Better Technology
For a Cleaner Environment
POWER PLANTS¶ MAIN COMPONENTS & CONTROL
Jenö Kovács
Power generation
± Power generation principles
± Direction of development
± Example: World¶s first supercritical CFB OTU boiler
Main control tasks
± Power control
± Frequency control
± Unit control principles
SCHEDULE
Power generation
± Power generation principles
» Thermal and electrical power
» Energy sources and energy conversion processes (with/out combustion)
» Steam (gas) cycle plants
» Efficiency map
± Fuel flexibility:
» Fluidization principle
» BFB, CFB boilers
± Possibility to increase efficiency: OTU boilers
± Example: First supercritical CFB OTU boiler (Lagisza)
POWER GENERATION
Energy sources Power Plants Energy demand
Renewable Without combustion
wind, solar, hydro, tidal, wind- , solar- , hydro- , Electrical power
wave, geothermal, geothermal- , tidal-, electricity
biomass/fuel wave power plants
Thermal power
Fossil With combustion steam
coal, oil, gas, peat coal, oil, gas, peat hot water
biomass/fuel
steam/gas cycle
Nuclear
Nuclear power plant
POWER GENERATION
Primary energy carriers:
solar-, wind-, hydro-, tidal-, marine power
Geothermal energy
Pyhäkoski hydro power plant
Wind turbine Tidal turbine
Solar Two ± Mojave Desert, California 11 MW Photovoltaic Wave energy
COMBUSTION BASED POWER GENERATION
Chemical Thermal Mechanical Electrical
energy energy energy energy
Boiler Turbine ~
oil, gas,
coal, peat,
z
biomass, Emissions
wood,
RDF, REF,
waste
COMBUSTION BASED POWER GENERATION
Gas turbine (GT) power plant
K | 32 44%
Chemical Thermal Mechanical Electrical
energy energy energy energy
Boiler
hot flue
GT ~
gas
District heating or
Steam generation
air flue gas
COMBUSTION BASED POWER GENERATION
Steam turbine (ST) power plant
Chemical Thermal Mechanical Electrical
energy energy energy energy
Boiler
steam
ST ~
Process District
steam heating
water
POWER GENERATION
Meri-Pori condensing power plant: 565 MWe
VTT Energia (1999): Energia Suomessa. Tekniikka, talous ja ympäristövaikutukset. Edita Oy, Helsinki.
POWER GENERATION
Rauhalahti C(ombined)H(eat)P(ower) plant: 87 MWe + 205 MWth
Source: Timo Järvinen & Eija Alakangas, VTT Energy, ALTENER AFB-NET V - Part 2 l Cofiring, l Rauhalahti CHP plant l
POWER GENERATION
Efficiency = energy out / energy in
QS >95%
60 90% >95%
QF
Energy in Energy in Mechanical Electrical
fuel, QF steam, QS energy, QM energy, QE
Boiler ST ~
QM
32 45%
QS
QM Q T Thermal
60 85% energy, QT
QS
Overall efficiency = (QE+QT)/QF = (60-90%) * (35-85%) * 95% = 20-72%
POWER GENERATION
Nowadays requirements
Less pollution
± Same amount of fuel (kg/sec) more energy out (MW) = Higher efficiency
± Solution (besides green/renewable energy):
± Increase the efficiency of combustion
± Increase the efficiency of steam cycle
± Combined heat and power generation (CHP)
Fuel flexibility
± Burn many different fuels in the same boiler
± Coal, peat, RDF, wood, «
± Solution:
± Fluidized bed combustion
POWER GENERATION
Fluidized bed combustion
Solution to fuel flexibility and combustion efficiency (>80%)
Flue gas
Flue Flue
gas gas
Fue Fue
l
Fue
l
Ai Ai Ai
Fixed Bubbling fluidized bed Circulating fluidized bed
Foster Wheeler Fluidized Bed Technology
Increasing fuel-flexibility
143 BUBBLING FLUIDIZED BED (BFB) BOILERS
FLUID BED TECHNOLOGY First unit Ideal technology for biofuels
1976
Total 7100 MWth BFB sold
141 in operation
Flue gas 2 under construction
304 CIRCULATING FLUID BED (CFB) BOILERS
1979 Total 18 602 MWe CFB sold
260 in operation for variety fuels:
Fuel coal, lignite, petroleum coke, biomass,
RDF, etc.
