As carbon capture and storage (CCS) moves towards large-scale commercialisation, stakeholders along the CCS chain are required to address and resolve design and operability details, from generation to storage, at a commercial scale for the first time. As in other sectors, process simulation and modelling are key technologies for performing design calculations and analysis operations. Indeed, there is little that is new in terms of individual CCS chain components; conventional power stations, amine based CO2 capture plants, pipelines and compressors are mostly well understood. However, there are still significant challenges in the commercial implementation of CCS. These arise principally from the fact that the whole CCS chain needs to be considered as a single system in order to make design and operation decisions that satisfactorily address the commercial imperatives and risk requirements of the various stakeholders along the chain. The United Kingdom’s Energy Technologies Institute commissioned and co-funded a £3 million CCS System Modelling Toolkit involving E.On, EDF, Rolls-Royce, CO2DeepStore, Process Systems Enterprise and E4tech to deliver a robust, fully-integrated toolkit that can be used by CCS stakeholders across the whole CCS chain. The commercial tool arising from the project – gCCS – will be available in early 2014. gCCS will contain a full complement of models for conventional power generation, new power generation, solvent-based carbon capture, compression, transmission and injection. In addition, it will be possible to incorporate models of other plants, such as air separation units, using commercially-available capabilities, or to create custom models that can be incorporated within the environment. The system will be able to model both steady-state and dynamic operation. It will also include costing capabilities for use in rigorous mathematical optimisation that can include both continuous and discrete decisions, providing a common basis for techno-economic decisions across the chain.

1. CCS System Modelling and Simulation
Webinar – 21 November 2013, 1600 GMT

2. Webinar Program 2013-14
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CCS systems integration (ROAD)
Making the business case for CCS (2Co)
Global Status of CCS: 2013 (Global CCS Institute)
North West Sturgeon Refinery Project overview (North West Redwater Partnership)
Commercial structures for CO2 networks (National Grid)
Whole-chain system modelling for CCS (gCCS)
Pipeline design and operation (ECOFYS)
Progressing onshore storage in Europe (CIUDEN)
The role of export credit agencies, commercial banks and multilateral banks in funding
CCS demonstration projects (Société Générale)
TCEP business case and contracting strategy (Summit Power)
Key social research findings (CSIRO)
ULCOS stakeholder engagement (ArcelorMittal)
Relative permeability guideline (Stanford University)
http://www.globalccsinstitute.com/get-involved/webinars

3. QUESTIONS
 We will collect questions during
the presentation.
 Your MC will pose these questions
to the presenter after the
presentation.
 Please submit your questions
directly into the GoToWebinar
control panel.
The webinar will start shortly.

4. Alfredo Ramos Plasencia
 Worked at PSE in a range of
roles, starting as a consultant in
2006 and working up to his
current role as Vice President
Strategic Business Development
CCS & Power.
 Prior to this, Alfredo worked in
water services and at Aachen
University in Germany.
 He graduated from Aachen
University in 2000 with a Master of
Science in Chemical Engineering.
 Alfredo will provide an overview of
CCS System Modelling and
Simulation and will present some
of the capabilities of gCCS, which
is being developed by PSE.

5. THE ADVANCED PROCESS modelling COMPANY
CCS System Modelling and Simulation
Alfredo Ramos, Head of Power & CCS Business Unit
A webinar hosted by the Global CCS Institute
November 21st 2013
A gPROMS PLATFORM PRODUCT
© 2013 Process Systems Enterprise Limited

6. Overview
 PSE
Introduction
 Systems
modelling for CCS
 Case Study
System description
Steady-state analysis
Dynamic analysis
 Conclusions
© 2013 Process Systems Enterprise Limited

7. PSE HISTORY: FROM RESEARCH TO INDUSTRY
1989 – 1997
1997
Now
USA
100s of person-years of
R&D with industry
Company ‘spun out’
Acquires technology
Simulation & modelling,
optimisation, numerical
solutions techniques,
supply chain
Private, independent company
incorporated in UK
London HQ
Saudi Arabia
India
Germany
Thailand



