Integrated Gasification Combined Cycle Power Plants - … Mansouri-Final.… · · 2015-02-23Integrated Gasification Combined Cycle Power Plants ... turbine block to enable the

Integrated Gasification Combined Cycle

Power Plants with Focus on Low Emission Gas Turbine Technology

by

Mohammad Mansouri Majoumerd

Thesis submitted in partial fulfillment of

the requirements for the degree of

PHILOSOPHIAE DOCTOR

(PhD)

Faculty of Science and Technology

Department of Petroleum Engineering

2014

University of Stavanger

N-4036 Stavanger

NORWAY

www.uis.no

©2014 Mohammad Mansouri Majoumerd

All rights reserved

ISBN:

ISSN:

PhD Thesis UiS, No.

http://www.uis.no/

iii

Abstract

It is foreseen that global demand for electricity will increase continuously, mainly due to

population growth and improved living standards, worldwide. At the same time, the

climate change issue due to increasing GHG emissions, more specifically from the heat

and power sector, has become one of the most important global concerns. Thus there has

been a genuine demand for the delivery of innovative solutions to provide electricity in a

more sustainable way. Several pathways, which have significant potential for GHG

emissions mitigation, while providing electric power, have been introduced and

investigated during recent years. The improvement of energy efficiency and the

deployment of carbon capture and storage (CCS) in fossil-based power plants are amongst

the options to stabilize the atmospheric levels of greenhouse gas emissions, while

enabling the continued use of fossil fuels. In this regard, the integrated gasification

combined cycle (IGCC) power plant is one of the most promising power generation

technologies. Environmentally benign use of coal as primary fuel, use of highly reliable

gas turbine (GT) technology, possibilities for poly-generation of different products and for

pre-combustion CO2 capture are important features of this technology.

In 2009, the European Union co-financed the “Low Emission Gas Turbine Technology for

Hydrogen-rich Syngas (H2-IGCC)” project to achieve its targets of higher energy

efficiency and lower GHG emission levels along with greater security of energy supply.

This project aimed at providing technical solutions for using undiluted hydrogen-rich

syngas in gas turbines for IGCC application with CO2 capture.

As part of the H2-IGCC project, this PhD thesis presents investigations into the

deployment of pre-combustion CO2 capture in IGCC power plants aiming at providing

practical and realistic system integration solutions. The emphasis has been on the gas

turbine block to enable the combustion of undiluted hydrogen-rich syngas, a requirement

iv Abstract

of future IGCC technology with CO2 capture. For this purpose, different state-of-the-art

technologies for various sub-systems of the IGCC plant were proposed and the most

practical options based on the feedback from industrial partners within the H2-IGCC

consortium were selected for further thermodynamic analyses. The outcomes of these

analyses together with technical constraints related to the proposed cycle configurations

were used by other working groups as boundary conditions for the development of a gas

turbine technology optimized for undiluted H2-rich syngas. Moreover, a techno-economic

tool has been generated, which enabled economic assessments of the IGCC plant with

CO2 capture and its main fossil-based competitors, using realistic cost and performance

data confirmed by important players in the European power market.

During the implementation of this thesis, it is demonstrated that the combustion of

undiluted H2-rich syngas and the meeting of fuel flexibility targets are not possible using

the existing GT technology. Accordingly, necessary modifications were proposed and

implemented to provide an optimized GT technology suitable for the combustion of

undiluted H2-rich syngas. It is also found that investigated fossil-based power plants have

similar cost levels. The marginal difference in the cost of electricity for different plants

was within the level of uncertainties in the assessment of investment costs. Therefore,

other main drivers, apart from the cost of electricity, can affect the selection of a power

generation technology such as operational flexibility and potential for future technological

improvements.

Keywords: CO2 capture and storage, gas turbine, H2-rich syngas, IGCC, power

generation, system integration, techno-economy

v

Acknowledgements

This research was co-financed by the European Union’s Seventh Framework Programme

for Research and Development. Financial support from the European Commission,

Directorate-General for Energy is gratefully acknowledged.

I would like to express my sincere gratitude to Professor Mohsen Assadi for his excellent

supervision and encouragement throughout my PhD program. I also appreciate his efforts

in providing me with the unique opportunity of being involved in two European-funded

projects, the H2-IGCC project and the European North Sea Energy Alliance (ENSEA)

project. I would like to thank Peter Breuhaus at the International Research Institute of

Stavanger (IRIS) for sharing his long-term experience and profound knowledge within the

field of gas turbine technology.

Thanks to Nikolett Sipöcz, Sudipta De, and Homam Nikpey for sharing their knowledge

and the collaborative works resulting in several journal and conference papers.

I would like to thank all the project partners in the H2-IGCC project whose contributions

have been used in this work. In this regard, my special thanks go to Han Raas at

Nuon/Vattenfall for performing gasification simulations and for sharing knowledge about

operational aspects of IGCC power plants. I am also thankful to Chris Lappee at

Nuon/Vattenfall, Stuart James, James Bowers, Karel Dvorak and Adam Al-Azki at E.ON

UK for sharing their industrial perspectives and providing technical and economic inputs.

Inputs from our partners in other sub-projects of the H2-IGCC project such as

combustion, materials and turbo-machinery in addition to the perfect coordination

activities, which were carried out by European Turbine Network (ETN) are also

appreciated.

vi Acknowledgements

Furthermore, my sincere thanks must go to my former colleagues at the University of

Stavanger (UiS) and my friends in Stavanger for their motivation and encouragement. I

would also like to express my gratitude to the new energy, risk management and well

construction group at IRIS.

Finally, and perhaps most importantly, I would like to take this opportunity to express my

deep gratitude to my family for their endless love and support.

Mohammad Mansouri Majoumerd,

Stavanger, Norway

vii

Table of Contents

Abstract .............................................................................................................................. iii

Acknowledgements ............................................................................................................. v

Table of Contents ............................................................................................................... vii

Nomenclature...................................................................................................................... xi

List of appended papers .................................................................................................... xxi

Additional papers not included .......................................................................................xxiii

1. Introduction ..................................................................................................................... 1

1.1. Background information ........................................................................................... 1

1.2. Objectives ................................................................................................................. 3

1.3. Limitations ................................................................................................................ 4

1.4. Methodology ............................................................................................................. 5

1.5. Outline of the thesis .................................................................................................. 6

2. Technical background ...................................................................................................... 7

2.1. Growing energy demand ........................................................................................... 7

2.2. Climate change ......................................................................................................... 8

2.2.1. Greenhouse gas emissions ................................................................................. 9

2.2.2. Climate change and the power sector .............................................................. 11

2.3. Mitigation policies .................................................................................................. 12

2.3.1. Carbon capture and storage .............................................................................. 13

viii Table of Contents

2.3.2. The European Union climate strategy .............................................................. 14

2.4. Various capture technologies in the power sector................................................... 15

2.4.1. Post-combustion CO2 capture .......................................................................... 17

2.4.2. Pre-combustion capture ................................................................................... 19

2.4.3. Oxy-fuel combustion ....................................................................................... 21

3. Coal-based power plants ................................................................................................ 25

3.1. Why coal-based power plants? ............................................................................... 26

3.2. Coal-fired power generation ................................................................................... 27

3.3. IGCC power plant’s components ............................................................................ 30

3.3.1. Air separation................................................................................................... 30

