Modeling of Gas Turbine and Its Control System

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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, 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
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