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Bolland

TEP03 CO2 capture in power plants

Part 3 Power plant technology

EfficiencyAccounting CO2Classification

Olav BollandProfessor

Norwegian University of Science and TechnologyDepartment of Energy and Process Engineering

Sept 2013

2

Gas Technology Centre NTNU – SINTEFOlav Bolland

Coal power plants

3


Processes for power generation with coal

4


Coal-fired power plant with main components - PCC

5


Steam cycle in coal-fired power plant

6


The world’s most efficient coal-fired unit with 47% efficiencyDenmark

Nordjyllandsværket, unit 3Net output : 385 MWSteam parameters : 300 bar/585 °C/585 °CMaximum district heating : 460 MWCommissioning year : 1998

Nordjyllandsværket, unit 3

7


CFBC - Circulating Fluidised Bed Combustion

off-gas

separationgas - solid

backflowingsolid stream

mixinggas - gas

mixinggas - solids

Lm

mixingsolids - solids

macro-scalerecycle streampenetration

ash

primary air

coal+limestone

secondaryair

8


Fluidised Bed

5 – 100 MW

Stationary fluidized bed Circulating fluidized bed

9


PFBC – Pressurised Fluidised Bed Combustion

10


Integrated Gasification Combined Cycle (IGCC)

ST

Generator

HRSG

Air

GT

Gasifier

AirSeparation

UnitCompressed air

N2

O2

Quench/ heat

recovery

Particulate removal

Sulfur removal

Coal feed

Raw syngas

Hydrogen-rich gas

Quench water

Recovered heat

H2S

Recovered heat

11


Integrated Gasification Combined Cycle (IGCC)

Pressurized waterinlet

Pressurized wateroutlet

Fuel Oxygen, steam

Cooling screen

Quenchwater

Granulated slag

Gas outlet

Cooling jacket

Burner

Siemens SFG gasifier BGL gasifier

12


Gas turbine power plants

13


GC T 1-shaft gas turbine (all GTs > 100 MWbut also smaller)

C T 2-shaft gas turbineT

C T TC 2-shaft gas turbine

C T TC 3-shaft gas turbineT

gas generator powerturbine

G

G

G

Gas Turbine Classification

14


General Electric LM2500ca. 30 MW, oil&gas, process/chemical industry, ships

15


Siemens V94.2ca. 170 MW,

first gas turbine with low-NOXcombustor

NOX = NO + NO2

16


T1: Combustor exit temperature (not much used)T2: Temperature after first blade row in Stage 1 (mostly used)T3: Calculated mixing temperature of combustor exit stream and

cooling air (ISO definition)

T1

T2

Definitions of Turbine Inlet Temperature - TIT

17


Turbine Blade Cooling

18


Air cooling of turbine blades

19


Single-Crystal

DirectionallySolidified

Turbine blade materials

Conventionalcasting

20


21


To enable the blades to withstand the high combustion

temperatures, a layer of metallic corrosion protection is first applied – under vacuum to

prevent it oxidizing. Using a plasma jet, a ceramic thermal-insulating layer is then applied

(Siemens).

22


TIT development

700

800

900

1000

1100

1200

1300

1400

1500

1600

1960 1965 1970 1975 1980 1985 1990 1995 2000 2005 2010

Year

Tem

per

atu

re i

n C

Metal skintemperature

Thermal BarrierCoating

ISO TIT First rotorinlet temperature

Metal skin temperature

ISO TIT

First rotorinlet temperature

Thermal barriercoating

23


Combined Cycle power plants

24


Combined Cycle Power Plant,the principle

Gas TurbineSteam Turbine

Heat recoverysteam generatoror HRSG

Condenser

To stack

Generator

Generator

FuelFuel Supplementary

firing

G G

PumpBy-passstack

By-pass

25


Steam Cycle – triple pressure reheat

26


FOR QUALITATIVE INDICATION ONLY

Thermoflow, Inc.

PEACE/GT PRO 13.0

Date: 08.12.04

Company: NTNU

User: Olav Bolland

C:\Documents and Settings \obolland\Desktop\EXAMPLE

Drawing No:

HEAT RECOVERY STEAM GENERATOR

ELEVATION

A A

B B

C C

D D

E E

F F

1

1

2

2

3

3

4

4

5

5

6

6

7

7

8

8

A B C D E F G H I J

A C D E

F

G

H

12.7 m - 17.8 m 16.5 m 4.1 m 40.0 m 21.8 m 6.8 m - -

HRSG - Horizontal boiler

27


0

100

200

300

400

500

600

700

0 50 100 150 200 250 300

Tem

pera

ture

[C

]