3.3.1.1. Cryogenic ASU and power island integration options .............................. 32

3.3.1.2. Other ASU technologies ........................................................................... 35

3.3.2. Gasification ...................................................................................................... 35

3.3.2.1. Entrained-flow gasifiers ............................................................................ 36

3.3.2.2. Gasification performance .......................................................................... 38

3.3.2.2.1. Coal quality ........................................................................................ 39

3.3.2.2.2. Cold gas efficiency ............................................................................ 40

3.3.3. Syngas cleaning and conversion ...................................................................... 41

3.3.3.1. Syngas cleaning ........................................................................................ 41

3.3.3.2. Water-gas shift reaction ............................................................................ 42

3.3.3.3. Acid gas removal ...................................................................................... 44

3.3.3.4. Sulfur recovery unit .................................................................................. 47

3.3.3.5. Advanced syngas cleaning and conversion ............................................... 48

3.3.4. CO2 compression and dehydration ................................................................... 50

3.3.5. Gas turbine ....................................................................................................... 52

Table of Contents ix

3.3.5.1. Combustion process .................................................................................. 52

3.3.5.2. Turbo-machinery ...................................................................................... 54

3.3.5.3. Materials ................................................................................................... 56

3.3.5.4. Commercial syngas-fueled gas turbine ..................................................... 56

3.3.5.5. Advanced hydrogen turbine technology ................................................... 57

3.3.6. Bottoming cycle ............................................................................................... 58

3.4. Current IGCC power plants status .......................................................................... 58

4. H2-IGCC power plant.................................................................................................... 61

4.1. H2-IGCC project .................................................................................................... 61

4.2. System integration .................................................................................................. 64

4.2.1. Cryogenic air separation unit ........................................................................... 65

4.2.2. Gasification ...................................................................................................... 66

4.2.3. Syngas conversion ........................................................................................... 66

4.2.4. Acid gas removal ............................................................................................. 67

4.2.5. Gas turbine ....................................................................................................... 68

4.3. System performance analysis .................................................................................. 70

4.3.1. Software tools .................................................................................................. 71

4.3.2. Boundary conditions ........................................................................................ 74

4.3.2.1. Ambient conditions ................................................................................... 74

4.3.2.2. Feedstock properties ................................................................................. 74

4.3.2.3. Gas turbine boundaries and performance .................................................. 76

5. Economic evaluation ..................................................................................................... 81

5.1. Cost estimating methodology ................................................................................. 81

5.1.1. Costing scope ................................................................................................... 83

5.1.2. Capital costs ..................................................................................................... 84

x Table of Contents

5.1.2.1. Step-count costing method ........................................................................ 84

5.1.2.2. Capacity adjustment .................................................................................. 86

5.1.2.3. Price fluctuations ...................................................................................... 86

5.1.2.4. Currency exchange ................................................................................... 87

5.1.3. Operation and maintenance (O&M) costs ....................................................... 87

5.1.4. Fuel cost ........................................................................................................... 87

5.1.5. CO2 cost measures ........................................................................................... 88

5.2. Uncertainty in the economic results ........................................................................ 89

6. Concluding remarks ....................................................................................................... 93

6.1. Conclusions ............................................................................................................ 93

6.2. Scientific contributions ........................................................................................... 96

6.3. Suggestions for further research ............................................................................. 98

7. Summary of appended papers ...................................................................................... 101

Bibliography .................................................................................................................... 109

Paper I .............................................................................................................................. 121

Paper II ............................................................................................................................ 133

Paper III ........................................................................................................................... 147

Paper IV ........................................................................................................................... 161

Paper V ............................................................................................................................ 175

Paper VI ........................................................................................................................... 187

xi

Nomenclature

Abbreviations

AGR acid gas removal

Al2O3 aluminum (III) oxide or alumina

Ar argon

AR4 4th assessment report of Intergovernmental Panel on Climate Change

ASU air separation unit

BFW boiler feed water

BUA bottom-up approach

CAESAR CArbon-free Electricity by SEWGS: Advanced materials, Reactor-, and

process design

CaO calcium oxide

CAPEX capital expenditure

CCS carbon capture and storage

CEPCI Chemical Engineering Plant Cost Index

CHP combined heat and power

xii Nomenclature

CH4 methane

CI cost index

CLC chemical looping combustion

CMD coal milling and drying

CO carbon monoxide

Co cobalt

COE cost of electricity

COS carbonyl sulfide

COT combustor outlet temperature

CO2 carbon dioxide

Cr chromium

Cu copper

DCF discounted cash flow

DGAN diluent gaseous nitrogen

DLN dry low NOx

DOE Department of Energy

EBTF European Benchmarking Task Force

EOS equation-of-state

EPCC engineering, procurement and construction costs

ETS emissions trading system

Nomenclature xiii

EU European Union

E-GasTM ConocoPhillips gasifier

FBC fluidized bed combustion

Fe iron

FeO ferrous or iron oxide

FGD flue gas desulfurization

FP7 Seventh Framework Programme

GAN gaseous nitrogen

GDP gross domestic product

GE General Electric

GHG greenhouse gas

GOX gaseous oxygen

GT gas turbine

HHV higher heating value

HP high pressure

HRSG heat recovery steam generator

HSE health, safety and environment

HT high temperature

HTS high temperature shift

H2 hydrogen

xiv Nomenclature

H2O water

H2S hydrogen sulfide

H2-IGCC Low Emission Gas Turbine Technology for Hydrogen-rich Syngas

project

IC indirect costs

IEA International Energy Agency

IGCC integrated gasification combined cycle

IGV inlet guide vanes

IL ionic liquid

IP intermediate pressure

IPCC Intergovernmental Panel on Climate Change

IR index ratio

ITM ion transport membrane

KP Kyoto Protocol

LHV lower heating value

LP low pressure

LT low temperature

LTS low temperature shift

MAC main air compressor

MEA monoethanolamine

MgO magnesium oxide

Nomenclature xv

MHI Mitsubishi Heavy Industry

Mo molybdenum

M&S Marshall and Swift cost index

NETL National Energy Technology Laboratory

NG natural gas

NGCC natural gas combined cycle

NGV nozzle guide vane

NH3 ammonia

NOx nitrogen oxides

NPV net present value

N2 nitrogen

N2O nitrous oxide

OC owner costs

OECD Organization for Economic Co-operation and Development

OEM original equipment manufacturer

OPEX operational expenditure

O&M operation and maintenance

O2 oxygen

PC pulverized coal

PCC pulverized coal combustion

xvi Nomenclature

PC-SAFT perturbed-chain statistical associating fluid theory

PGAN pressurized gaseous nitrogen

PM particulate matter

PR Peng-Robinson

RE renewable energy

R&D research and development

SC supercritical

SCGP Shell Coal Gasification Process

SCOT Shell Claus off-gas treating

SCPC supercritical pulverized coal

SCR selective catalytic reduction

SEWGS sorption-enhanced water-gas shift

SFG Siemens Fuel Gasification

SiO2 silicon dioxide

SOA state-of-the-art

SOx sulfur oxides

SO2 sulfur dioxide

SR Schwarzentruber and Renon

SRU sulfur recovery unit

ST steam turbine

Nomenclature xvii

SWGS sour water-gas shift

TBC thermal barrier coating

TDPC total direct plant cost

TEC total equipment costs

TEG tri-ethylene glycol

TGT tail gas treating

TIT turbine inlet temperature

TOT turbine outlet temperature

TPC total plant costs

UHC unburned hydrocarbons

UNFCCC United Nations Framework Convention on Climate Change

USC ultra-supercritical

USCPC ultra-supercritical pulverized coal

U.S. DOE United States Department of Energy

VIGV variable inlet guide vanes

WGS water-gas shift

Zn zinc

Latin

∆ℎ enthalpy change (kJ kg-1)

