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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, and4‐1 Constant Pressure heat
rejection
Temperature Entropy diagram
T
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)
T1 (>0) (sec) T2 (>0) (sec) T3 (>0) (sec)
Ambient temperature load limit, AT KT VMAX VMIN Dturb
0.05 0.4 0.1 3 1 2 0.95 -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 waterinjection and inlet guidevanes 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
SIMULATION OF AVR
AVR1_dat.m required
Kr
Tr.s+1Transfer Fcn4
Kf.s
Tfa.s+1Transfer Fcn3
Ke
Te.s+1Transfer Fcn2
1
s+1Transfer Fcn1
Ka
Ta.s+1Transfer Fcn
t
To Workspace1
Vt
To Workspace
Step Scope
Clock
Xne FsrnFa
Fb
SPEEDGOVERNOR
FUELLIMITS
VALVEPOSITIONER
GAS FUELSYSTEM
Fc
Fsr
F2
ROTOR
ROTOR SPEED
Wf
FIG NO. BLOCK DIAGRAM OF A GAS TURBINE
Tre
Fsrt
Tm
Txm1
Tx
Aligv
Wx
Tx2
Tx3Tx1
Tre Tr1
IGV TempControl
IGV actuator
IGV limits
Fuel TempControl
Thermocouple
Radiationsheild
0.46
1.0 1.0
0.46
n
To Workspace1
t
To Workspace
Tload
In1
In2Out1
In1
In2Out1
In1
In2Out1
In1
In2Out1
Out1
Out1
In1
In2
Out1
In1Out1
In1
In2
In3
Out1
In1
In2
In3
Out1
In1
In2Out1
In1
In2Out1
In1
In2
Out1
Scope1
Scope
min
1s
1s
1s
Zg
-K-
0.2
1/Tt
0.3/Tt
1/T1
Akf
-K-Wg
0.23Xnr
Clock
0 10 20 30 40 50 60 70 80 90 1000.999
1
1.001
1.002
1.003
1.004
1.005
1.006
1.007
1.008
1.009
Time(Sec)
Spe
ed(p
.u)
SIMULATION OF GT GOVERNOR SYSTEM
Different positioner gains
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
AIRINLET
FUEL
COMBUSTOR
DRIVENEQUIPMENT
COMPRESSOR TURBINE
AIRINLET
FUEL
COMBUSTOR
DRIVENEQUIPMENT
COMPRESSOR TURBINE
EXHAUSTGAS
Combined cycle plant
Combined Cycle (Brayton & Rankine Cycles)
LOW PRESSURE STEAM(For Deaeration)
INTERMEDIATEPRESSURESTEAM
HIGHPRESSURESTEAM
HEAT RECOVERYSTEAM GENERATOR
INTERMEDIATE PRESSURE STEAM(To Intermediate Pressure Steam Turbine)
HIGH PRESSURE STEAM(To High Pressure Steam Turbine)
TURBINECOMPRESSOR
GENERATOR
ELECTRICPOWER
AIRINLET
COMBUSTOR
FUEL
EXHAUST GAS
GENERATOR
ELECTRICPOWER STEAM
EXHAUST
CONDENSATE RETURN TO HRSGGAS TURBINE STEAM TURBINE
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
AIR INLETFILTERAIR INLETFILTER
GASTURBINEGASTURBINE
EXHAUSTBYPASSSILENCER
EXHAUSTBYPASSSILENCER
GENERATORGENERATOR
DIVERTERVALVEDIVERTERVALVE
SUPPLE-MENTARYBURNER
SUPPLE-MENTARYBURNER
HEATRECOVERYSTEAMGENERATOR(HRSG)
HEATRECOVERYSTEAMGENERATOR(HRSG)
EXHAUSTSILENCEREXHAUSTSILENCER
PROCESSSTEAMPROCESSSTEAM
Steam Turbine
Combined Cycle Power Plant
Captive Power Plant - General Overview
NAPHTHAGAS OIL
GAS TURBINENAPHTHAGAS OIL
8 X 125 TPH HRSG
AUX BOILERS
4 x 125 TPH
Refinery Fuel Oil
STEAM TURBINE
HP steam 42 Kg/cm2
MP steam 17 Kg/cm2To Refinery
Power Steam
INSTALLED CAPACITY 360 MW 1500 TPHPRESENT GENERATION 269 MW 979 TPHEXPORT TO GEB CAPABILITY 80 MW ------------
TO GEB 132/220 kV
TO REFINERY
4 X 30 MW
8 X 30 MW
11 KV
33 KV
33 KV
11 KV
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 outputMW (ISO) MW (350 C) ( MW)
PG 6541 37.52 32.64 28.7PG 6551 38.48 33.48 28.7PG 6561 38.82 33.77 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 NADBPS HRSGs (01 No) 125 125 NAThermax HRSGs (01 No.) 125 125 134*
(* Steam flow for one hour in 08 hrs. shift)
• 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
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.)
