Modeling of Gas Turbine and Its Control System Dr M S R Murty Gas Turbine Scheme Brayton Cycle • The cycle is made up of four completely irreversible processes: 1‐2 Isentropic Compression; 2‐3 Constant Pressure heat addition; 3‐4 Isentropic Expansion, and 4‐1 Constant Pressure heat T rejection Temperature Entropy diagram Brayton Cycle • Air is first compressed in an adiabatic process with constant entropy within the compressor (process 1–2), usually an axial compressor. Pressure of 13–20 times that of atmospheric is achieved after the compression stage. • Fuel, either liquid of gas is then mixed with the compressed air and burnt in the combustor (process 2–3). After which, the hot gasses is allowed to expand through the turbine (process 3–4). This gas expansion drives the blades of the turbine and consequently the shaft of the generator connected to it. Transfer Function Block Diagram: Rowen’s Model GT Controls modelled • There are four blocks related with speed/load control, temperature control, fuel control, and air control. • Speed/load control : determines the fuel demand according to the load reference and the rotor speed deviation • Temperature control: restricts the exhaust temperature not to injure the gas turbine. The measured exhaust temperature is compared with the reference temperature. The output is the temperature control signal . GT Controls • The fuel demand is compared with the temperature control signal in the fuel control block. The lower value is selected by the low value selector, and it determines the fuel flow • The air control block adjusts the airflow through compressor inlet guide vanes (IGV) so as to attain the desired exhaust temperature. The exhaust temperature is kept lower than its rated value (say 1 %). Airflow Control • The adjustable airflow is about 30% of the rated airflow. The adjusting speed is slow compared with the fuel flow. • The airflow is proportional to the rotor speed. GT Operating parameters Wf= fuel flow , W = the airflow , Te = Exhaust temperature, Tr = reference temp. Tf = turbine inlet temp Generation of Valve Control signal Power Output Temperature control Rotor Inertia Simplified GT Model PID Governor Detailed Model The droop circuit includes an intentional filter time constant, Td, of 0.8 s. GT Models in PSS/E • GAST Gas turbine‐governor model ‐ Simple model • GAST2A Gas turbine‐governor model ‐ Similar to the Rowen model • GASTWD Gas turbine‐governor model ‐ Suitable for Woodward governors GAST Model in PSS/E Fuel valve opening Flow Exhaust Temp R (speed droop) 0.05 Ambient temperature T2 (>0) (sec) T3 (>0) (sec) load limit, AT KT T1 (>0) (sec) 0.4 0.1 3 1 VMAX 2 VMIN 0.95 Dturb -0.05 0 Step change in Speed Reference Each division 10 Seconds Each division 10 Seconds Twin Shaft GT Permanent Droop using CDP • Compressor Discharge Pressure (CDP) rather than valve position or electrical power feedback is used for permanent droop setting on some units • Typical values of CDP versus output power is shown in the table The discontinuity between 25% and 40% power is when the water injection and inlet guide vanes go into service. On line Step response Off line Step response Typical frequency response curves OUTER LOOP CONTROLS: Load control • Some units are operated with an outer‐loop active power controller. Digital Unit Controller produces a pulse to the governor raise or lower input that is proportional to the distance away from the MW set‐point. • The governor is programmed to ramp the reference at a rate of 0.3%/s when receiving these pulses. Outer Loop Control : pf/VAr Controller • Many gas turbine units are equipped with a pf/VAr controller which is in service whenever the unit is on‐line. This is an outer‐loop control, which monitors generator stator reactive current and controls to a fixed VAr or pf set‐point. • The controller is often used in pf mode, controlling to unity power factor. • The control structure is an “integrator