𝐴 area (m2)

xviii Nomenclature

𝐶 cost (€)

𝑐𝑝 specific heat transfer coefficient at constant pressure (kJ mol-1 K-1)

𝐼𝑗 installation costs of a component (sub-system) (€)

𝐿𝐻𝑉 lower heating value (kJ kg-1 or kJ m-3)

�� mass flow rate (kg s-1)

𝑝 pressure (bar)

�� volumetric flow rate (m3 s-1)

𝑅 gas constant (kJ kg-1 K-1)

𝑆 scaling parameter

𝑇 temperature (K)

𝑊 work (kW)

�� mean value of a parameter

Greek letters

𝛽 pressure ratio (-)

𝛾 isentropic exponent (-)

𝜅 constant

𝜂 efficiency (%)

𝑓 cost scaling exponent (-)

Subscripts

Nomenclature xix

𝑎𝑢𝑥 auxiliary

𝑐 compressor

𝑐𝑎𝑝𝑡𝑢𝑟𝑒 power plant with carbon dioxide capture

𝑐𝑎𝑝𝑡𝑢𝑟𝑒𝑑 carbon dioxide captured at a power plant

𝑐𝑔 cold gas

𝑐𝑖 coal input

𝑒 expander

𝑒𝑙 electrical

𝑖 inlet

𝑖𝑠 isentropic

𝑗 sub-system (or component)

𝑚 mechanical

𝑜 outlet

𝑜𝑏𝑦 original base year

𝑝 pumping

𝑝𝑟𝑜𝑐, 𝑐 process contingencies

𝑝𝑟𝑜𝑗, 𝑐 project contingencies

𝑟𝑒𝑓 reference

𝑠 specific

𝑠𝑔 syngas

xx Nomenclature

𝑠𝑡 steam turbine

𝑡ℎ thermal

𝑢𝑏𝑦 updated base year

Units

Gt Giga tonnes

Hz Hertz

kWh kilowatt hour

Mt million tonnes

Mtoe million tonnes of oil equivalent

MW Megawatt

MWe Megawatt electricity

MWh Megawatt hour

Pa.s Pascal second

ppm part per million

ppmvd part per million volumetric dry

tC tonne of carbon

TJ Terajoule

TWh Terawatt hour

wt% weight percentage

xxi

List of appended papers

Paper I Sipöcz, N., Mansouri, M., Breuhaus, P., Assadi, M., Development of H2-rich

syngas fuelled GT for future IGCC power plants – Establishment of a

baseline, Presented at ASME Turbo Expo 2011, GT2011-45701,

Vancouver, Canada, June 2011.

Paper II Mansouri Majoumerd, M., De, S., Assadi, M., Breuhaus, P., An EU initiative

for future generation of IGCC power plants using hydrogen-rich syngas:

Simulation results for the baseline configuration. Applied Energy, 2012, 99:

p. 280-290.

Paper III Mansouri Majoumerd, M., Raas, H., De, S., Assadi, M., Estimation of

performance variation of future generation IGCC with coal quality and

gasification process – Simulation results of EU H2-IGCC project. Applied

Energy, 2013, 113: p. 452-462.

Paper IV Mansouri Majoumerd, M., Assadi, M., Fuel change effects on the gas

turbine performance in IGCC application, Presented at 13th International

Conference on Clean Energy (ICEE-2014), Istanbul, Turkey, June 2014.

Paper V Mansouri Majoumerd, M., Assadi, M., Breuhaus, P., Techno-economic

evaluation of an IGCC power plant with carbon capture, Presented at

ASME Turbo Expo 2013, GT2013-95486, San Antonio, Texas, USA, June

2013.

Paper VI Mansouri Majoumerd, M., Assadi, M., Techno-economic assessment of

fossil fuel power plants with CO2 capture ‒ Results of EU H2-IGCC project.

International Journal of Hydrogen Energy, 2014, 39: p. 16771-16784.

xxiii

Additional papers not included

Paper VII Mansouri Majoumerd, M., Breuhaus, P., Smrekar, J., Assadi, M., Basilicata,

C., Mazzoni, S., Chennaoui, L., Cerri, G., Impact of fuel flexibility needs on

a selected GT performance in IGCC application, Presented at ASME Turbo

Expo 2012, GT2012-68862, Copenhagen, Denmark, June 2012.

Paper VIII Nikpey Somehsaraei, H., Mansouri Majoumerd, M., Breuhaus, P., Assadi,

M., Performance analysis of a biogas-fueled micro gas turbine using a

validated thermodynamic model. Applied Thermal Engineering, 2014, 66: p.

181-190.

Paper IX Nikpey, H., Mansouri Majoumerd, M., Assadi, M., Breuhaus, P.,

Thermodynamic analysis of innovative micro gas turbine cycles, Presented

at ASME Turbo Expo 2014, GT2014-26917, Düsseldorf, Germany, June

2014.

Paper X Mansouri Majoumerd, M., Nikpey Somehsaraei, H., Assadi, M., Breuhaus,

P., Micro gas turbine configurations with carbon capture – Performance

assessment using a validated thermodynamic model. Applied Thermal

Engineering, 2014, 73: p. 170-182.

Paper XI Mansouri Majoumerd, M., Assadi, M., Breuhaus, P., H2-IGCC system

integration and techno-economic analysis, Presented at 7th International Gas

Turbine Conference (IGTC-14), Brussels, Belgium, October 2014.

Paper XII Assadi, M., Mansouri Majoumerd, Jana, K., De, S., Intelligent biogas

fuelled distributed energy conversion technologies: Overview of a pilot

study in Norway, Accepted for presentation at ASME 2014 Gas Turbine

India Conference, GTINDIA2014-8231, New Delhi, India December 2014.

1

1. Introduction

This work is based on a research project co-financed by the European Union (EU)

Seventh Framework Programme for Research and Development. The aim of this project

was to provide and demonstrate technical solutions, which allow the use of state-of-the-art

highly efficient and reliable gas turbines (GT) in the next generation of integrated

gasification combined cycle (IGCC) plants with carbon dioxide (CO2) capture.

1.1. Background information

The rapid growth of the world’s population coupled with the improved living standards

has led to an increasing demand on energy, worldwide. The global economic situation

during the past few years has offset this increase to some extent by the reduction in

industrial activities. However, some factors including global population, living standards

and global economy are foreseen to be the main drivers of the energy demand increase in

coming years. Though there will be a significant improvement in energy efficiency, the

projected primary energy use in the year 2040 will be approximately 35% higher

compared to the 2010 level. Electricity generation will represent the largest driver of

energy demand by 2040 and is expected to account for about half the increase in global

demand for energy [1].

