Optimal Synthesis of Integrated Gasification Combined Cycle (IGCC) Systems

R. S. Kamath, I. E. Grossmann, L. T. Biegler Department of Chemical Engineering

Carnegie Mellon University Pittsburgh, PA 15213

March, 2011

2

Problem Statement

Given Type of coal (quality, composition)

Power demand Mode of operation (with or without chemical/H2 production) Extent of CO2 capture Location of site Ambient conditions for utilities (air, water)

Determine Optimal structural configuration and operating conditions

Minimize Investment and operating costs

Additional constraints to be met Environmental emissions (current or more stringent future ones)

3

Superstructure for IGCC

C oal Handling Gas ifier

S team Generation

HeatR ecovery

S teamTurbine

GasTurbine

S yngas  C ooling

P roces sC ondens ateTreatment

Ac id g asC leaning

&S ulfur

R ecovery

C O2

C aptureH2

P roduc tion

H2/C O R atioAdjus tment

(S hift)

C hemicalP roduc tion

C oal

R awS yngas

C ondensate

C ooledS yngas

S

S M

S S

PowerP roduc tion

C oal

M

TreatedWastewater

S ulfur

C hemical

To C O2 s torage

H2

C leanS yngas

E lectricalE nergy

InjectionS team

MechanicalP ower

Hot E xhaust gas

E xhaust gasAir

As hTreatment

Ash/S lag

TurbineF uel

T reatedAsh

WHB S team

WHB S team

Gas ifier S team

S uperheatedS team

Boiler F uel

P rocessS team

C ondensate

E lectricalE nergy

T reatedTailgas

C OAL  GAS IF IC ATION S E C T ION

POWE R  GE NE RATION S E C T ION

C oal Handling Gas ifier

A irS eparation

Unit

S team Generation

HeatR ecovery

S teamTurbine

GasTurbine

S yngas  C ooling

P roces sC ondens ateTreatment

Ac id g asC leaning

&S ulfur

R ecovery

C O2

C aptureH2

P roduc tion

H2/C O R atioAdjus tment

(S hift)

C hemicalP roduc tion

C oal

R awS yngas

C ondensate

C ooledS yngas

S

S

S M

S S

PowerP roduc tion

C oal

M

TreatedWastewater

S ulfur

C hemical

To C O2 s torage

H2

C leanS yngas

E lectricalE nergy

InjectionS team

MechanicalP ower

Hot E xhaust gas

E xhaust gasAir

As hTreatment

Ash/S lag

TurbineF uel

T reatedAsh

Oxygen

WHB S team

WHB S team

Gas ifier S team

S uperheatedS team

Boiler F uel

P rocessS team

C ondensate

E lectricalE nergy

T reatedTailgas

C OAL  GAS IF IC ATION S E C T ION

POWE R  GE NE RATION S E C T ION

C oal Handling Gas ifier

A irS eparation

Unit

S team Generation

HeatR ecovery

S teamTurbine

GasTurbine

S yngas  C ooling

P roces sC ondens ateTreatment

Ac id g asC leaning

&S ulfur

R ecovery

C O2

C aptureH2

P roduc tion

H2/C O R atioAdjus tment

(S hift)

C hemicalP roduc tion

C oal

R awS yngas

C ondensate

C ooledS yngas

S

S

S M

S S

PowerP roduc tion

C oal

M

TreatedWastewater

S ulfur

C hemical

To C O2 s torage

H2

C leanS yngas

E lectricalE nergy

InjectionS team

MechanicalP ower

Hot E xhaust gas

E xhaust gasAir

As hTreatment

Ash/S lag

TurbineF uel

T reatedAsh

Oxygen

WHB S team

WHB S team

Gas ifier S team

S uperheatedS team

Boiler F uel

P rocessS team

C ondensate

E lectricalE nergy

T reatedTailgas

C OAL  GAS IF IC ATION S E C T ION

POWE R  GE NE RATION S E C T ION

C oal Handling Gas ifier

A irS eparation

Unit

S team Generation

HeatR ecovery

S teamTurbine

GasTurbine

S yngas  C ooling

P roces sC ondens ateTreatment

Ac id g asC leaning

&S ulfur

R ecovery

C O2

C aptureH2

P roduc tion

H2/C O R atioAdjus tment

(S hift)