Steam Turbine
MP133TPH
LP60TPH
Normal steam flowHP section =15.27 MWMP section = 5.73 MWLP section = 11.81 MW
• 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 triedfor 01hr.
Auxiliary Boilers
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 80 186.3HP to MP 24.9 47.4 138MP to LP 9.1 34.9 120Start up & letdown ‐ 12.5 25(HHP to HP)
STEAM SYSTEM
Boilers Nos. Nos. in operation Generation (TPH)
Auxiliary Boilers 4 4 500HRSGs 8 8 880Total 12 12 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.
X132‐1 132‐2
132 kV GEB BUS132‐3
132 kV RPL BUS
132‐4 132‐5 132‐6 132‐7
RIL 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
A3 B10 A4 A7A4 A7 B4 B8 A5 A6 B7 B11 A12 A3 B5 B4 A12 A3 B11 B3
ES‐EE941‐01 ES‐EE941‐02 ES‐RU772‐01 ES‐RU772‐02
MRS # 1 : BOARD # 1 MRS # 1 : BOARD # 2 MRS # 2 BOARD # 1 MRS # 2 BOARD # 2
1.HYDJN 5.75 MW M
2.PP STRM A/B‐A 2.UTILITY 2A 2.UTILITY 1A 2.RTF S/S 2 A 2.TNSHIP A 2.HYDRJN B
3.UTILITY 2B
8.RTF S/S 1A 8. FCC A
9. PLATFMR 7.3 MW
6.PRT 2 FCC
7.FCC 10 MW M
BUS A BUS B
2.TNSHIP B
4.HYDJN 5.75 MW M
5.MTF L2‐C1
6.MTF L2‐C2
7.RTF S/S 1 B
1.FCC B
3.UTILITY 1B
4.CPP 772‐B
5.RRTF B
BUS A BUS BBUS A BUS B
6.MTF L1‐C2
7.CRUDE 1 4.4 MW M
9.CRUDE 1 A
10.CRUD 2, 4.4MW M
1.COKER A
3.PLATFMR/HNUU A
4. PRT 1 FCC
5.MTF L1‐C1
4.CRUDE 1 4.4MW M
6.CPP 772 A
1.CRUDE 2 A
3.COKER B
4.RRTF A
5.PLATFMR 7.3 MW
7.PLATFMR 7.3 MW
1.CRUDE 2 B
3.CRUD 2, 4.4 MW M
4.SULPHER B
5.PLATFMR/HNUU B
6.RTF S/S 2 B
7.CPP 941 B
1.SULPHER A
3.HYDRGN A
6.AROM.TATORY A
5.HYDJN 5.75 MW M
6.AROM.TATORY B 6.CRUDE 1 B
7.AROM.PX.TR.3 A
8.CPP 941 A
7.AROM.733 CT B
2.AROM.PX.TR.2B
3.AROM.PX.TR.3B
4.PP STRM A/B‐B
5.PP STRM C‐B
3.PP STRM C‐A
4.AROM.PX. TR.1 A
5.AROM.PX.TR.2 A
BUS A BUS B
1. AROM. 733 CT A 1.AROM.PX.TR.1B
RIL RPL RPL RPL
CPP Generation and Distribution Overview
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 consumptioncauses 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