Climate change due to anthropogenic greenhouse gas (GHG) emissions is identified as the

greatest threat to mankind [2]. The major source of these GHGs is CO2 emissions, and the

heat and power sector is identified as the largest contributor to these emissions. CO2

emissions from the heat and electricity supply sector were about 42% of total global CO2

emissions from fossil fuels in the year 2011 [3]. The present challenge for the power

2 Introduction

sector is to meet the ever-increasing demand for electricity and simultaneously mitigate

the greenhouse gas emissions, principally CO2.

Several sustainable solutions have been developed and introduced to cover the additional

demand and to mitigate CO2 emissions in recent years. One possible option is to replace

fossil-based power plants by renewable energy (RE) sources. In 2008, renewable energies

contributed approximately 19% of global electricity demand, and most scenarios foresee a

higher projected share in coming years [4]. Renewable sources are ultimately the most

important option for the future. However, apart from the long timescale for the complete

transformation from fossil-based fuels, RE sources suffer from the fluctuating nature or

variability of production [5]. Given all these aspects, the development of suitable

technology for large-scale power generation using fossil fuels during this transition is

urgently needed.

The other solution to mitigate CO2 emissions is the enhanced use of lower carbon

intensity fuels in power plants instead of e.g. oil and coal, which have higher carbon

contents. In this context, the use of natural gas (NG) for power generation has been

increasing in some countries, mostly due to the fact that it is more environmentally

friendly. However, coal is still the most widely used fossil fuel for large-scale power

generation [5], although the CO2 emissions from coal power plants are almost two times

higher than those from NG-fueled power plants. The International Energy Agency’s (IEA)

New Policies Scenario foresees a 25% increase in coal consumption in the year 2035

compared to the 2009 level. This increase will be 65% based on the Current Policies

Scenario [5]. The security of energy supply due to wider geographical distribution of coal

reserves and availability of abundant resources has promoted coal-fueled power

generation technologies. In addition, factors such as safe storage, easy transportation over

a long distance, less volatile pricing status motivate higher use of coal. Amongst available

reliable technologies for electric power generation, coal plants are still dominating the

market, mainly due to better economic attributes [6].

Carbon capture and storage (CCS) is also one of the key players for decarbonizing the

heat and power supply according to the European Energy Roadmap 2050 [7]. The

deployment of CCS in coal-fired power generation will maintain coal consumption at a

certain level among other fossil fuels under more restricted emissions regulations in

future.

Nomenclature 3

By virtue of the aforementioned aspects, there has been a demand for the development of

a reliable, environmentally-friendly, coal-based technology with the deployment of CO2

capture and storage.

1.2. Objectives

The vision of this PhD thesis, as part of the European H2-IGCC project, was to enable the

application of the state-of-the-art (SOA) gas turbine technology in the next generation of

IGCC plants (i.e. with CO2 capture system) with the flexibility to operate on undiluted H2-

rich syngas. Figure 1.1 illustrates the structure of the current thesis.

Figure 1.1. The structure of the current thesis

The overall objective of this thesis was, therefore, to provide a detailed system analysis

that generates realistic techno-economic performance indicators for future IGCC plants

with the deployment of CO2 capture. In this regard, special efforts were dedicated to:

Establish and improve a thermodynamic model in order to evaluate the

thermodynamic performance indicators of the IGCC plant with pre-combustion

CO2 capture unit.

4 Introduction

Investigate the consequences of burning H2-rich syngas in IGCC power plants at

both the system level and the GT level.

Investigate the fuel flexibility target by burning non-capture clean syngas instead

of H2-rich syngas and natural gas in the GT.

Update and improve an available GT model using new designed GT

characteristics to cope with the needs of the project and to allow future

adjustments based on the feedback from the project’s partners.

Identify different alternatives for component integration to reach higher plant

efficiency and investigate various configurations of the system in terms of the

plant’s operability.

Develop a tool for economic evaluation and assess capital expenditures

(CAPEX) and operational expenditures (OPEX) for the IGCC plants.

Compare the technical and economic performance indicators of the IGCC plants

with other fossil-based power plants, i.e. advanced supercritical pulverized coal

(SCPC) and natural gas combined cycle (NGCC) plants.

1.3. Limitations

The main focus of this research work was on system modeling and analysis for low

carbon IGCC power plants with special emphasis on the gas turbine technology.

Accordingly, different plant’s components were integrated to establish the selected IGCC

plant with CO2 capture unit. Then, the system was thermodynamically modeled and

analyzed along with continuous modifications of the gas turbine to enable the combustion

of undiluted hydrogen-rich syngas. In addition, a part of the activities was related to

techno-economic assessments of the selected IGCC plant and its fossil-based competitive

technologies. The techno-economic studies performed were exclusively reviewed by some

European utility providers, and economic figures were compared with realistic cost data

provided by project partners. It should be highlighted that the lack of large-scale IGCC

plants with CO2 capture system increases the level of uncertainty in both technical and

economic indicators. However, realistic performance and cost data used in simulations

and techno-economic assessment reflects the current development level of IGCC plants.

Moreover, some of the major alternative plant’s components contributing to efficiency

improvement have been identified and are presented here.

Nomenclature 5

This work does not address the issues revolving around the transport and storage of

captured CO2 and only focuses on the CO2 capture part. Transient (and dynamic)

simulation of the investigated cycles is also outside the scope of this thesis. While

practical heat integration was used for the selected system, thermodynamic optimization is

excluded from the present work.

1.4. Methodology

A literature review was performed to provide a process description as well as performance

data for different components of the IGCC plant based on state-of-the-art technologies.

The collected information, together with data generated during the implementation of this

work, was used for the modeling of the entire IGCC system. The thermodynamic models

described in this thesis were developed using different software tools. The simulation of

power block was performed using the heat and mass balance program, IPSEpro. For this

purpose, existing component models in IPSEpro, as well as certain models developed

during the H2-IGCC project, were used. In addition, the Enssim software, developed by a

member of the H2-IGCC project, was used to simulate and analyze the gasification block.

Simulation and modeling of the gas cleaning process of the IGCC plant were carried out

using ASPEN Plus. After establishing the baseline IGCC plant with CO2 capture, the

performance of different components and the layout of the plant were continuously

modified using the feedback from operators of similar plants.

In order to determine state-of-the-art methodologies for cost estimation in the power

sector, a literature review was performed. A Microsoft Excel-based tool has been

developed for the techno-economic comparison of different power generation

technologies, using performance data obtained from simulations and available cost data in

open literature. A techno-economic comparison between three fossil-based power

systems, i.e. IGCC, SCPC and NGCC plants, was conducted using the developed tool.

Moreover, the developed tool enabled the effects of the variation of different parameters

on the economic indicators to be investigated.

6 Introduction

1.5. Outline of the thesis

The present thesis is a summary of six scientific papers, preceded by an introduction to

the work that provides supplementary information to that presented in the papers.

Chapter 1 provides an overview of the present thesis by means of a brief background to

current energy related issues and an explanation of the objectives and limitations of this

thesis. Chapter 2 presents an extended background to the climate change concern,

different GHG mitigation options and the main CO2 capture methods. Chapter 3 gives a

brief introduction to coal power plants and concisely describes different sub-systems of an

IGCC power plant as well as different challenges for the integration of such an energy

conversion system. Chapter 4 contains the selected IGCC plant configuration, challenges

related to the use of undiluted hydrogen-rich syngas and a general description of heat and

mass balance tools used for the investigations performed during the course of this thesis.