44 under construction
Biggest unit in operation 300 MWe
ATMOSPHERIC FLUIDIZED BED GASIFIER
1981 Ideal technology for biomass and RDF
9 gasifiers sold
Air
Developed in the 60¶ s
FOSTER WHEELER CFB
Process Description
Steam
Feed water to drum
Steam drum
Solids separator Steam outlet
Downcomer Economizer
Combustion chamber Feed water inlet
Air heater
Fuel
Dust collector
Limestone
Fly ash
Induced draft fan
Bottom ash Secondary air fan
To ash silos Primary air fan
INCREASING NET EFFICIENCY
Supercritical steam pressure
Highest achievable plant efficiency with supercritical steam parameters. One of the most effective
measures for achieving high power plant efficiency is selecting a high design steam pressure.
Efficiency increases by roughly 3% on making the transition from 167 bar (e.g. drum boiler) to 250 bar,
without significant increases in investment costs
Source [3]: Siemens AG Power Generation (2001): Benson Boilers for maximum cost-effectiveness in power plants
INCREASING NET EFFICIENCY
Supercritical steam pressure
Source: J. Franke, R. Kral, and E. Wittchow (1999):
Steam generators for the next generation of power plants aspects of design and operating performance. VGB Power Tech 12/99.
INCREASING NET EFFICIENCY
Natural Circulation vs. O(nce)T(hrough)U(nit) Design
(subcritical) (sub/supercritical)
Source: Siemens AG Power Generation (2001): Benson Boilers for maximum cost-effectiveness in power plants
PKE LAGISZA POWER PLANT
The World¶s 1st Supercritical CFB-OTU Boiler
Lagisza 460 MWe (condensing power plant), bituminous coal
The 460 MWe Lagisza CFB plant will replace 5 smaller power plants within PKE
PKE -Lagizsa
PKE LAGISZA POWER PLANT
The World¶s 1st Supercritical CFB-OTU Boiler
Lagisza 460 MWe (condensing power plant), bituminous coal
The 460 MWe Lagisza CFB plant will replace 5 smaller power plants within PKE
Improved plant efficiency 34,7% to 45,0%
Improved emissions
SO2 92% ~ 22 300 t/year reduction
Furnace:
NOx 71% ~ 4 700 t/year reduction
Depth: 11 m (36 ft)
CO2 28% ~ 970 000 t/year reduction
Width: 28 m (92 ft)
Height: 48 m (157 ft)
UNIT & LOCAL CONTROL
&
GRID FREQUENCY CONTROL
UNIT & LOCAL CONTROL
OVERALL CONTROL AIMS
Quantitative target: the required power (MW e/th)
Qualitative target: frequency & voltage
steam pressure & temperature
UNIT CONTROL
optimal/econimical operation of power plant
following changes/schedule in power requirement
maintaining emissions
LOCAL CONTROL
receives setpoint from unit control
maintains temperature, pressure, flow, ...
UNIT CONTROL
Example of a condesing power plant (MWe)
Power / frequency
measurement
p
UNIT CONTROL
Generated Power (MWe)
PMWe KG PMWturbine KG KT PMWsteam
ª kJ º ª º
PMWsteam «kW ª kg º 'h« kJ »
m
¬ sec »¼ « sec »
¬ ¼ ¬ kg ¼
enthalpy : h ~ p ressure , Temperature
PSTEAM PT PMWe
Turbine ~
UNIT CONTROL
Fixed pressure operation
Boiler follow mode PT RH
PRESSURE
SET POINT
S +/-
± Power generation controlled by turbine
PID
admission valves 2
G
± Pressure controlled by boiler demand
± Storage capacity of boiler is utilized in
load changes. (if drum type boiler)
± Rapid response to changes in load +/- S
PID MW SET
demand 1 POINT
± Difficult pressure control
BOILER
DEMAND
± Frequency support is possible.
UNIT CONTROL
Fixed pressure operation
Boiler follow mode with feedforward PT FT RH
P SET
POINT
S +/-
± Power generation controlled by turbine
PID PD
admission valves 2 1
G
± Pressure controlled by boiler demand
± Storage capacity of boiler is utilized in
load changes. S MW SET
POINT
± Rapid response to changes in load
PD
+/+
2
demand
+/-
± Difficult pressure control
BOILER
DEMAND PID
± Frequency support is possible. 1
± Feedforward (PD-type) from load
demand or steam flow to boiler FEEDFORWARD
demand is used to improve (OPTIONAL)
pressure control during load
changes.
