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