Heat transfer [MW]

Flue gas

Water/steam

pinch,smallest T in boiler,limititation for thesteam production

evaporator,boiling at constanttemperature

economiser,

slope 1 pmc

superheater,

slope 1 pmc

Flue gas line,

slope 1 pmc

HRSG TQ-diagram

28


Triple pressure reheat steam turbine

29


Enthalpy/entropy-diagram

30


G G

G

MM

G

ADirect water cooling

of condenser

DWater-cooling with dry cooling tower

CAir-cooledcondenser

BWater-cooling withwet cooling tower

Power plant cooling systems

31


DemisterWater inlet -from condenser

Water outlet -to condenser

Air inlet

Waterdistributor

Air outlet

Cooling tower

32


Cooling tower plume

Phot

o: O

lav

Bol

land

32

Cruas Nuclear power plant, FranceSchwarze Pumpe power plant, Germany

33


Induced draft cooling towers

34


Cogeneration of heat and powerSteam turbine extraction

Gas turbine Heat recovery Boiler

Hot exhaust Exhaust to stack

Power PHeat QSteam turbine

Condenser

High-pressure steam

Steam, close to vacuum

Water

Steam extraction

Cooling water

Heat (Q) reduces the power generation (P) In the steam turbineQ can be zero P=max

35


no extractionQP

LHV

Relation between heat production and powerin a plant using a steam turbine; conventional steam plant or combined cycle

Steam that is extracted from a steam turbine could alternatively have been used for further expansion and power generation

Heat production reduces the power generation (fixed fuel flow)

How is the power output reduced as function of heat generation?

The relation is then:

1

QP

P Q

36

Gas Technology Centre NTNU – SINTEFOlav BollandCHP Bolland, 2007

0

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

60 70 80 90 100 110 120 130 140 150 160 170 180 190 200 210 220 230

Steam extraction temperature, saturated [˚C]

Ra

tio

be

twee

n h

ea

t in

ex

tra

cted

ste

am

an

dlo

ss o

f st

ea

m t

urb

ine

po

wer

ou

tpu

t,

[-]

0123456789101112131415161718192021222324252627282930

Ste

am

ex

tra

ctio

n p

ress

ure

=

satu

rati

on

pre

ssu

re f

or

tem

per

atu

re o

n a

bsc

issa

[b

ar]

condenser pressure = 0.04 [bar]

condenser pressure = 0.07 [bar]

Saturation line

5QP

District heating

3.5-5QP

Typical amine boilingor paper drying

Relation between heat production and power

37


Power plant efficiency

38


Generator 1 2 3 4

Numbers in kilowatt

1

1 1

Gross shaft power

266755

/ 39.2%T K

LHV

W W W

W Q

Mechanical

losses

1067

99.6%m

2

2

Net shaft power

265688

39.1%

W

Generator-

losses

3985

98.5%g

Auxiliary power

Transformer

3926

98.5%aux

3

3

Generator terminal

261703

38.5%

W

LHV

Fuel energy

Q 680204

100%

4

4

Net power

257777

37.9%

W

265173CW

Air

Compressor

531928TW

Exhaust

Turbine

Fuel

LHVm

WWWW

f

auxipgmSTgmCTPInet

,,

PInet, net power plant efficiency for Power Island -

fm fuel flow rate kg/s

LHV lower heating value kJ/kg

TW turbine work, calculated as fluid enthalpy change kW (>0)

CW compressor work, calculated as fluid enthalpy change kW (<0)

m mechanical efficiency -

g generator efficiency -

STW steam turbine work, calculated as fluid enthalpy change kW (>0)

PW pump work, feed water pumps, cooling water pumps, etc. kW (<0)

aux auxiliary power efficiency (power island only!)


39


LHVm

WWWW

f

auxipgmSTgmCTPInet

,,

PInet, net power plant efficiency for Power Island -



TW turbine work, calculated as fluid enthalpy change kW (>0)

CW compressor work, calculated as fluid enthalpy change kW (<0)

m mechanical efficiency -

g generator efficiency -

STW steam turbine work, calculated as fluid enthalpy change kW (>0)

PW pump work, feed water pumps, cooling water pumps, etc. kW (<0)

aux auxiliary power efficiency (power island only!)

