ccs system modelling: enabling technology to … 1a to 3a/1a4 - lawal.pdfccs system modelling:...

© 2014 Process Systems Enterprise Limited

Adekola Lawal – Senior Consultant, Power & CCS

CCS system modelling: enabling technology to help accelerate commercialisation and manage

technology risk

10th ECCRIA 15 September 2014


Overview

Systems modelling for CCS

CCS process models

Power generation

Solvent-based CO2 capture

CO2 compression

CO2 transmission and injection

Applications

Case Study 1 – CCS Chain

Shell CCS Operability study

DECC Industrial CCS study


Systems modelling for CCS


Grid demand Flexibility Efficiency Fuel mix Trip scenarios

Sizing Flexibility Buffer storage Amine loading Capital cost optimisation Energy sacrifice Heat integration Solvent issues

Optimal operating point Efficiency New design Impurities Control Safety

Composition effects Phase behavior Capacity Buffering / packing Routing Safety Depressurisation Control Leak detection

Tools PROATES GTPro Ebsilon Dymola Aspen Plus …

Tools gPROMS PROMAX Aspen Plus …

Tools Various in-house

Tools OLGA PIPESIM …

CCS chains

Existing technology in a new configuration

Government Policy Strategic Infrastructure development H&S

Compression Supply variability Composition Thermodynamics Temperatures / hydrates Well performance Long-term storage dynamics Back-pressures

Injection/storage

…new technology required to address the new challenges posed by integrated CCS system

Tools OLGA Prosper/Gap …


The CCS System modelling Tool-kit Project 2011-2014

Energy Technologies Institute (ETI)

gPROMS modelling platform & expertise

Project Management

~£3m project commissioned & co-funded by the ETI

Objective: “end-to-end” CCS modelling tool

http://www.eti.co.uk/


System-wide modelling Key enabling technology for CCS

Explore complex decision space rapidly based on high-fidelity, technically realistic models

resolve own technical and economic issues

take into account upstream & downstream behaviour

Manage interactions and trade-offs

Evaluate technology – existing and next-generation

judge relative merits of emerging technologies

support consistent, future-proof choices

Integrating platform for

working with other stakeholders in chain

collaborative R&D, working with academia


CCS System Modelling Tool-Kit

gCCS initial scope (2014/Q3)

Process models

Power generation

Conventional: pulverised-coal, CCGT

Non-conventional: oxy-fuelled, IGCC

Solvent-based CO2 capture

CO2 compression & liquefaction

CO2 transportation

CO2 injection in sub-sea storage

Materials models

cubic EoS (PR 78)

flue gas in power plant

Corresponding States Model

water/steam streams

SAFT-VR SW/ SAFT- Mie

amine-containing streams in CO2 capture

SAFT- Mie

near-pure post-capture CO2 streams


CCS components process models


Governor valve

Feed Water Heaters

Deaerator Condenser

Generator

Coal

Air

Boiler

Turbine sections

Flue gas treatment

> 10 recycles & closed water/steam loop

Sub-system #1

Supercritical pulverized coal power plant


gCCS Power Plant library – conventional power generation

CCGT power plant

Gas Turbine

Condenser

Generator

Steam turbines

Steam drums

Economisers, superheaters, evaporators

Input flexibility: Total power output or natural gas flowrate specified

Air

Natural Gas

Steam to Capture Plant

Condensate return

Stack


Process side

Sub-system #1 – other power technologies considered

Oxyfuel power plant

Ste

am c

ycle

Compression and

purification

Oxyfuel boiler and

recycle


Steam Cycle


Oxyfuel power plant P

roce

ss s

ide


Integrated Gasification Combined Cycle power plant (IGCC)

Air separation unit

(ASU) and compression

Gasification and

syngas cooling

Syngas conditioning

Acid gas removal

(AGR) and

sulphur recovery

unit (SRU)

Gas turbine

HRSG and steam

turbines


IGCC power plant


CO2 inlet

Absorber

Direct Contact Cooler (DCC)

Buffer Tank

Stripper

Reboiler

Condenser

CO2 capture rate controller

Solvent /water make-up controllers

Sub-system #2

CO2 capture plant


Sub-system #3

CO2 compression plant

Fixed speed electric drive

Variable speed electric drive

Dehydration unit

Cooler KO drum

Compression section

(Frame #1: 4 ; Frame #22)