C hemicalP roduc tion

C oal

R awS yngas

C ondensate

C ooledS yngas

S

S

S M

S S

PowerP roduc tion

C oal

M

TreatedWastewater

S ulfur

C hemical

To C O2 s torage

H2

C leanS yngas

E lectricalE nergy

InjectionS team

MechanicalP ower

Hot E xhaust gas

E xhaust gasAir

As hTreatment

Ash/S lag

TurbineF uel

T reatedAsh

Oxygen

WHB S team

WHB S team

Gas ifier S team

S uperheatedS team

Boiler F uel

P rocessS team

C ondensate

E lectricalE nergy

T reatedTailgas

C OAL  GAS IF IC ATION S E C T ION

POWE R  GE NE RATION S E C T ION

C oal Handling Gas ifier

A irS eparation

Unit

S team Generation

HeatR ecovery

S teamTurbine

GasTurbine

S yngas  C ooling

P roces sC ondens ateTreatment

Ac id g asC leaning

&S ulfur

R ecovery

C O2

C aptureH2

P roduc tion

H2/C O R atioAdjus tment

(S hift)

C hemicalP roduc tion

C oal

R awS yngas

C ondensate

C ooledS yngas

S

S

S M

S S

PowerP roduc tion

C oal

M

TreatedWastewater

S ulfur

C hemical

To C O2 s torage

H2

C leanS yngas

E lectricalE nergy

InjectionS team

MechanicalP ower

Hot E xhaust gas

E xhaust gasAir

As hTreatment

Ash/S lag

TurbineF uel

T reatedAsh

Oxygen

WHB S team

WHB S team

Gas ifier S team

S uperheatedS team

Boiler F uel

P rocessS team

C ondensate

E lectricalE nergy

T reatedTailgas

C OAL  GAS IF IC ATION S E C T ION

POWE R  GE NE RATION S E C T ION

4

Methodology (Daichendt and Grossmann, 1997)

Step 1 : Input-Outlet Level   Develop basic aggregate models for all sections   Connect the models to form a simplified superstructure   Optimize at I/O level by minimizing only operating costs (material & energy)

Further Steps: Optimizing superstructure at higher complexity levels   Use results (initial point, bounds) from previous optimization runs   Increase complexity of models for the sections, one at a time   Repeat the procedure till superstructure of desired complexity is optimized

5

Aggregate Model for Coal Gasification

Model solved as an inner minimization problem (inside an outer optimization model)

Min

s. t.

Atomic balance for reacting species

Component mole balance for inerts

Non-negativity of molar flows

Evaluation of component Gibbs energy

Add equilibrium reactions

(temperature approach)

Restricted Gibbs Energy Minimization

6

Capability of restricted Gibbs model

Composition (mole %)

Shell entrained gasifier (Ni and Williams, 1995)

GE entrained gasifier (Klara, 2007)

CoP entrained gasifier (Klara, 2007)

Actual Model Actual Model Actual Model

N2 4.5 4.375 1.68 1.689 1.82 1.695

H2 28.5 28.474 33.49 32.844 27.38 27.735

CH4 --- 0.003 0.1 0.097 4.0 3.762

CO 62.5 62.207 34.42 34.779 38.51 38.504

CO2 1.6 1.657 15.11 15.287 14.68 14.63

H2O 1.8 2.013 14.29 14.389 12.51 12.568

H2S --- 0.897 0.72 0.723 0.79 0.784

COS --- 0.303 0.02 0.027 0.05 0.058

NH3 --- 0.001 0.17 0.164 0.26 0.264

Trace 1.1 --- --- --- --- ---

ΔTApproach

Shift -250 -500 -445

Reforming -100 70 375

COS hydrolysis 0 -575 -385

NH3 synthesis 0 -685 -797

7

Superstructure for the Utility section

Ref: Bruno et al. (1998)

8

Numerical Example for Utility model

Electricity: 500 MW Mechanical Power No 1: 5 MW Mechanical Power No 2: 15 MW HP Heating: 5 MW MP Heating: 20 MW LP Heating: 50 MW

Demands

Pressure of Steam Headers HP: 45 bar MP: 20 bar LP: 7 bar 62 process streams

3 HP turbines (7 modes) 2 MP turbines (3 modes) 5 Headers (HP, MP, LP, Cond, Vac) 1 Gas turbine (compressor, expander) 3 Boilers (HP, MP, HRSG) 4 Combustors (GT, Boilers) 5 Liquid pumps 2 Air blowers 1 Deaerator