UNIT CONTROL
Fixed pressure operation
Turbine follow mode PT RH
PRESSURE
SET POINT
± Power generation controlled by boiler S +/-
PID
demand 2
± Pressure controlled by turbine admission G
valves
± Storage capacity of boiler is not utilized
for rapid load changes.
± Sluggish response to changes in load +/- S
PID MW SET
demand 1 POINT
± Accurate (easy) pressure control
BOILER
DEMAND
± Frequency support is not possible.
± Feedforward from load demand to boiler
demand is recommended to improve
load change rate. (see next slide)
UNIT CONTROL
Fixed pressure operation
Turbine follow mode with feedforward PT RH
PRESSURE
SET POINT
± Power generation controlled by boiler S +/-
PID
demand 2
± Pressure controlled by turbine admission G
valves
± Storage capacity of boiler is not utilized
for rapid load changes. +/- S
± Sluggish response to changes in load PID MW SET
1 PD POINT
demand 1
± Accurate (easy) pressure control
BOILER
DEMAND
+/+
± Frequency support is not possible.
± Feedforward (PD-type) from load demand
to boiler demand is used to improve
load change rate. FEEDFORWARD
UNIT CONTROL
Variable pressure operation
Natural sliding pressure mode 100
± Operation with fully open turbine
Steam pressure (% pmax)
80
admission valves
Modified sliding pressure mode 60
± Operation with slightly throttled 40
turbine admission valves.
± Throttling reserve of turbine
valves can be used for Natural sliding pressure
20
immediate changes of limited Modified sliding pressure
size in power generation.
0
20 40 60 80 100
Load (% MCR)
COORDINATED UNIT CONTROL EXAMPLE
(MODAKOND by ABB)
Source: http://library.abb.com/GLOBAL/SCOT/scot221.nsf/VerityDisplay/B471E93C2DBFAB2BC1256E2300382268/$File/PT_ModConSol_MODAN_Rev5.pdf
FREQUENCY CONTROL
Grid area of UCTE
(Union for the Co-ordination of Transmission of Electricity)
FREQUENCY CONTROL in UCTE
Always an equilibrium between electricity production and consumption should exist
± Grid frequency is a measure of the equilibrium
Primary control
± Reaction time max. 30 seconds (UCTE)
± Fast power reserves are used (turbine and condensate throttling reserves)
± P ±type control Æ deviation corrected but steady-state error exists
Secondary control
± To remove steady state error after the primary frequency
Generator
control droop
action(S)
± Secondary control restores primary control reserves
PGn 'f
SG
Tertiary control fn 'PG
± Base load of a unit given mainly based on rough electricity PGn
'PG consumption 'f k 'f
predictions. fn SG
FREQUENCY CONTROL
Time scale
FREQUENCY CONTROL
Example
1. Initially no power exchange between networks
No frequency deviation
'P1 0 'P2 0
'f 0
Network 1 Network 2
FREQUENCY CONTROL
Example
1. Initially no power exchange between networks
No frequency deviation
2. Shudden loss of power in the area 2
'P1 0 'P2 0
'f z 0
'f
Network 1 Network 2
FREQUENCY CONTROL
Example
3. First primary control activated: replace the lost power
'f z 0
P P
P 'P1
P P
Network 1 Network 2
FREQUENCY CONTROL
Example
3. First primary control activated: replace the lost power
4. Then the failure area is located and secondary control is applied
'f z 0
'f
P PS
P 'P1
P P
Network 1 Network 2
UNIT CONTROL
Variable pressure operation
REQUIRED POWER CHANGE AVAILABLE RESERVES
6
RH
Power change (% PN )
MSTR
5
CFB
4
OTU G
3
CTR
2 CTR
CTR
0 MSTR = MAIN STEAM THROTTLING RESERVE
0 10 20 30 40 CTR = CONDENSATE THROTTLING RESERVE
Time (s)
LAGISZA PROCESS SIMULATION
Grid frequency support (primary and secondary)
Generator power
378
368
358
MW
348
338
328
318
0 100 200 300 400 500 600 700 800 900
Time (s)
Setpoint Simulated
CONCLUSION
Questions?
Comment?
Thank you!