Chapter 5 describes the economic methodology selected for the techno-economic

assessments as well as calculations performed for techno-economic studies within this

PhD project. The main conclusions of this work are presented in Chapter 6, and, finally,

Chapter 7 introduces the papers included in the thesis.

7

2. Technical background

The provision of energy in its most modern state, i.e. electricity, has been faced with a

major concern over the past two decades, and that is climate change. Climate change due

to anthropogenic greenhouse gas emissions is considered to be one of the most serious

threats to natural ecosystems and human life in the 21st century. The aim of this section is,

therefore, to provide a clear picture about future energy mix and its link to the climate

change concern.

Accordingly, a brief review of the most important energy indicators published by various

organizations will be presented. This review will offer an approximate picture of future

energy growth. The second part of this section is dedicated to the climate change concern

and greenhouse gas emissions. An overview of different mitigation policies to stabilize

greenhouse gas concentration in the atmosphere will be given with a focus on carbon

capture and storage. Finally, the most mature carbon capture technologies will be briefly

described.

2.1. Growing energy demand

World total primary energy consumption was 12,470 Mtoe in 2012 [8]. Global population,

global economy, energy-intensity of the global economy and living standards are the main

drivers of the world’s energy demand [9]. The global population will increase more than

30% from 2013 to 2050 and reach nearly 9.6 billion [10]. This number shows another 2.4

billion energy consumers, mainly in Asia and Africa. During recent years, the global

economy has faced the worst recession since the Second World War [11]. It began with

the crisis in the United States in 2007-08 and then the EU zone faced a weak economy.

However, using stronger measures to stimulate the economy has had a positive effect and

8 Technical background

a marginal economic growth has been visible recently. The projected gross domestic

product (GDP), which is an indicator of economic growth, is expected to increase at an

annual average rate of 2.8-3.7% in the next two to three decades [1, 12, 13]. Most of this

growth will come from emerging economies and non-OECD (Organization for Economic

Co-operation and Development) countries. Meanwhile, the projected GDPs of China,

India, and Africa are expected to grow by an annual average rate of about 4-5% until

2040. Global economic growth will then slow gradually as the emerging economies

become mature. Together with the rapid growth of the economy, urbanization,

industrialization and increased living standards are also projected for the future. The

projected urbanization rate for 2035 is 61%, compared to 51% in 2010 [13]. The greater

part of this increase will again come from non-OECD countries, where people want to

reach higher living standards. The shift of population to cities means a greater number of

homes and higher average energy consumption compared to rural areas, although it

enables people to have access to more efficient energy use.

As mentioned, all the fundamental drivers of energy demand (except energy-intensity)

will continuously grow in the coming decades. Energy efficiency will continue to play a

major role in moderating the energy growth. The energy-intensity (energy consumption

per capita) projection shows a downward trend worldwide over the coming decades [13].

This is an indicator of more efficient utilization of energy. However, improved living

standards will outpace energy efficiency and will ultimately result in a higher demand for

energy in the future. Therefore, global primary energy consumption, with a small

variation between data from different scenarios and organizations, is projected to grow at

an average annual rate of 1.2-1.6 % over the period of 2010 to 2030 [1, 12, 14]. To

conclude this section, the need for a greater supply of energy through the development of

efficient technologies seems inevitable in the future.

2.2. Climate change

The change in the state of the climate as a result of human activities, in addition to natural

climate variability, represents a potentially serious threat facing humanity in the 21st

century. Some of the variations in climate, which have been observed during past years,

are [15]:

Increase in global average air and ocean temperatures;

Technical background 9

rise of global average sea level;

decrease in snow and ice extent;

change in hydrological systems, e.g. increased runoff and warming of lakes and

rivers; and

changes in terrestrial, marine and freshwater biological systems.

According to the Fifth Assessment Report (AR5) of Intergovernmental Panel on Climate

Change (IPCC), “Warming of the climate system is unequivocal”. Moreover, “it is

extremely likely that human influence has been the dominant cause of the observed

warming since the mid-20th century”. The global average combined land and ocean

surface temperature increased 0.85 °C from 1880 to 2012. A comparison between the

average temperature of 1850-1900 and of 2003-2012 shows a total increase of 0.78 °C

[16].

2.2.1. Greenhouse gas emissions

A change in the atmospheric concentration of greenhouse gases such as carbon dioxide,

methane (CH4), nitrous oxide (N2O) and halocarbons altered the energy balance of the

climate system and is considered as one of the main drivers of climate change. It is very

certain that the anthropogenic increase in greenhouse gas concentrations, together with

other anthropogenic forces, is responsible for more than half of the observed increase in

global average surface temperature from the mid-20th century to 2010 [16]. Figure 2.1

shows the share of different anthropogenic greenhouse gases in total emissions in 2004

[15].

Figure 2.1. Global anthropogenic greenhouse gas emissions in 2004 (data adopted from IPCC AR4)

CO2 (fossil fuel use)

57 %

CO2

(deforestation, decay of

biomass, etc.)17 %

CO2 (other)3 %

CH4

14 %

N2O8 %

Fluorinated gases1 %


The global atmospheric concentration of CO2, which is widely recognized as the most

important GHG contributor to global warming, has increased from a pre-industrial value

of about 278 to 394 ppm in 2012 [15, 17]. Figure 2.2 illustrates that CO2 concentration

has increased almost 25% between 1958 and 2012 [17]. The combustion of fossil fuel,

some energy-intensive industrial processes, land use changes (mainly deforestation),

agriculture and domestic waste disposal are the most important contributors to the

growing CO2 emissions [15, 18].

Figure 2.2. Annual mean atmospheric carbon dioxide concentration at Mauna Loa Observatory,

Hawaii, USA

Given the negative effects of increasing GHG emissions, the United Nations Framework

Convention on Climate Change (UNFCCC) was set up as a first international climate

treaty in 1992. The aim was to mitigate climate change due to the global temperature rise

and to cope with its inevitable impacts. A few years later, the need for stronger measures

to limit the increasing GHG emissions resulted in the adoption of the Kyoto Protocol (KP)

on December 11, 1997 in Kyoto, Japan [19]. The main objective of this international

agreement was to legally commit its parties by setting internationally binding targets and

timetables for reducing GHG emissions. The protocol came into force in 2005, and a

heavier burden has been placed on developed nations. This is mainly because such

countries are recognized as principally responsible for the current levels of GHG

emissions in the atmosphere due to their industrial activities over the past two centuries.

The average emission reduction target for the first commitment period of this protocol

310.00

320.00

330.00

340.00

350.00

360.00

370.00

380.00

390.00

400.00

1955 1965 1975 1985 1995 2005 2015

Ave

rage

CO

2co

nce

ntr

atio

n (

pp

m)

Year


(2008-2012) was 5% from the 1990 levels [19]. During the second commitment period

from 2013 to 2020, the target was set to at least an 18% reduction of GHG emissions from

the 1990 levels [20].

2.2.2. Climate change and the power sector

Currently, about 37% of global primary energy is consumed by electricity generation. The

global electricity generation was 22,126 TWh in 2012 [21], with an annual average

growth rate of 2.95% from 1990 to 2012 [8]. Fossil-fuel electricity generation accounted

for 68% of the total generation and coal, the most carbon-intensive fossil fuel, was the

largest contributor to the electricity supply in 2012. Figure 2.3 shows the share of all

sources in the production of electricity in 2012 (data adopted from key world energy

statistics 2013, International Energy Agency [21]).