Superstructure

Non-convex MINLP problem Binary variables: 44 Continuous variables: 1275 Constraints: 1309

Modeled and solved using GAMS (Intel Core 2 Duo 2.4 GHz with 2 GB RAM)

Logic constraints 1 turbine Max 1 demand (mechanical or power) Mechanical demand Either electricity or turbine MP turbine can’t contribute power

9

Optimal Solution for Numerical Example

Operating cost = $307.27 Million/yr

10

Superstructure for Air Separation Unit

PPU

Was te Purge

L P  GAN

L P  GOX

HP  GAN

Ambient A ir

A ir integ ration(Gas  Turbine) H2O

C O2

Multi‐s treamheat exchanger

HighP res s ureC olumn

Integ ratedcondens erreboiler

L ow P res s ureC olumn

Multi‐s treamheat exchanger

11

Aggregate model for complex columns Cascade model for counter-current stages (Kremser method with Edmister approximation)

Performance

Recovery fractions

Effective Absorption/Stripping factors

  Simulation-based (like rigorous models)   Columns interconnected cascades and feed/side-draw stages   Optional feeds/side-draws (may or may not exist)   Cascades bypassed (disappear) if corresponding

feed/side-draw stages do not exist

E ntering   liquid (L 0)

E xiting      vapor (V1)

E xiting      liquid (L N)

E ntering    vapor (VN+1)

Poor Approximations removed

Better (realistic) constraints added Vapor outlet at dew point Liquid outlet at bubble point

12

Possible modes for LP column

S 1

S 2S 3

S 4

S 5

S 6

S 7S 8

S 10 S 12

1

1

S 18S 19

S 21S 23

S 26

S 27

S 29

S 30S 31

High Purity O2 produc t

Main F eed(always  exis ts )

4

S 1

S 2S 3

S 4

S 5

S 6

S 7S 8

S 9 S 11

S 13 S 14

1

2

1

S 15

S 16S 17

2

S 18S 19

S 21S 23

S 26

S 27

S 29

S 30S 31

High Purity O2 produc t

Main F eed(always  exis ts )

4

S 1

S 2S 3

S 4

S 5

S 6

S 7S 8

S 10 S 12

1

1

S 18S 19

S 20S 22

3

S 24S 25

S 26

S 27S 28

S 29

S 30S 31

High Purity O2 produc t

Vapor S ide‐draw(optional)

Main F eed(always  exis ts )

4

S 1

S 2S 3

S 4

S 5

S 6

S 7S 8

S 9 S 11

S 13 S 14

1

2

1

S 15

S 16S 17

2

S 18S 19

S 20S 22

3

S 24S 25

S 26

S 27S 28

S 29

S 30S 31

High Purity O2 produc t

Vapor S ide‐draw(optional)

Main F eed(always  exis ts )

4

Superstructure (LP column of ASU)

Only main feed exists

2 feeds exist

Main feed & Side-draw exist

Both feeds & Side-draw exist

13

Simulation of LP column

S 1

S 2S 3

S 4

S 5

S 6

S 7S 8

S 9 S 11

S 13 S 14

1

2

1

S 15

S 16S 17

2

S 18S 19

S 20S 22

3

S 24S 25

S 26

S 27S 28

S 29

S 30S 31

High Purity O2 produc t

Vapor S ide‐draw(optional)

Main F eed(always  exis ts )

4 Column hardware configuration   Stages (including reboiler) : 45   Number of feeds : 3 (Top + Main + 2nd)   Stage location of main feed : 32   Stage location of 2nd feed : 21   Stage location of vapor side-draw : 9

Operating conditions   Column Pressure : 5 bar   Reboil Ratio : 3.5

Feed characteristics

  Molar flowrate : 3 kmol/s   Mol % N2 : 0.708155   Mol % O2 : 0.279439   Mol % Ar : 0.012407   Temperature : 96.7K

b) Top feed a) Main and 2nd feed   Molar flowrate : 1 kmol/s   Mol % N2 : 0.996717   Mol % O2 : 0.002687   Mol % Ar : 0.000596   Temperature : 93.8K