Surge valve


Pipelines Schedule 40, 18’’

Emergency shutdown valves

(ESD) Gate valve

Vertical riser from sea bed

CO2 flowmeter

Sub-system #4

CO2 transmission pipelines

20km

16

0m

200km

-20

0m


Wells 7’’, 2km

Distribution header

Choke valves

Reservoir ~250 bar

Wellhead connections

20m above water, 70m submerged

Sub-system #5

CO2 injection & storage in reservoir


Offshore dense-phase injection; 4 injection wells

~2km reservoir depth (acknowledgement:

CO2DeepStore)

220km of pipeline Onshore and Offshore

~800MWe Supercritical Pulverized coal (acknowledgement: E.ON)

4 compression trains 2 frames per train Surge control (acknowledgement: Rolls-Royce)

Chemical absorption MEA solvent 90% CO2 capture

System overview

29,700 equations/variables 27,991 algebraic 1,709 differential

Computation time (on desktop computer) ~200s for steady state

(much) less for sensitivity runs

~7h for 50h dynamic simulation


System model hierarchy


Case Study: state-state analysis


Scenario Description Power plant operation

(% of nominal load) Capture plant operation

(CO2 % captured)

SS1.1 (a,b,c) Base Load Power Plant (a) 100%; (b) 75%; (c) 50% 0% (no capture)

SS1.2 (a, b) Base load CCS Chain 100% (a) 90%; (b) 50%

SS1.3 (a, b) Part Load Analysis (a) 75%; (b) 50% 90%

SS1.4 Extreme Weather: Max Summer

100% 90%

SS1.5 Extreme Weather: Max Winter 100% 90%

Steady-state scenarios

used for model calibration (e.g. Stodola constants for steam turbines; HTA for feed water heaters, etc.)

Temperatures

(oC)

Affected sub-systems Base Case

Extreme Summer

ExtremeWinter

Cooling water Power, Capture, Compression 18 22 7

Air Power, Transmission, Injection

15 30 -15

Sea water Transmission, Injection 9 14 4

NB. Geothermal gradient of +27.5oC / km


Steady-state analysis

Power generation

100% 0%

75% 0%

50% 0%

100% 90%

100% 50%

75% 90%

50% 90%

100% 90%

Summer

100% 90%

Winter

: coal milling + power plant auxiliaries

: coal milling + power plant auxiliaries + CO2 compression

: capture plant steam


Case Study: dynamic analysis


System-wide modelling

Typical day in 2010

-10000

0

10000

20000

30000

40000

50000

60000

00:30 12:30 00:30 12:30

Barrage

Useable Wind

Flexible

Lose Base or Spill

Spill

Baseload

-Spill

Wind= low penetration

Baseload=Inflexible Nuclear

Flexible =(Gas and Coal) varies

around the demand curve

Barrage = Intermittent Tidal

Time

Grid Demand (MW)

Source:


System-wide modelling

Windy day in 2030 with high wind penetration

-10000

0

10000

20000

30000

40000

50000

60000

00:30 12:30 00:30 12:30

Barrage

Useable Wind

Flexible

Lose Base or Spill

Spill

Baseload

-Spill

Wind= high penetration

Flexible =(Gas and Coal) varies

around the demand curve and also

variations in wind power

Grid Demand (MW)

Time

Additional power at night is large

enough to impact base load plant

– requires spill of renewable or

baseload power.

Source:


Power

Load

5 mins

5 mins 75%

100%

Time

1 hour

5 hours 23.5 hours

42.5 hours

Power

Load

5 mins 75%

100%

Time

5 hours

Dynamic analysis

Scheduled changes in power plant load

Scenario DS1.1 Scenario DS1.2


3 4 5 6 7 8 9 1050

55

60

65

70

Mass f

low

rate

(kg/s

)

3 4 5 6 7 8 9 10400

500

600

700

800

Net

Pow

er

(MW

e)

(a) Coal mass flowrate

3 4 5 6 7 8 9 1032

3334

3536

3738

Net

Eff

icie

ncy (

%)

3 4 5 6 7 8 9 10400

500

600

700

800

Net

Pow

er

(MW

e)

(b) Power plant net efficiency

3 4 5 6 7 8 9 100

0.5

1

Ste

m p

ositio

n

3 4 5 6 7 8 9 10400

500

600

700

800

Net

Pow

er

(MW

e)

