suitable amount of time (up to 60 hrs) has elapsed. At this point, the turning gear and auxiliary lube oil pump will stop and the shutdown sequence is complete. On recognition of a shutdown condition, various contact status and analog values are saved (frozen) for display, if desired. 644 Gas Turbine Engineering Handbook [...]... (26 -10-01)/CHAPTER 19.3D ± 664 ± [634±691/58] 1.11 .20 01 2: 38PM 664 Gas Turbine Engineering Handbook Table 19 -2 Criteria for Selection of Pressure and Temperature Sensors for Compressor Efficiency Measurements Compressor Pressure Ratio P2/P1 6 7 8 9 10 11 12 13 14 15 16 P2 Sensitivity (%) T2 Sensitivity (%) 0.704 0.750 0.788 0. 820 0.848 0.873 0.895 0.906 0.933 0.948 0.963 0 .21 8 0 .23 1 0 .24 0 0 .25 0 0 .26 0... 2  F (Æ1  C) G:/GTE/FINAL (26 -10-01)/CHAPTER 19.3D ± 666 ± [634±691/58] 1.11 .20 01 2: 38PM 666 Gas Turbine Engineering Handbook copper/constantan –300 iron/constantan –300 chromel/alumel –300 750 1600 23 00 chromel/constantan 32 platinum, 10% rhodium/platinum 32 platinum, 13% rhodium/platinum 1800 32 2800 29 00 platinum, 30% rhodium/ platinum, 6% rhodium platinel 1813/platinel 1503 100 32 327 0 23 72. .. 0 .25 0 0 .26 0 0 .26 5 0 .27 0 0 .27 7 0 .28 2 0 .28 7 0 .29 0 Tabulation showing percent changes in P2 and T2 needed to cause ‰% change in air compressor efficiency Ideal gas equations are used  one considers the fact that the gas turbine ingests about 7000±9000 cf  (198 .21 79 25 4.8516 cm) of air per minute for every megawatt of power produced Temperature and Pressure Measurement for Compressors and Turbines Temperature... it relates to each of these three phenomena, can be appreciated if Gas Turbine Engineering Handbook G:/GTE/FINAL (26 -10-01)/CHAPTER 19.3D ± 6 62 ± [634±691/58] 1.11 .20 01 2: 38PM 6 62 Figure 19-10 Instrumentation for monitoring and diagnostics on a gas turbine engine G:/GTE/FINAL (26 -10-01)/CHAPTER 19.3D ± 663 ± [634±691/58] 1.11 .20 01 2: 38PM Control Systems and Instrumentation 663 Figure 19-11 Instrumentation... G:/GTE/FINAL (26 -10-01)/CHAPTER 19.3D ± 668 ± [634±691/58] 1.11 .20 01 2: 38PM 668 2 3 4 Gas Turbine Engineering Handbook Compressor discharge Same as compressor inlet thermocouples One or two units required in this area Turbine inlet temperature Thermocouple is constructed of platinumplatinum rhodium with the junction enclosed with ceramic insulation  Typically, 9± 12 units are required at this stage Turbine. .. system G:/GTE/FINAL (26 -10-01)/CHAPTER 19.3D ± 665 ± [634±691/58] 1.11 .20 01 2: 38PM Control Systems and Instrumentation 665 Temperature Measurement Temperature measurement is important to gas turbine performance Exhaust gas temperature should be monitored to avoid overheating of turbine components Most gas turbines are equipped with a series of thermocouples in their exhausts Measuring turbine inlet temperature... filter system is to protect the gas turbine The performance of the gas turbine inlet-air filter system has important and far-reaching influences on overall maintenance costs, reliability, and availability of gas turbines There are three major results of improper air filtration: (1) erosion, (2) fouling of the axial-flow compressor, and (3) corrosion of the gas turbine hot -gas path inlets The importance... system utilizing RTDs can be accurate to Æ0: 02  F (Æ0:01  C) Pyrometers The use of pyrometers in control of the advanced gas turbines is being investigated Presently all turbines are controlled based on gasifier turbine exit temperatures or power turbine exit temperatures By measuring the G:/GTE/FINAL (26 -10-01)/CHAPTER 19.3D ± 667 ± [634±691/58] 1.11 .20 01 2: 38PM Control Systems and Instrumentation... cycle and thus the G:/GTE/FINAL (26 -10-01)/CHAPTER 19.3D ± 658 ± [634±691/58] 1.11 .20 01 2: 38PM 658 Gas Turbine Engineering Handbook operation of the plant Life cycle costs, based on a 25 -year life, indicate that the following are the major cost parameters: 1 2 3  Initial purchase cost of equipment is 7±10% of the overall life cycle cost  Maintenance costs are about 15 20 % of the overall life cycle cost... termed a ``breakdown'' Ref: “Power Plant Diagnostics Go On-Line” Mechanical Engineering December 1989 1.00 Unit Cost 0.75 0.50 0 .25 0.00 Corrective Preventive Predictive Figure 19-7 Comparison between various maintenance techniques G:/GTE/FINAL (26 -10-01)/CHAPTER 19.3D ± 646 ± [634±691/58] 1.11 .20 01 2: 38PM 646 Gas Turbine Engineering Handbook or ``fix as fail'' repair strategy, to a ``preventive'' regime, . continuously. 0 20 40 60 80 100 120 0 2 4 6 8 10 12 14 Time in Minutes Percent of Parameters (%) Flow Power Firing Temperature Speed Figure 19-6. A typical shutdown curve for a gas turbine. 6 42 Gas Turbine Engineering Handbook G:/GTE/FINAL. (%) –100 –80 –60 –40 20 0 20 40 60 80 100 –5 –4 –3 2 –1 0 1 2 3 4 5 GT&ST ST GT&GTC GTC STC LOAD CHANGE (%) Figure 19-4. Droop curves for Combined Cycle Power Plants. 640 Gas Turbine Engineering Handbook G:/GTE/FINAL. loop. 636 Gas Turbine Engineering Handbook G:/GTE/FINAL (26 -10-01)/CHAPTER 19.3D ± 637 ± [634±691/58] 1.11 .20 01 2: 38PM Temperature Speed TIME Ignition Tempe rature Speed Figure 19 -2. Startup