Figure 2.3. Electricity generation from various sources in 2012

The ever-increasing world demand for electricity generation represents the largest driver

of demand for primary energy consumption. The demand for electricity is projected to

grow more rapidly than the increase in total energy consumption over the next few

decades [1, 12]. This demand will be almost 70% higher in 2035 than the current

electricity demand [22].

As mentioned earlier, CO2 is the most important greenhouse gas contributing to climate

change and the power sector is identified as the single largest sector emitting CO2.

Oil4.8 %

Natural gas 21.9 %

Coal41.3 %

Nuclear11.7 %

Hydro15.8 %

Other4.5 %


According to the IEA, CO2 emissions from the electricity and heat supply sector

constituted about 42% of total global CO2 emissions from fossil fuels in the year 2011 [3].

2.3. Mitigation policies

The successful implementation of efficient mitigating measures is extraordinarily vital to

stabilizing GHG concentration in the atmosphere. The mitigation of greenhouse gas

emissions can be achieved through a wide variety of measures and tools in different

sectors including energy, industry, agriculture, forestry, etc. The focus of this sub-section

is on the mitigation options for the energy sector, which has the highest importance in

terms of sectorial share of global GHG emissions [9]. These options can ultimately reduce

the GHG emissions per unit of energy consumption through the following actions:

Energy conservation and efficiency improvement;

transformation/replacement of carbon-intensive fossil fuels by cleaner

technologies such as switch from coal to natural gas, enhanced use of RE

sources, and enhanced utilization of nuclear energy; and

reduction of CO2 emissions using CCS while utilizing energy from fossil fuels.

Improving energy saving and efficiency is a priority within all mitigation policies [7].

Energy saving could be performed using more stringent minimum requirements for

appliances and new buildings, high renovation rates for existing buildings and the

establishment of energy savings obligations on energy utilities. The reduction of GHG

emissions due to the efficiency improvement will, however, be gradually decreased

because of the associated cost of further improvements [9]. On the contrary, less carbon-

intensive technologies such as RE and GHG emissions abatement through CCS will be

more attractive because of their decreasing costs as a result of technological maturity [9].

There has been a great deal of speculation on the further utilization of nuclear energy

since 2011 after the Fukushima accident at the Fukushima Daiichi plant in Japan. Soon

after this accident, a few countries such as Germany and Switzerland adopted constrained

nuclear energy scenarios, which allow the retirement of plants over their lifetime or

earlier, without commissioning any new installations. Some countries will maintain the

total deployment of nuclear energy at current levels. Nevertheless, economic

considerations as well as the security of the energy supply would result in the domination


of pre-Fukushima nuclear scenarios coupled with tighter safety requirements [23] as

several new nuclear plants are currently under construction around the globe [24].

Renewable energy has considerable potential to play an important and increasing role in

achieving GHG mitigation targets and to eliminate GHG emissions from the combustion

of fossil fuels. These energy sources are undoubtedly the only option for the future.

During recent years, many RE technologies have become increasingly market

competitive, resulting in a significant increase in their global deployment [4]. Renewable-

based electricity generation is expected to continue growing over the next few decades

due to high government support and declining investment costs. Under different IEA

scenarios, the share of RE sources in total electricity generation rises from 20% in 2011 to

25-48% in 2035. However, producing energy from renewable sources is still not wholly

mature and cannot meet the present demand fully in an economic and feasible way. The

estimated timescale for the complete transformation from fossil fuels to renewable

resources is not definite and is likely to be a significant time away [5].

Carbon capture and storage could constitute an important part of the mitigation portfolio

for the stabilization of atmospheric greenhouse gas concentrations over the course of the

21st century [7, 9]. The deployment of this decarbonization strategy in the power sector

will maintain continued utilization of fossil fuels and the available infrastructure, while

also limiting the anthropogenic CO2 emissions in the near future. The widespread

deployment of CCS technologies might also prevent a drastic falling of fossil fuel

consumption as a result of the higher share of RE sources and more stringent emissions

regulations in the future.

It should be clearly underlined that no single mitigation option can provide all of the

emission reductions required for the stabilization of atmospheric GHG concentrations

[25]. Thus, a portfolio containing all the aforementioned mitigation options is necessary to

provide a comprehensive package of different sustainable solutions to tackle increasing

anthropogenic GHG emissions.

2.3.1. Carbon capture and storage

Carbon capture and storage is an essential measure designed to curb global CO2

emissions. The commercial realization of the CCS process involves three main steps a)

separation of CO2 from industrial/energy-related sources, b) transport of the


predominantly captured CO2 to a storage site (using high pressure pipelines, trucks, or

vessels) commonly in a supercritical state, and finally c) long-term isolation from the

atmosphere (please note that the latter two steps are not covered in this thesis). The

separation of the CO2 emissions, so called capture, is usually regarded as the most

expensive component in the CCS chain.

The main application of CCS is most likely to be in the large point sources (due to techno-

economic aspects) such as fossil-fuel power plants, fuel processing plants as well as other

industrial plants such as iron, steel and cement production plants. The application of CCS

in power generation, industries and fuel transformation has a mitigation potential of up to

20% by 2050 according to IEA scenarios [26]. Despite the great progress achieved in the

development of highly effective capture technologies, large-scale CCS application is not

yet commercially available for the power generation sector [27]. Although considerable

global efforts were under way to develop efficient and affordable CCS technologies, some

barriers towards the widespread deployment of CCS-related technologies remain unsolved

such as:

Lack of international agreement on cutting CO2 emissions [28];

public perception and knowledge of CCS [28];

legal and regulatory aspects such as lack of regulations on CO2 quality for

transport and storage and lack of required assessments of pipelines and storage

sites [18, 28];

market and political issues such as carbon credits and uncertainty of future

carbon costs [28];

High risk for leakage and other safety aspects associated with transport and

injection of CO2 in the designated storage sites;

high capital-intensity of most CCS technologies [26]; and

lack of commercial-scale demonstration plant, high efficiency loss, technical

maturity and uncertainties for CCS application in power plants.

2.3.2. The European Union climate strategy

Taking serious actions to mitigate the dangerous effects of global warming has been one

of the European Union’s strategic priorities during the last two decades. This will ensure

more sustainable and secure energy systems. To limit the increase of the global average


temperature so that it does not exceed 2 ºC higher than the pre-industrial level, the

European Council adopted three targets to meet by 2020 in relation to the 1990 level [29]:

Reduction of GHG emissions by 20%;

improving the energy efficiency by 20%; and

increasing the share of renewable energy to 20%.

The EU has also implemented several measures to reach these targets and to stimulate the

economy and job market. Measures include, but are not limited to, are establishing the 1st

international carbon market, the EU emissions trading system (ETS), assigning national

targets for domestic GHG reduction and increasing RE sources, setting up new standards

to improve energy efficiency and reducing GHG emissions in the transport sector [30, 31].

In implementing foregoing actions and strategies, Europe has made a good progress

towards its target for GHG emissions reduction. The estimation for combined emissions

from the European member countries was about 18% below the 1990 level in 2012 [31].

The share of renewable energy sources in gross final energy consumption was about 14%,

and some countries could have already achieved their 2020 targets in 2012 [32].