(c) Governor valve stem position

3 4 5 6 7 8 9 100

0.5

1

Ste

m p

ositio

n

3 4 5 6 7 8 9 10400

500

600

700

800

Net

Pow

er

(MW

e)

(d) LP turbine inlet valve stem position

3 4 5 6 7 8 9 10600

650

700

750

800

Mass f

low

rate

(kg/s

)

3 4 5 6 7 8 9 10400

500

600

700

800

Net

Pow

er

(MW

e)

(e) Flue gas mass flowrate

3 4 5 6 7 8 9 100.137

0.1375

0.138

Time (hours)

Volu

me f

raction

3 4 5 6 7 8 9 10400

500

600

700

800

Net

Pow

er

(MW

e)

(f) CO2 volume fraction in flue gas

Dynamic analysis

Power plant

Controller maintains steam to reboiler

>3.5bar

Steam is saturated here

Coal mass flowrate

Power plant net efficiency

Flue gas mass flowrate

CO2 vol fraction

LP turbine inlet valve stem position

Governor valve stem position


3 4 5 6 7 8 9 1084

86

88

90

92

94

96

Time (hours)

CO

2 c

aptu

re r

ate

(%

)

3 4 5 6 7 8 9 10400

500

600

700

800

Net

Pow

er

(MW

e)

(a) CO2 capture rate

3 4 5 6 7 8 9 101000

1100

1200

1300

1400

1500

1600

Time (hours)

Lean s

olv

ent

flow

rate

(kg/s

)

3 4 5 6 7 8 9 10400

500

600

700

800

Net

Pow

er

(MW

e)

(b) Lean solvent flowrate to absorber

3 4 5 6 7 8 9 1080

100

120

Time (hours)

Reboile

r ste

am

requirem

ent

(kg/s

)

3 4 5 6 7 8 9 10400

500

600

700

800N

et

Pow

er

(MW

e)

(c) Reboiler steam requirement

DS 1.1

DS 1.2

3 4 5 6 7 8 9 10100

110

120

130

140

150

160

Time (hours)

CO

2 pr

oduc

t flo

wra

te (

kg/s

)

3 4 5 6 7 8 9 10400

500

600

700

800

Net

Pow

er (

MW

e)

(a) CO2 product flowrate

3 4 5 6 7 8 9 103

3.5

4

Time (hours)Spe

cific

reg

ener

atio

n re

quire

men

t (M

J/kg

CO

2)

3 4 5 6 7 8 9 10400

500

600

700

800

Net

Pow

er (

MW

e)

(b) Specific regeneration requirement

3 4 5 6 7 8 9 1010

15

20

25

Time (hours)

Sol

vent

spe

cific

dem

and

(m3/

tonn

e C

O2)

3 4 5 6 7 8 9 10400

500

600

700

800

Net

Pow

er (

MW

e)

(c) Solvent specific demand

DS 1.1

DS 1.2

Dynamic analysis

CO2 capture plant

CO2 capture rate

Solvent flowrate to absorber

Steam to reboiler

CO2 production rate (kg/s)

3 4 5 6 7 8 9 1040

50

60

70

80

Leve

l (%

)

3 4 5 6 7 8 9 10400

500

600

700

800

Net

Pow

er (M

We)

(a) Absorber sump level

3 4 5 6 7 8 9 1040

50

60

70

80

Leve

l (%

)

3 4 5 6 7 8 9 10400

500

600

700

800

Net

Pow

er (M

We)

(b) Stripper sump level

3 4 5 6 7 8 9 100.02

0.025

0.03

0.035

0.04

Vol

ume

fract

ion

3 4 5 6 7 8 9 10400

500

600

700

800

Net

Pow

er (M

We)

(c) Absorber liquid holudp at 8.5m

3 4 5 6 7 8 9 100

100

200

300

400

Time (hours)

Leve

l (%

)

3 4 5 6 7 8 9 10400

500

600

700

800

Net

Pow

er (M

We)

(d) Buffer tank level

Solvent buffer tank level (%)


3 4 5 6 7 8 9 1036

37

38

39

40

41

Net

Eff

icie

ncy (

%)

3 4 5 6 7 8 9 1080

100

120

Reboile

r ste

am

dem

and (

kg/s

)(b) Power plant net efficiency vs reboiler steam demand

Time (hours)