Malaysia
China
Software and services (60:40)
Major process industry focus – all sectors
Strong R&D
Strong commercials
Royal Academy MacRobert Award for Engineering Innovation
© 2013 Process Systems Enterprise Limited
Japan
Advanced Process Modelling

UK’s highest engineering award
Korea

8. BUs responsible for business & product
development
Oil & Gas
Chemicals &
Petrochemicals
Life Sciences, Consumer
& Fine Chemicals
Software Technology Group
The gPROMS platform
Equation-oriented modelling & solution engine
© 2013 Process Systems Enterprise Limited
Power & CCS

9. Systems modelling for CCS
© 2013 Process Systems Enterprise Limited

10. CCS challenges
Multiple stakeholders with different issues & challenges
Government
Policy
Strategic
Infrastructure development
H&S
Optimal operating
point
Efficiency Tools
New design Various in-house
Impurities
Control
Safety
Grid demand
Flexibility
Efficiency
Fuel mix
Trip scenarios
Sizing
Flexibility
Buffer storage
Amine loading
Tools
Capital cost
gPROMS
optimization
PROMAX
Energy sacrifice Plus
Aspen
Heat integration
Solvent issues
Tools
PROATES
Dymola
GTPro
Aspen Plus
Composition effects
Phase behavior
Tools
Capacity
OLGA
Buffering / packing
PIPESIM
Routing
Safety
Depressurisation
Control
Leak detection
Injection/storage
Compression
Supply variability
Composition
Thermodynamics
Tools
Temperatures / hydrates
OLGA
Well performance
Prosper/Gap
Long-term storage
dynamics
Back-pressures
…currently being addressed by point solutions
© 2013 Process Systems Enterprise Limited

11. 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 behavior


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
 Manage complexity and risk at
multi-scale, network-wide level
© 2013 Process Systems Enterprise Limited

12. The CCS System modelling Tool-kit Project
2011-2014

Energy Technologies Institute (ETI)
~$5m project commissioned &
co-funded by the ETI
Objective: “end-to-end” CCS modelling tool
gPROMS modelling
platform & expertise
Project
Management
© 2013 Process Systems Enterprise Limited

13. gCCS initial scope (2014/Q2)

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
Open architecture allows incorporation of 3rd party models
© 2013 Process Systems Enterprise Limited

14. Why gSAFT?
Accurate prediction of phase envelope for near-pure CO2 mixtures
(Chapoy et al, 2011)
© 2013 Process Systems Enterprise Limited

15. Case Study: CCS chain
One of 4 major Case Studies designed to validate the tool
© 2013 Process Systems Enterprise Limited

16. System overview
Chemical absorption
MEA solvent
90% CO2 capture
220km pipeline
Dense phase CO2
Onshore and Offshore
~800MWe
Supercritical
Pulverized coal
(acknowledgement: E.ON)
© 2013 Process Systems Enterprise Limited
4 parallel compression trains
2 frames per train
Surge control
Offshore dense-phase
(acknowledgement:
Rolls-Royce)
injection; 4 injection wells
~2km reservoir depth
(acknowledgement:
CO2DeepStore)

17. Sub-system #1
Supercritical pulverized coal power plant
Governor valve
Turbine
sections
Generator
Boiler
Air
Coal
Feed Water
Heaters
Flue gas
treatment
Deaerator
Condenser
> 10 recycles & closed water/steam loop
© 2013 Process Systems Enterprise Limited

18. Sub-system #2
CO2 capture plant
CO2 capture
rate controler
Solvent /water makeup controlers
Absorber
Condenser
Stripper
Reboiler
CO2 inlet
© 2013 Process Systems Enterprise Limited
Direct Contact
Cooler (DCC)
Buffer Tank

19. Coupling between subsystems #1 and #2
Steam draw-off for amine regeneration
Potential steam draw-off points
Optimal drawoff point
© 2013 Process Systems Enterprise Limited
Pressure too high
 efficiency penalty
Pressure too low
Pressure potentially
too low at minimum plant loads