with gain” feedback to the AVR set‐point. Pf/ VARController • To ride through system transient disturbances, the control should be as slow as possible, however, too long a setting will result in operator intervention and overshoot in the resulting unit operating point. Simulink Model Ka Step Ke 1 T a.s+1 T e.s+1 s+1 T ransfer Fcn T ransfer Fcn2 T ransfer Fcn1 Scope Vt Kf.s T o Workspace T fa.s+1 T ransfer Fcn3 Kr t T r.s+1 Clock T ransfer Fcn4 SIM ULAT ION OF AVR AVR1_dat.m required T o Workspace1 1.0 1.0 Aligv In1 0.2 Tr1 T re -KFuel T emp Control 1 s Tm Fsr In3 Xne Fsrn In1 Fa GAS FUEL SYST EM In1 Out1 In2 -KFb Tx2 Tx VALVE POSITIONER min FUEL LIMITS Out1 In1 In3 0.23 In2 Out1 Tx3 Out1In2 Out1 In2 Fsrt Out1 In1 Txm1 In1 1/Tt Tx1 Radiation sheild T hermo couple Xnr Wg Wx IGV actuator Out1 In1 In2 IGV limits IGV T emp Control Tre Out1 0.46 0.46 0.3/T t 1 s In1 Out1 In2 Out1 In2 In1 In1 Out1 In2 Out1 In2 Fc Zg Akf ROTOR SPEED GOVERNOR Wf In1 1 s ROT OR SPEED T load 1/T 1 Out1 F2 In2 n To Workspace1 FIG NO. BLOCK DIAGRAM OF A GAS TURBINE Scope t Clock To Workspace Scope1 SIMULATION OF GT GOVERNOR SYSTEM 1.009 Different positioner gains 1.008 1.007 Speed(p.u) 1.006 1.005 1.004 1.003 1.002 1.001 1 0.999 0 10 20 30 40 50 60 Time(Sec) 70 80 90 100 Combined cycle • Heat engines are only able to use a portion of the energy their fuel generates (usually less than 30%). The remaining heat from combustion is generally wasted. • Combining two or more "cycles" such as the Brayton cycle (Gas Cycle) and Rankine cycle (Steam Cycle) results in improved overall efficiency. Simple GT cycle FUEL AIR INLET COMBUSTOR EXH AU ST G AS DRIVEN EQUIPMENT COMPRESSOR TURBINE Combined cycle plant Combined Cycle (Brayton & Rankine Cycles) EXHAUST GAS LOW PRESSURE STEAM (For Deaeration) AIR INLET FUEL INTERMEDIATE PRESSURE STEAM (To Intermediate Pressure Steam Turbine) COMBUSTOR HIGH PRESSURE STEAM (To High Pressure Steam Turbine) GENERATOR HEAT RECOVERY STEAM GENERATOR GENERATOR ELECTRIC POWER COMPRESSOR TURBINE ELECTRIC POWER GAS TURBINE STEAM TURBINE HIGH INTERMEDIATE PRESSURE PRESSURE STEAM STEAM CONDENSATE RETURN TO HRSG STEAM EXHAUST HRSG • Steam is generated by firing hot exhaust gases from Gas turbines (GTs) • Remaining steam required is generated by firing Supplementary fuel. Typical Industrial Cogeneration System EXHAUST BYPASS SILENCER EXHAUST SILENCER DIVERTER VALVE AIR INLET FILTER HEAT RECOVERY STEAM GENERATOR (HRSG) GENERATOR GAS TURBINE SUPPLEMENTARY BURNER PROCESS STEAM Steam Turbine Combined Cycle Power Plant Captive Power Plant - General Overview AUX BOILERS NAPHTHA GAS OIL 4 x 125 TPH Refinery Fuel Oil 8 X 30 MW GAS TURBINE NAPHTHA GAS OIL 11 KV 8 X 125 TPH 33 KV HRSG 4 X 30 MW STEAM TURBINE TO REFINERY 11 KV TO GEB 132/220 kV 33 KV HP steam 42 Kg/cm2 Power Steam MP steam 17 Kg/cm2 INSTALLED CAPACITY PRESENT GENERATION EXPORT TO GEB CAPABILITY 360 MW 269 MW 80 MW 1500 TPH 979 TPH ------------ To Refinery GAS TURBINES • • • • 5 Nos, GE Frame-6 machines supplied by BHEL, Hyderabad 3 Nos, GE Frame-6 machines supplied by NP, Italy. GT # 1 & 4 are having BLACK START CAPABILITIES. All gas turbines are capable to run at base load with spread well within the limit : • Machine Design output Design output Site output MW (ISO) MW (350 C) ( MW) PG 6541 PG 6551 PG 6561 37.52 38.48 38.82 32.64 33.48 33.77 28.7 28.7 28.7 HRSG •HRSG load with GT at base load in unfired mode: HHP Steam (TPH) BHEL HRSGs (06 nos.) 53‐55 DBPS HRSG (01 No.) 53‐55 Thermax HRSG (01 No.) 53‐55 •HRSG load with GT at base load in fired mode: Steam (TPH) Design(TPH) Max (TPH) BHEL HRSGs (06 Nos.) 125 125 NA DBPS HRSGs (01 No) 125 125 NA Thermax HRSGs (01 No.) 125 125 134* (* Steam flow for one hour in 08 hrs. shift) Steam Turbine • All 4 STGs are tested to deliver 30 MW of power. • Steam turbines are provided with HP and MP extractions • Maximum steam flow through one steam turbine shall be as follows 262 TPH HHP steam (Max) Pr: 109 Kg/CM^2 @ 505 DegC MP 133 TPH LP 60 TPH 180 TPH HP steam (Max) 149 TPH HP steam (Normal) Pr: 44.8 Kg/CM^2 @ 383 DegC 80 TPH MP steam (Max) 53 TPH MP steam (Normal) Pr: 18.8 Kg/Cm^2 @ 282 DegC 60 TPH to Condenser (Max.) 20 TPH to Condenser (Min.) Normal steam flow HP section =15.27 MW MP section = 5.73 MW LP section = 11.81 MW Auxiliary Boilers • All 4 Auxiliary Boilers are capable to deliver 125 TPH , at 115 KG/CM2(g) and 510 Deg C. • 10 % overload margin i,e 137 TPH at 110 KG/CM2 (g) and 5100 C also tried for 01hr. PRDS Six PRDS are provided to supply HP, MP & LP steam to the process. PRDS is sized to meet the demand normally met by two steam turbines on the basis that one trips whilst another is out of service for maintenance. Design flow rates (TPH) of PRDS are : Min. Normal Max. HHP to HP 21.4 80 186.3 HP to MP 24.9 47.4 138 MP to LP 9.1 34.9 120 Start up & letdown ‐ 12.5 25 (HHP to HP) STEAM SYSTEM Boilers Nos. Nos. in operation Generation (TPH) Auxiliary Boilers HRSGs Total 4 8 12 4 8 12 500 880 1380 • Auxiliary boilers able to ramp up 9 MT /Min/boiler in case of emergency without much pressure variation at HHP level • Able to meet steam demand when both PRTs trip. • Able to supply HP and MP steam, without pressure drop, if STG trips. CPP Generation and Distribution Overview X 132‐1 132‐2 132 kV GEB BUS 132‐3 132 kV RPL BUS 132‐4 132‐5 RIL 132‐6 132‐7 RPL GTG # 8 GTG # 3 GTG # 2 STG # 2 GTG # 1 STG # 1 STG # 3 GTG # 4 GTG # 5 GTG # 6 GTG # 7 STG # 4 G G G G G G G G G G G G A7 B4 B8 A6 B7 B11 A12 A3 B5 A3 B11 B3 A3 B10 A4 A5 ES‐EE941‐01 A7 BUS B ES‐RU772‐02 MRS # 2 BOARD # 1 MRS # 2 BOARD # 2 RPL RPL RPL BUS A A12 ES‐RU772‐01 MRS # 1 : BOARD # 2 RIL BUS B B4 ES‐EE941‐02 MRS # 1 : BOARD # 1 BUS A A4 BUS A BUS B BUS A BUS B 1. AROM. 733 CT A 1.AROM.PX.TR.1B 1.SULPHER A 1.CRUDE 2 B 1.CRUDE 2 A 1.COKER A 1.FCC B 1.HYDJN 5.75 MW M 2.PP STRM A/B‐A 2.AROM.PX.TR.2B 2.UTILITY 2A 2.UTILITY 1A 2.RTF S/S 2 A 2.TNSHIP A 2.HYDRJN B 2.TNSHIP B 3.PP STRM C‐A 3.AROM.PX.TR.3B 3.HYDRGN A 3.CRUD 2, 4.4 MW M 3.COKER B 3.PLATFMR/HNUU A 3.UTILITY 1B 3.UTILITY 2B 4.AROM.PX. TR.1 A 4.PP STRM A/B‐B 4.CRUDE 1 4.4MW M 4.SULPHER B 4.RRTF A 4. PRT 1 FCC 4.CPP 772‐B 4.HYDJN 5.75 MW M 5.AROM.PX.TR.2 A 5.PP STRM C‐B 5.HYDJN 5.75 MW M 5.PLATFMR/HNUU B 5.PLATFMR 7.3 MW 5.MTF L1‐C1 5.RRTF B 5.MTF L2‐C1 6.AROM.TATORY A 6.AROM.TATORY B 6.CRUDE 1 B 6.RTF S/S 2 B 6.CPP 772 A 6.MTF L1‐C2 6.PRT 2 FCC 6.MTF L2‐C2 7.AROM.PX.TR.3 A 7.AROM.733 CT B 7.PLATFMR 7.3 MW 7.CPP 941 B 7.CRUDE 1 4.4 MW M 7.FCC 10 MW M 7.RTF S/S 1 B 8.CPP 941 A 8.RTF S/S 1A 8. FCC A 9.CRUDE 1 A 9. PLATFMR 7.3 MW 10.CRUD 2, 4.4MW M Power Plant Control • Plant parameters are to be maintained by closed loop control • Boiler: Steam parameters like pressure, temperature, other process parameters like furnace pressure, drum level • Turbine‐ Generator : Power (MW), speed or frequency Need for Control • Mismatch in generation and consumption causes deviation in plant parameter • Mismatch in steam flow: pressure change • Mismatch in heat flow: temperature change • Mismatch in power: speed change • Mismatch in gas flow: furnace. pr. change Control Systems • • • • GTG Control System (GE Mark V) STG Control System (GHH Borsig) Burner Management System (AB PLC):48 Foxboro DCS Control Systems Distributed control System (Foxboro) ‐ 38 nodes Emergency Shutdown System (Triconex) ‐ 26 no. Fire & Gas System (Wormald) ‐ 35 no. Machine Condition Monitoring System (Bentley Nevada) ‐ 23 no. • Automatic Tank Gauging System (SAAB) ‐ 259 no. • • • • Electrical Load Distribution Management System • • • Two major functions – Load management System (LMS) – Electrical Distribution Management System (EDMS) LMS functions: – Load shedding – Active/Reactive power control – Synchronisation EDMS main functions: – Data logging & reporting – circuit breaker control – Power System Event Recording & Alarm Annunciation's Combined Cycle Plant: Scheme for Modeling Model of Combined Cycle Power Plant