3 4 5 6 7 8 9 10600

700

800

Mass f

low

rate

(kg/s

)

3 4 5 6 7 8 9 10400

500

600

700

800

Net

Pow

er

(MW

e)

(a) Flue gas mass flowrate

Dynamic analysis

Power/CO2 capture two-way coupling

Flue gas flowrate

Power plant net efficiency vs. reboiler steam demand


3 4 5 6 7 8 9 107

7.5

8

Pow

er

requirem

ent

(MW

e)

3 4 5 6 7 8 9 10400

500

600

700

800

Net

Pow

er

(MW

e)

(a) Electric drive 1 power requirement

DS 1.1

DS 1.2

3 4 5 6 7 8 9 103

3.5

4

4.5

5

Pow

er

requirem

ent

(MW

e)

3 4 5 6 7 8 9 10400

500

600

700

800

Net

Pow

er

(MW

e)

(b) Electric drive 2 power requirement

3 4 5 6 7 8 9 1038

38.1

38.2

38.3

38.4

Pre

ssure

(bara

)

3 4 5 6 7 8 9 10400

500

600

700

800

Net

Pow

er

(MW

e)

(c) Dehydrator inlet pressure

3 4 5 6 7 8 9 1096

97

98

99

100

Time (hours)

Pre

ssure

(bara

)

3 4 5 6 7 8 9 10400

500

600

700

800

Net

Pow

er

(MW

e)

(d) Compressor discharge pressure

Dynamic analysis

CO2 compression plant

Drive #1 power

Drive #2 power

Dehydrator inlet pressure

Compressor discharge pressure

3 4 5 6 7 8 9 100

10

20

30

40

50

Surg

e m

arg

in (

%)

3 4 5 6 7 8 9 10400

500

600

700

800

Net

Pow

er

(MW

e)

(a) Compressor section 1 surge margin

3 4 5 6 7 8 9 100

10

20

30

40

50

Surg

e m

arg

in (

%)

3 4 5 6 7 8 9 10400

500

600

700

800

Net

Pow

er

(MW

e)

(b) Compressor section 2 surge margin

3 4 5 6 7 8 9 100

10

20

30

40

50

Surg

e m

arg

in (

%)

3 4 5 6 7 8 9 10400

500

600

700

800

Net

Pow

er

(MW

e)

(c) Compressor section 3 surge margin

3 4 5 6 7 8 9 100

10

20

30

40

50

Surg

e m

arg

in (

%)

3 4 5 6 7 8 9 10400

500

600

700

800

Net

Pow

er

(MW

e)

(d) Compressor section 4 surge margin

3 4 5 6 7 8 9 100

10

20

30

40

50

Surg

e m

arg

in (

%)

3 4 5 6 7 8 9 10400

500

600

700

800

Net

Pow

er

(MW

e)

(e) Compressor section 5 surge margin

3 4 5 6 7 8 9 100

10

20

30

40

50

Time (hours)

Surg

e m

arg

in (

%)

3 4 5 6 7 8 9 10400

500

600

700

800

Net

Pow

er

(MW

e)

(f) Compressor section 6 surge margin

Surge margins

Drive #1, Section #1






Compressor surge control


Dynamic analysis

CO2 transmission pipelines

Buffer potential for flexible operation

5 10 15 20 25 30 35 40 45 50100

110

120

130

140

150

160

Time (hours)

Ma

ss f

low

rate

(kg

/s)

Pipeline inlet

At landfall valve

At 100km

Pipeline outlet


Dynamic analysis

CO2 injection & storage

0 5 10 15 20 25 30 100

110

120

130

140

150

Time (hours)

Ma

ss flo

wra

te (

kg

/s)

0 5 10 15 20 25 30 400

500

600

700

800

Ne

t P

ow

er

(MW

e)

Mass flowrate of injected CO2

DS 1.1

DS 1.2

Load returned after 1 hour

Load maintained at 75% MCR


Case Study: Shell Flexibility


Operability studies of capture plant

Source: Shell


Case Study: Industrial CCS Techno-economics


Industrial CCS Techno-economics

Source: Carbon Capture Journal


Thank you

ccs system modelling: enabling technology to … 1a to 3a/1a4 - lawal.pdfccs system modelling:...

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