14

Simulation Results for LP Column

S 1

S 2S 3

S 4

S 5

S 6

S 7S 8

S 9 S 11

S 13 S 14

1

2

1

S 15

S 16S 17

2

S 18S 19

S 20S 22

3

S 24S 25

S 26

S 27S 28

S 29

S 30S 31

High Purity O2 produc t

Vapor S ide‐draw(optional)

Main F eed(always  exis ts )

4 RADFRAC (Aspen Plus)

Aggregate Model (GAMS)

PercentageDeviation

Top Product

Flowrate kmol/s 3.655712 3.655495 -0.005959

N2 fraction 0.955236 0.9552676 0.003294

O2 fraction 0.040921 0.041131 0.510924

Ar fraction 0.003841 0.0036014 -6.260899

Temperature K 95.235956 95.237254 0.001362

Bottom Product

Flowrate kmol/s 1.344287 1.344505 0.016207

N2 fraction 6.82E-05 4.16E-04 509.7528

O2 fraction 0.965723 0.964031 -0.175294

Ar fraction 0.034207 3.56E-02 3.9319807

Temperature K 108.690204 108.677308 -0.011864

Reboiler Duty MW 28.517856 28.516891 -0.003386

15

Model for Multi-stream Heat Exchangers

H1

H2C 1

C 2

  Almost no models in literature (Proprietary MHeatX model in Aspen Plus)   MHeatX assumes all outlet streams have same Temperature if DOF > 1   Need an equation-oriented model suitable for optimization

Aggregate Model for MHEx   Use Pinch technology to formulate an inverse problem

  Given a MHEx (adiabatic black box), determine feasible temperatures and heat capacity flowrates for all inlet and outlet streams.

  Use Duran & Grossmann (1986) model with no objective function and zero utility loads

  Generates feasible points for outer problem in which model is embedded.

  No temperature intervals (useful for simultaneous optimization and heat integration)

  Can’t estimate capital cost (handy when emphasis is on energy/utility costs)

16

Dealing with Phase Change in MHEx

  Some streams can change phase during heat transfer (difficulty in enthalpy calculation, FCp is not constant)

  No models exist for heat integration with phase change (phase is not known a priori)

Proposed Model

H1

H2C 1

C 2

  It is known that streams H1 and C2 do not change phase

  Streams C1 and H2 may change phase

H1

C 1

H2

C 2

H2S up

H22P

H2S ub

C 1S up

C 12P

C 1S ub

T C 1,INS up

T C 1,OUTS up

T C 1,IN2P

T C 1,OUTS ub

T C 1,OUT2P

T C 1,INS ub

TH2,INS up

TH2,INS up

TH2,INS up

TH2,OUTS up

TH2,OUTS ub

TH2,OUT2P

17

Mathematical model for phase detection For both hot and cold streams

a) Region detection for inlet stream

b) Region detection for outlet stream

c) Equations for Flash calculation for 2-phase region

For hot streams

For cold streams

18

1

2

3

4

56

7

8

9

10

11

12

13

14

15

16HPC

SPLT1

MHEx1FLSH2

FLSH1

MXR1

LPC

Sample flowsheet for ASU

Aspen Plus (Rigorous) ~ 960 variables Aggregate Model (GAMS) ~ 280 variables

F = {4.353, 4.355} T = {114.167, 114.145}

F = {7.576, 7.577}

T = {109.201, 109.218}

T = {112.912, 112.916}

F = {1.419, 1.420} T = {124.935, 124.942}

T: Temperature (K) F: Flowrate (kmol/s)

19

Conclusions and Future Work

Conclusions   Formulated the proposed superstructure for IGCC as MINLP model   Methodology: solve large combinatorial problem with models of

various complexity levels   Developed aggregate models for coal gasification, utility section,

complex distillation columns and Multi-stream Heat Exchangers in ASU   Preliminary results show systematic topology optimization (Utility model)

accurate predictions (Gibbs model), and good match between aggregate and rigorous models (ASU)

Future Work   Develop aggregate models for other sections of the IGCC plant

(e.g. acid gas cleaning, Sulfur recovery, CO2 capture)   Optimize the superstructure at input-output level (considering only

operating costs)   Based on previous optimization results, develop more rigorous

models and optimize the superstructure at next level of complexity