20. Sub-system #3
CO2 compression plant
Fixed speed
electric drive
Variable speed
electric drive
Dehydration unit
Compression
section
(Frame #1: 4 ; Frame #22)
Cooler KO drum
© 2013 Process Systems Enterprise Limited
Surge valve

21. Sub-system #4
CO2 transmission pipelines
Gate valve
CO2 flowmeter
Pipelines
Schedule 40, 18’’
© 2013 Process Systems Enterprise Limited
20km
-200m
160m
Emergency
shutdown valves
(ESD)
Vertical riser
from sea bed
200km

22. Sub-system #5
CO2 injection & storage in reservoir
Distribution
header
Choke valves
Wellhead
connections
20m above water,
70m submerged
Wells
7’’, 2km
Reservoir
~250 bar
© 2013 Process Systems Enterprise Limited

23. System overview
Chemical absorption
MEA solvent
90% CO2 capture
220km of pipeline
Onshore and Offshore
 29,700 equations/variables
 27,991 algebraic
4 compression trains
 1,709 differential
2 frames per train
~800MWe
 Computation time (on desktop computer)
Surge control
Supercritical
Offshore dense-phase
 ~200s for steady state
(acknowledgement:
Pulverized coal
injection; 4 injection wells
 (much) less for sensitivity runs
Rolls-Royce)
(acknowledgement: E.ON)
~2km reservoir depth
 ~7h for 50h dynamic simulation
© 2013 Process Systems Enterprise Limited
(acknowledgement:
CO2DeepStore)

24. Case Study: state-state analysis
© 2013 Process Systems Enterprise Limited

25. Steady-state scenarios
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
Extreme Weather:
Max Winter
100%
90%
100%
90%
SS1.5
Affected sub-systems
Base
Extreme Extreme
Temperatures
(oC) used for model calibration
Case
Summer
Winter
(e.g.
Cooling water Stodola constants for steam turbines; HTA for feed water heaters, etc.) 7
Power, Capture, Compression
18
22
Air
Sea water
© 2013 Process Systems Enterprise Limited
Power, Transmission,
Injection
Transmission, Injection
15
30
-15
9
14
4
NB. Geothermal gradient of +27.5oC / km

26. Steady-state analysis
Power generation
: coal milling
+ power plant auxiliaries
: coal milling
+ power plant auxiliaries
+ CO2 compression
: capture plant steam
+ CO2 compression
100% 75% 50% 100% 100% 75% 50% 100% 100%
0% 0% 0% 90% 50% 90% 90% 90% 90%
Summer Winter
© 2013 Process Systems Enterprise Limited

27. Steady-state analysis
CO2 compression power
100%
90%
100%
50%
75%
90%
50%
90%
100%
90%
100%
90%
Summer
Winter
Differences primarily due to
changes in viscosity of fluid in pipeline
© 2013 Process Systems Enterprise Limited

28. Case Study: dynamic analysis
© 2013 Process Systems Enterprise Limited

29. Dynamic analysis
Scheduled changes in power plant load
Scenario DS1.1
Scenario DS1.2
Power
Power
Load
Load
100%
100%
5 hours
75%
5 hours
23.5 hours
75%
5 mins
5 mins
5 mins
42.5 hours
1 hour
Time
© 2013 Process Systems Enterprise Limited
Time