The European Commission has recently announced its 2030 climate and energy goals,

including: GHG emission reduction by 40% below the 1990 level, increase of renewable

energy by at least 27% and renewed ambitions for energy efficiency policies. The

European Union aims to achieve a competitive, secure and low-carbon economy, while

maintaining the affordability of energy for end-users [33].

2.4. Various capture technologies in the power sector

The previous background information showed the necessity for CO2 emissions reduction

in the power generation sector. Various CO2 separation methods have been developed and

utilized by industry for many years. However, these technologies have not been

commercially applied in the power sector through CCS application. All of the currently

available technologies for large-scale CO2 separation require both significant additional

equipment and energy input than the standard power plants without capture [34]. Progress

in many directions connected to CO2 capture technologies has been rapid, and many

innovative concepts have been developed during the last decade. Concepts like chemical


looping combustion (CLC), membrane and adsorption technologies have been explored to

find more energy-efficient and less expensive approaches [35].

In spite of extensive development of the aforementioned emerging technologies, the

timescale for the deployment of each technology in the power generation sector and its

current development status differ. Due to the urgent need for successful demonstration of

capture projects, it is important to check the near-term prospect of each capture approach

to reduce the number of available options. The current section will, therefore, give an

overview of the proven technologies for commercial CO2 capture deployment in fossil-

based power plants. The available approaches for this purpose are often divided into the

three following categories:

Post-combustion capture from combustion flue gas;

pre-combustion capture or de-carbonization of the fuel stream; and

oxy-fuel combustion or direct combustion of fuel with oxygen (O2).

These three approaches are shown in Figure 2.4. These technologies can be applied to

both gas-fired and coal-fired power systems.

Power & Heat

Fuel

Air

CO2 separation

Power & HeatFuel

Shift reaction,

gas clean-up +

CO2 separation

Reforming/

Gasification

Syngas

AirSteam or Air/O2

H2

Post-combustion capture

Pre-combustion capture

Oxy-fuel combustion

N2, O2, H2O

N2, O2, H2O

Power & Heat

O2

Fuel

Air separationAir

N2

CO2 dehydration,

compression,

transport, and

storage

CO2

CO2

CO2

Recycled CO2&H2O

Figure 2.4. Technical options for CO2 capture from fossil-based power plants


Regardless of the CO2 capture type, the following common challenges need to be

addressed by further development in CO2 capture technologies:

The complexity of the power plants inevitably increases with deployment of CO2

capture.

The operability and flexibility of the power plants are negatively affected by

deployment of CO2 capture. In particular, these items need to be assessed: the

dynamic/transient behavior of the plants during start-up, shut-down and load-

changing conditions.

2.4.1. Post-combustion CO2 capture

The post-combustion CO2 separation comprises the removal of carbon dioxide from flue

gas after combustion of the fuel. The small fraction of CO2 in the flue gas, which is mixed

with other combustion products and a large fraction of nitrogen from atmospheric air,

makes capture difficult. There are four main processes which can be utilized for large-

scale CO2 removal from flue gases:

Absorption using re-generable liquid solvents;

cryogenic separation anti-sublimation;

membrane technology; and

adsorption using solid adsorbents.

The absorption process, by means of a re-generable chemical solvent (Figure 2.5),

typically based on a form of amine, is currently considered as the most

common/developed technique for post-combustion capture [36, 37]. Other CO2 separation

methods still need more research and development attention to achieve mature and cost-

effective processes.

The solvent is counter-currently being contacted by the sour gas (gas containing CO2)

from the top of the absorber column. From the absorber bottom, the CO2-rich solvent is

then transferred to a regenerator where it is stripped of the CO2 by heat transfer (e.g. heat

release from steam). The regenerated or CO2-lean solvent is cooled via a lean/rich solvent

heat exchanger and recirculated to the top of the absorber, completing the cycle.


Absorber Stripper

Rich solvent

Lean gas

Rich/lean solvent HEX

Steam

Treatment

Direct

contact

coolerFlue gas

BlowerReboiler

Lean amine cooler

Lean pump

Condenser

CO2

Figure 2.5. The schematic configuration of the conventional absorption system

One of the most important features of the post-combustion capture is that it can be applied

to newly designed or existing fossil-fuel power plants. In addition, this capture approach

can be applied to other industries such as cement production, oil refining and

petrochemicals. Moreover, the impact of this approach on the power conversion process is

marginal [38], especially when an external heat source for regeneration is applied.

However, the capture process is less efficient due to the low concentration of CO2 in the

flue gas [38], which is typically between 3 and 15 vol% depending on the fuel type [18].

The major challenge ahead for the widespread deployment of post-combustion capture is

the relatively large parasitic load on the power plant due to the energy intensive solvent

regeneration process [38, 39]. Other secondary challenges are the high capital costs

required for the capture unit and to develop proper solvents (in the case of the absorption

method) with low degradation rate and volatility with fewer negative environmental

impacts.


2.4.2. Pre-combustion capture

Carbon dioxide can also be separated prior to the combustion process by converting the

fuel to CO2 and hydrogen (H2) and removing the CO2 from the fuel gas. The following

main processes can be utilized for large-scale CO2 separation from the fuel stream:

Absorption using physical or chemical solvents or hybrid system using

physical/chemical solvent;

pressure/temperature/electric/vacuum swing adsorption;

membrane technology; and

calcium oxide carbonation.

Similar to post-combustion, the absorption process is the most preferred technology for

pre-combustion capture, more specifically using physical solvents when the pressure of

the syngas is high. The other technologies are still at an early stage of development, and

many uncertainties remain concerning the performance of these individual technologies

when integrated into the rest of the power plant [18].

One of the promising technologies that could benefit from pre-combustion capture is the

integrated gasification combined cycle. The block flow diagram of the IGCC power plant

with CO2 capture is illustrated in Figure 2.6. The synthesis gaseous product (often known

as syngas) leaving the gasifier, where partial oxidation of the fuel (e.g. coal or oil) occurs,

is mainly a mixture of H2 and carbon monoxide (CO). By the addition of steam, the CO

content of the syngas is catalytically shifted to CO2. The CO2 is finally removed from the

H2 and the hydrogen-rich syngas is used as fuel in a gas turbine. The high CO2

concentration after CO-shift reaction allows efficient de-carbonization of the fuel stream.

Therefore, pre-combustion imposes a lower energy penalty than for post-combustion with

similar size and duty [40-42].

The other technologies which have great potential for pre-combustion capture are H2

production plants using steam reforming, partial oxidation and auto-thermal reforming of

natural gas or light hydrocarbons [18]. Detailed descriptions of these technologies are

available in standard textbooks and hence are not given here.


Power & Heat

Fuel Raw

syngas

Air/O2

H2-rich syngasAir

N2

CO2

Slag

Gas cooling/

dedustingShift reaction

Acid gas

removal

CO2 removal

Gasification

Air separation

unit

Air

CO2 compression &

dehydration

Sulfur recovery

Sour gas

Clean syngasSteam Liquid CO2

N2

StackElectricity to

grid

Flue gas to atmosphere

Figure 2.6. The block flow diagram of the IGCC power plant with CO2 capture

As with CO2 captured at higher pressure level, compression energy demand and capture

unit size (and consequently costs) are lower than those for post-combustion capture [40].