LHVm

WWW

f

AUXOCOPInetNPEnet

22

,,

NPEnet, Net Plant Efficiency

PInet, net power plant efficiency for Power Island



2COW work for CO2 compression kW (<0)

2OW work for O2 separation and compression kW (<0)

AUXW work for any related auxiliary processes kW (<0)


40


Reduction in efficiency when capturing CO2efficiency reduction related to plant efficiency

outputpower per consumed isenergy fuelmuch how is rateHeat

kWh

kJ

3600 :rateheat cyclePower

kWh

kWh :efficiency cyclePower

work

LHV

LHV fuel

work

HR

Q

W

NG CCGT Coal PC

Efficiency 58.0 % 43.0 %

Efficiency - with CO2 capture (assumes 8%-points efficiency reduction) 50.0 % 35.0 %

Heat rate - no CO2 capture 6207 8372

Heat rate - with CO2 capture (assumes 8%-points efficiency reduction) 7200 10286

Additional fuel consumption [kJfuel/kWhpower] 16.0 % 22.9 %

2

2

without CO capturepower

with CO capture

Additional use of fuel per kWh

41


0 %

5 %

10 %

15 %

20 %

25 %

30 %

35 %

40 %

45 %

50 %

55 %

60 %

65 %

70 %

20 22 24 26 28 30 32 34 36 38 40 42 44 46 48 50 52 54 56 58 60 62 64 66 68 70

Add

itio

nal c

onsu

mpt

ion

of f

uel

beac

use

of C

O2

capt

ure

[%/k

Whp

ower

]

Efficiency of reference power plant without CO2 capture [%]

5%-points

8%-points

10%-points

12%-points

15%-points

2

2

without CO capture

with CO capture

Additional fuel use when capturing CO2

PCC

NGCC

42


Specific Primary Energy Consumption for CO2 Avoided, SPECCA

Natural gas CoalFuel LHV MJ/kg fuel 50 28Fuel CO2 kg CO2/MJ_LHV 0.055 0.1

kg CO2/kg fuel 2.75 2.8eta 50 % 35 %eta_ref % 58 % 43 %E kg CO2/KWh 0.035 0.075E_ref kg CO2/KWh 0.35 0.75HR kJ_LHV/kWh 7200 10286HR_ref kJ_LHV/kWh 6207 8372

SPECCA kJ_LHV/kg CO2 3153 2835SPECCA MJ_LHV/kg CO2 3.15 2.83Fraction of LHV 17.3 % 28.3 %

LHV power

2

power

LHV LHV

2 2

1 13600

heat rate kJ /kWh

kg COE=

kWh

MJ kJSPECCA= ,

kg CO kg CO

refref

ref ref

HR HRSPECCA

E E E E

HR

43


Accounting CO2 capture

44


Powerplant

FuelCO2 emitted

Powerplant

CO2 emitted

CO2 captured

2

fuel LHV

kg CO

kWh

2

work

kg COkWhref

work

fuel LHV

kWhkWhref

Power, 1 kWh

Power, 1 kWh

Pre-combustionCO2 capture

2

work

fuel LHV

kWhkWhCO

Fuel feed

2

fuel LHV

kg CO

kWh

CO, CO2 and

H2-rich fuel

2

LHV, fuel feed

(1 )

kg CO

kWh

cap

2

2

work

kg CO

kWhcapCO

2

2

work

kg CO(1 )

kWhcapCO

2

2

kg CO captured

kg CO feedcap

Post-combustionCO2 capture

CO2 emitted

CO2 captured

Power, 1 kWh

Powerplant

2

work

fuel LHV

kWh

kWhCO

Fuel feed

2

fuel LHV

kg CO

kWh

CO2

2

2

work

kg CO

kWhCO

2

LHV

kg CO

kWhcap

2

2

work

kg CO(1 )

kWhcapCO

2

2

kg CO captured

kg CO feedcap

Accounting - 1

45


Accounting CO2 - 2

The CO2 capture ratio, ca p is defined as the fraction of the formed CO2 which is captured

CO2 captured the amount of CO2 captured per main product of the plant

2

22

work

kg COCO captured

kWh

cap

CO

CO2 emitted amount of CO2 emitted per main product of the plant

2

22

work

kg COCO emitted (1 )

kWh

cap

CO

46


Accounting CO2 - 3

CO2 capture efficiency, ,cap e ,

the net reduction of CO2 emission per unit of net power output comparing a reference power without CO2 capture and that of a similar power plant, and the emission of CO2 per unit of power output of the reference plant. Or; the ratio between CO2 avoided and the emission of CO2 per unit of power output of the reference plant.

2

2

,

(1 )

1 (1 )

capref CO ref

cap e capCO

ref

CO2 avoided, the net reduction of CO2 emission per unit of net power output comparing a reference power plant without CO2 capture and that of a similarpower plant with CO2 capture.