30. Dynamic analysis
Stem position
5
6
7
(b) Power plant net efficiency
8
9
400
10
800
700
Power plant net
efficiency
3
4
5
6
7
(c) Governor valve stem position
8
9
1
600
500
400
10
800
Governor
valve stem position
0.5
3
4
5
6
7
8
(d) LP turbine inlet valve stem position
9
1
700
600
500
400
10
800
700
0.5
0
Mass flowrate (kg/s)
4
600
3
4
5
LP turbine inlet
valve stem position
8
9
6
7
(e) Flue gas mass flowrate
500
400
10
800
800
750
700
700
Flue gas
mass flowrate
650
600
3
4
5
6
7
(f) CO2 volume fraction in flue gas
8
9
0.138
600
500
400
10
800
700
0.1375
0.137
CO2 vol fraction
3
4
5
© 2013 Process Systems Enterprise Limited
6
7
Time (hours)
8
9
600
500
400
10
Net Power (MWe)
38
37
36
35
34
33
32
3
500
Net Power (MWe)
50
0
Volume fraction
600
Coal mass flowrate
55
Net Power (MWe)
700
60
Net Power (MWe)
800
65
Net Power (MWe)
(a) Coal mass flowrate
70
Net Power (MWe)
Stem position
Net Efficiency (%)
Mass flowrate (kg/s)
Power plant
Controller maintains
steam to reboiler
>3.5bar
Steam is
saturated here

31. Dynamic analysis
CO2 capture plant
(a) CO2 capture rate
800
94
700
92
90
600
88
84
500
CO2 capture rate
86
3
4
5
6
7
8
Net Power (MWe)
CO2 capture rate (%)
96
400
10
9
Time (hours)
(a) CO2 product flowrate
700
1400
1300
600
Solvent flowrate
to absorber
4
5
6
7
8
Time (hours)
120
800
700
100
600
Steam
to reboiler
3
4
5
6
7
8
9
500
400
10
Time (hours)
DS 1.1
DS 1.2
© 2013 Process Systems Enterprise Limited
Net Power (MWe)
Reboiler steam requirement (kg/s)
(c) Reboiler steam requirement
80
DS 1.1
DS 1.2
130
600
120
CO2 production rate (kg/s)
110
100
3
4
5
6
7
8
9
500
400
10
Time (hours)
400
10
9
700
140
(b) Specific regeneration requirement
4
800
700
3.5
600
Reboiler load (GJ/te CO2)
3
3
4
5
6
7
8
9
500
Net Power (MWe)
3
800
150
400
10
Time (hours)
(c) Solvent specific demand
25
800
700
20
600
Solvent demand
(m3 solvent/te CO2)
15
10
3
4
5
6
7
Time (hours)
8
9
500
400
10
Net Power (MWe)
1000
500
Specific regeneration requirement (MJ/kg CO2)
1100
Solvent specific demand (m3/tonne CO2)
1200
Net Power (MWe)
Lean solvent flowrate (kg/s)
1500
CO2 product flowrate (kg/s)
160
800
Net Power (MWe)
(b) Lean solvent flowrate to absorber
1600

32. Dynamic analysis
Power/CO2 capture two-way coupling
(a) Flue gas mass flowrate
700
700
600
500
Flue gas flowrate
600
3
4
5
6
7
8
9
400
10
(b) Power plant net efficiency vs reboiler steam demand
Net Efficiency (%)
41
120
40
39
100
38
Power plant net efficiency
vs. reboiler steam demand
37
36
3
4
5
© 2013 Process Systems Enterprise Limited
6
7
Time (hours)
8
9
Net Power (MWe)
800
80
10
Reboiler steam demand (kg/s)
Mass flowrate (kg/s)
800

33. Dynamic analysis
CO2 capture plant
(a) Absorber sump level
700
60
600
Absorber sump level
50
40
3
4
5
6
7
8
9
500
Net Power (MWe)
800
70
Level (%)
80
400
10
(b) Stripper sump level
700
60
600
Stripper sump level
50
40
3
4
5
6
7
8
9
500
Net Power (MWe)
800
70
Level (%)
80
400
10
(c) Absorber liquid holudp at 8.5m
800
0.035
700
0.03
600
0.025
0.02
3
4
5
6
7
Liquid vol. fraction
at absorber mid-point
8
9
500
Net Power (MWe)
Volume fraction
0.04
400
10
(d) Buffer tank level
700
200
600
Solvent buffer tank level (%)
100
0
3
4
© 2013 Process Systems Enterprise Limited
5
6
7
Time (hours)
8
9
500
400
10
Net Power (MWe)
800
300
Level (%)
400

34. Dynamic analysis
CO2 compression plant
800
5
6
7
8
400
10
9
(a) Compressor section 1 surge margin
800
4.5
700
4
600
3.5
3
500
Drive #2 power
3
4
5
6
7
8
9
Surge margin (%)
5
Net Power (MWe)
400
10
(c) Dehydrator inlet pressure
600
Dehydrator
inlet pressure
38.1
38
3
4
5
6
7
8
500
400
10
9
(d) Compressor discharge pressure
800
99
700
Compressor
discharge pressure
98
97
96
3
4
5
6
7
Time (hours)
© 2013 Process Systems Enterprise Limited
8
9
600
500
400
10
DS 1.1
DS 1.2
Net Power (MWe)
Pressure (bara)
100
Compressor surge control
Surge margin (%)
38.2
Surge margin (%)
700
Surge margin (%)
38.3
Surge margins
50
800
40
700
30
600
20
Drive #1, Section #1500
10
0
3
4
5
6
7
(b) Compressor section 2 surge margin
8
9
400
10
50
800
40
700
30
600
20
500
Drive #1, Section #2400
10
0
800
Net Power (MWe)
Pressure (bara)
38.4
Surge margin (%)
Power requirement (MWe)
(b) Electric drive 2 power requirement
3
4
5
6
7
(c) Compressor section 3 surge margin
8
9
10
50
800
40
700
30
600
20
500
10
0
3
4
5
Drive #1, Section #3400
6
7
(d) Compressor section 4 surge margin
8
9
10
50
800
40
700
30
600
20
500
Drive #2, Section #1400
10
0
3
4
5
6
7
(e) Compressor section 5 surge margin
8
9
10
50
800
40
700
30
600
20
Drive #2, Section #2500
10
0
3
4
5
6
7
(f) Compressor section 6 surge margin
8
9
400
10
50
800
40
700
30
600
20
500
10
0
3
4
5
6
Drive #2, Section #3400
7
Time (hours)
8
9
Net Power (MWe)
4
Net Power (MWe)
3
Surge margin (%)
7
500
Net Power (MWe)
Drive #1 power
Net Power (MWe)
600
10
Net Power (MWe)
7.5
Net Power (MWe)
700
Net Power (MWe)
Power requirement (MWe)
(a) Electric drive 1 power requirement
8

35. Dynamic analysis
CO2 transmission pipelines
Buffer potential for flexible
operation
(a) Pipeline inlet pressure
800
98
700
96
600
94
500
92
90
0
5
10
15
20
25
Net Power (MWe)
100
Pressure (bara)

400
30
(b) Pipeline outlet pressure
700
106
600
104
500
102
100
0
5
130
Pipeline inlet
At landfall valve
At 100km
Pipeline outlet
120
110
5
10
15
20
25
Time (hours)
30
35
40
45
50
15
20
25
400
30
(c) Pipeline pressure difference
9
800
8.5
700
8
600
7.5
500
7
0
5
10
15
20
25
400
30
(d) Pipeline inlet mass flowrate
Mass flowrate (kg/s)
100
10
150
800
140
700
130
600
120
500
110
100
0
5
10
15
20
25
Net Power (MWe)
140
Pressure difference (bar)
Mass flowrate (kg/s)
150
800
108
Net Power (MWe)
Pressure (bara)
110
Net Power (MWe)
160
400
30
800
140
700
130
600
120
500
110
100
0
5
10
15
Time (hours)
20
25
400
30
DS 1.1
DS 1.2
© 2013 Process Systems Enterprise Limited
Net Power (MWe)
Mass flowrate (kg/s)
(e) Pipeline outlet mass flowrate
150