2

2CO avoided (1 )

capref CO

47


Accounting CO2 - 4

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1CO2 generated [kg/kWh]

Emitted

Captured

Plant withCO2 capture

Reference plant,no CO2 capture

CO2 captured

CO2 avoided

Additional CO2generated becauseof CO2 capture

48


Accounting CO2 - 5Example: The power plant efficiency without CO2 capture (reference, ref ) is 45%,

while the corresponding for the plant with CO2 capture is 35% (2CO ).

In the CO2 capture plant, 86% ( cap ) of all generated CO2 is captured and stored.

The fuel’s is assumed to be 342 g/kWhpower. The CO2 avoided is 0.623 kg CO2/kWhpower, while the CO2 captured is 0.840 kg CO2/kWhpower. The additional CO2 generated coming from an increase in fuel

consumption of 2

451.29

35ref

CO

is 0.217 kg CO2/kWhpower

The CO2 capture efficiency,

,ca p e , is 82%.

49


ClassificationCO2 capture

50


51


0.1

1

10

100

1000

-100 -90 -80 -70 -60 -50 -40 -30 -20 -10 0 10 20 30 40 50

Pre

ssu

re [b

ar]

Temperature [C]

LiquidSolid

Vapour

Sublimatio

n

Boiling/condensation

Melting/freezing

Critical point

Triple point

Sublimation point

5.18 bar-56.6 C

Flue gas must be compressed and cooled,P2/P1 depends on CO2 partial pressure5.1795/0.015=345 bar (1.5% CO2)

Transport & Storagecondition

Distillation

52


53


0.1

1

10

100

1000

-100 -90 -80 -70 -60 -50 -40 -30 -20 -10 0 10 20 30 40 50

Pre

ssu

re [b

ar]

Temperature [C]

LiquidSolid

Vapour

Sublimatio

n


Melting/freezing

Critical point

Triple point

Sublimation point

5.18 bar-56.6 C

Flue gas must be cooled,How low T depends on CO2 partial pressure


Anti-sublimation

54


55


Absorption of CO2most mature technology for flue gas

RectisolPurisolSelexol

BenfieldMEAMDEASulfinol

56


0.1

1

10

100

1000

-100 -90 -80 -70 -60 -50 -40 -30 -20 -10 0 10 20 30 40 50

Pre

ssu

re [b

ar]

Temperature [C]

LiquidSolid

Vapour

Sublimatio

n


Melting/freezing

Critical point

Triple point

Sublimation point

5.18 bar-56.6 C


Gas-phase separation

Cooling

Cooling

AbsorptionAdsorption

Oxy-combustionMembraneSorbents

57


58


59


OHCOOCH 2224 22

2222

22

77.344

)1(2

)77.3(4

Nn

mOn

mOHn

COm

NOn

mHC nm

AirAir excess ratio

Reactants

Products’exhaust’’flue gas’

3-14%

Oxy-combustion CO2 capture

60


Oxy-combustion – the principle

Conversion system

Air SeparationUnit

O2

hydrocarbonC,H

CO2 to storage

H2O extraction

Flue gasCO2 + H2O

CO2 or H2O recycle

61


Oxy-combustion - air separation?

Cryogenic distillation

AdsorptionMembrane

Polymeric membrane

Ceramic membrane

Vacuum Swing Adsorption

(VSA)

Vacuum Pressure Swing Adsorption

(VPSA)

Pressure Swing Adsorption

(PSA)

Electrically driven

membrane

Partial pressure driven

membrane

Air Separation Technologies

62


OHCOOCH2224

22

Air Separation Unit (ASU)

kg4kg1

32216

/dayO tons 4150

MJ/kg 50/skg 12MW600

)efficiency (50%MW600MW 300

2

CHCHfuel

fuele

44

)(@

Largest ASU train sizePossible in 2009

63


Oxy-combustion - Dilution of CO2

Flue gas pressure 1 atmCO2 partial pressure 0.6-0.8 atm

Oxy-combustioncoal

Ar; 1.9 %

SO2; 0.3 %H2O; 16.9 %

O2; 4.9 %

CO2; 62.5 %

N2; 13.5 %

Oxy-combustionnatural gas

N2; 3.2 %

CO2; 75.7 %

O2; 2.0 %

Ar; 4.8 %

H2O; 14.3 %

64


65


Oxygen ion transport membranes

ZrO2-Y2O3, CeO2,

La1-xSrxCo1-yFeyO3-d

Sr2Fe2O5,LaGaO3-d ,

(Bi2O2)(An-1BnOx), La2NiO4+d Mixed

conducting membrane

OMCM,

Oxygen ion conducting membrane,e.g. SOFC

Efficiency potential very good

66