36. Dynamic analysis
CO2 injection & storage
(a) Injection subsystem inlet pressure
700
105
600
500
0
5
10
15
20
(b) Injection subsystem outlet pressure
400
30
25
270
600
500
0
5
10
15
20
(c) Injection subsystem pressure difference
400
30
25
168
800
700
Mass flowrate (kg/s)
Mass flowrate (kg/s)
167.5
600
500
167
Net Power (MWe)
700
265
Pressure difference (bar)
800
0
5
10
15
20
(d) Injection subsystem inlet mass flowrate
400
30
25
150
800
140
700
130
600
120
500
110
100
0
5
10
15
20
(e) Mass flowrate of injected CO2
Net Power (MWe)
Pressure (bara)
275
Net Power (MWe)
100
Net Power (MWe)
800
400
30
25
150
800
140
700
130
600
120
500
110
100
0
5
10
15
Time (hours)
20
400
30
25
DS 1.1
DS 1.2
© 2013 Process Systems Enterprise Limited
Net Power (MWe)
Pressure (bara)
110

37. Conclusions
© 2013 Process Systems Enterprise Limited

38. Conclusions

Model-based engineering of
CCS chains
diverse stakeholders with
different concerns &
priorities
 need for coordination

A complex system…
…complex components
…complex steady-state and
dynamic interactions

BUT…within capabilities of
current state-of-the-art
modelling technology
© 2013 Process Systems Enterprise Limited

An end-to-end modelling tool
Capture, formalise & deploy
existing knowledge on CCS
technology
Common language for
communication
Open architecture allow
incorporation of future technology

39. When?

Now
gCCS v1.0 alpha 1 available for evaluation to selected
universities & research consortia
lead users among industrial partners

Soon (1-2 month timescale)
gCCS v1.0 alpha 2 release planned for January 2014
Main feature: Physical properties in component models for CO2 Capture,
Compression and Transport + Injection/storage provided by gSAFT

To follow (5-6 month timescale)
gCCS v1.0 beta to be released in Q2 2014
Main additions:
 Costing functionality
 streamlined component models
 online documentation & training
© 2013 Process Systems Enterprise Limited

40. Acknowledgements

This work was carried out as part of a £3m
project commissioned and co-funded by the
Energy Technologies Institute (ETI) and project
participants E.ON, EDF, Rolls-Royce, Petrofac
(via subsidiary CO2DeepStore), PSE and E4tech.

The project is aimed at delivering a robust, fully
integrated tool-kit that can be used by CCS
stakeholders across the whole CCS chain.
© 2013 Process Systems Enterprise Limited

41. PSE’s CCS Technology Team
 Gerardo Sanchis

Power plant
Product development
Power plant
 Mário
Calado
Compression Systems
Capture processes
 Dr

Adekola Lawal

Capture processes
Transmission & injection
 Dr Javier
© 2013 Process Systems Enterprise Limited
Dr Javier Fuentes
Software development
Alfredo Ramos
Technology Manager

Mark Matzopoulos
Marketing & Business
Development
Rodríguez
Capture processes
Physical properties
(gSAFT)
Dr Nouri Samsatli

Prof Costas Pantelides
Chief Technologist

42. Thanks for your attention!
Contact
Alfredo Ramos – Head Power & CCS Business Unit
a.ramos@psenterprise.com
© 2013 Process Systems Enterprise Limited

43. On-going developments
Model libraries – Power plant

Oxyfuel Flowsheet with Steam Cycle
© 2013 Process Systems Enterprise Limited

44. Tool-kit components
Model libraries – Power plant

Combined Cycle Gas Turbine flowsheet
Combustor
Compressor
and Gas
Turbine
Steam
drum
Economisers, superheaters,
evaporators
Loop
breaker
Recycle
breaker
Generator
Steam
turbines
Condenser
© 2013 Process Systems Enterprise Limited

45. On-going developments
Model libraries – Power plant

Integrated Gasification Combined Cycle power plant (IGCC)
HRSG and steam
turbines
Gasification and
syngas cooling
Air separation unit
(ASU) and compression
© 2013 Process Systems Enterprise Limited
Gas turbine
Acid gas removal
(AGR) and
sulphur recovery
unit (SRU)
Syngas conditioning

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