This capture approach also has the following advantages:

Chemical processing of the syngas (as in IGCC plants) coupled with CO2 capture

offers a wide range of products (e.g. H2, Fischer-Tropsch fuels) and a wide range

of downstream equipment such as gas turbines and fuel cells [40].

Due to the higher pressure and lower volume of the syngas flow to be treated in

the capture unit, the size of the capture unit is smaller than for the post-

combustion capture, where flues gases are treated.

Although the pre-combustion approach offers a less-expensive CO2 mitigation

technology, the incorporation of this method has major effects on the power conversion

process [38]. This drawback limits the application of pre-combustion on the existing

power plants.

It should be highlighted that the current thesis will focus on the application of post-

combustion CO2 capture in IGCC plants and its effects on the techno-economic

performance of the entire plant as well as on the GT unit.


2.4.3. Oxy-fuel combustion

Oxy-fuel combustion is the last promising approach described in this chapter designed to

support the separation of CO2 from fossil-based power generation. Similar to other carbon

capture approaches, oxy-fuel has yet to be commercially deployed, while it has a lower

technological readiness than the two latter capture technologies [28, 36, 39].

The nitrogen content of the air is almost 80 vol%, which dilutes the CO2 concentration in

the flue gas from the combustion process and makes the downstream CO2 capture process

costly. In the oxy-fuel combustion process, N2 is removed from the air by means of a

large-scale air separation unit (ASU) before the combustion (refer to Figure 2.7). This

process comprises a combination of high purity oxygen (typically around 95 mol%) and

recirculation of the flue gas for combustion of the fuel. The combustion product is a gas

consisting mainly of concentrated CO2 and water (H2O). Such a process (i.e. pure O2

combustion) has a combustion temperature of about 3500 °C [18]. Current materials

cannot handle such a high temperature. Oxy-fuel combustion is not feasible for currently

available gas turbines in natural gas combined cycles since their compression and

expansion systems are not suitable for CO2 as the main working fluid instead of N2 in air

[43]. Recirculation of a part of flue gas is, hence, to control the flame temperature and

consequently NOx formation in the boiler. In addition, this recirculated stream

compensates for the missing N2 flow to carry the heat through the boiler [27, 28]. This

stream is also used to feed the fuel to the boiler in the case of coal-firing plants [28]. The

recycle stream is about 60-70% of the flue gas, depending on the fuel composition [28].

The rest of the flue gas that is not recycled is then treated for undesirable components

such as particulates and sulfur removal. The clean flue gas is finally compressed, cooled

and purified from water vapor by condensation. The final product is predominantly CO2,

which is ready for transport and storage.


N2

Fly ash

Air

separation

unit

Air O2

Coal millCoal

Electrostatic

precipitator

Flue gas

desulfurization

Flue gas

condenser

Power

Gas-gas HEX WaterSulfur product

Flue gas primary recirculation

Flue gas secondary recirculation

Pulverized coal

To CO2 purification,

compression, transport &

storage

Flue gas to atmosphere

Figure 2.7. The block flow diagram of the pulverized coal plant with oxy-fuel combustion

One of the advantages of the oxy-fuel combustion is its significantly lower size of capture

unit compared to other technologies by combusting the fuel using purified oxygen [38].

Furthermore, the oxy-fuel combustion eliminates the need for conventional CO2 removal

technologies using chemical or physical absorption. Significant cost and energy savings

can, therefore, be realized. Moreover, oxy-fuel combustion offers flexibility for the

positioning of O2 injection either into the recycled stream (as pre-mixed condition) or

directly to the burner compared to the air combustion, which may help to control pollutant

emissions e.g. CO emissions [28]. However, the major challenges of oxy-fuel combustion

also revolve around a drastic change of working fluid from conventional air combustion to

a mixture of mainly CO2 and water vapor. The other technical uncertainties regarding the

commercial deployment of oxy-fuel combustion are as follows:

The need to supply high purity oxygen results in a large efficiency penalty using

energy-intensive processes such as conventional cryogenic distillation. Such a

process is not economically viable for oxy-fuel combustion [28] and can be

replaced with emerging technologies such as ion transport membrane (ITM)

technology to reduce the costs and energy consumption.

Oxy-fuel combustion has a high impact on the power plant process, which

complicates retrofitting existing plants [38]. This approach needs substantial

modifications (redesign) for the GT or conventional steam boiler technologies

(more specifically combustion system) due to the drastic change in the working

fluid [38, 44].


This approach cannot be applied just to a fraction of the main stream, so-called

slipstream, similar to post- or pre-combustion capture. This causes such an

approach to be applied only to a complete power plant module [39].

The high proportions of CO2 and H2O in the flue gases (compared to air

combustion) result in higher gas emissivity (radiative heat transfer) [27]. Thus

more sophisticated and expensive materials are required to be resistant against

the higher heat transfer rate [38], and a large volume of the flue gas needs to be

recirculated to offset the higher gas emissivity. Full-scale demonstration

boilers/GTs are required to validate radiative CFD models and thereby provide

accurate predictions of heat transfer between working fluid and materials [28].

In the case of boilers, the high concentration of CO2 (which has a high solubility

in water), high level of sulfur, and chlorine species generate a corrosive media

which requires particular caution when selecting proper materials [28, 38].

The condensation of water in the presence of a substantial amount of CO2 needs

to be carefully assessed [38].

25

3. Coal-based power plants

The current chapter firstly includes a synopsis of energy supply by coal and CO2

emissions from coal-based power generation technologies. Different coal-based power

systems are then reviewed. An overview of different available technologies and

components which constitute an integrated gasification combined cycle power plant is

further presented and discussed. Finally, the existing IGCC plants are listed and their

specifications are reviewed. The outline of Chapter 3 of this thesis is shown in Figure 3.1.

Integrated gasification combined cycle (3.3)

Why coal-based power

plants?

(3.1)

Coal-fired power generation

(3.2)

Air separation

(3.3.1)

Gasification

(3.3.2)

Syngas cleaning

and conversion

(3.3.3)

CO2 compression

and dehydration

(3.3.4)

Gas turbine

(3.3.5)

Bottoming

cycle

(3.3.6)

Current IGCC power plants

status

(3.4)

Figure 3.1. Outline of Chapter 3

26 Coal-based power plants

3.1. Why coal-based power plants?

Coal showed 2.5% higher consumption in 2012 compared to 2011 and has been the

fastest-growing fossil fuel during recent years [8]. The global distribution of proved coal

reserves (total: 860,938 Mt), together with coal consumption (total: 3,730 Mtoe) and

production (total: 3,845 Mtoe) are shown in Figure 3.2 (data from Ref. [8]). The IEA’s

New Policies Scenario projected a 25% increase in coal consumption in the year 2035

compared to 2009, while the other IEA scenario, Current Policies, predicted 65% higher

coal consumption than the level of 2009 [5].

(a)

(b)

(c)

Figure 3.2. Global share of (a) proved coal reserves, (b) coal production, and (c) coal consumption

at the end of 2012

29 %

1 %

35 %

0 %

4 %

31 % 14 %2 %

12 %

0 %

4 %68 %

12 %1 %

14 %

0 %

3 %

70 %

North America

South & CenterlAmericaEurope & Eurasia

Middle East

Africa

Asia Pacific

Coal-based power plants 27

The main reasons for the continued utilization of coal are the abundant resources of coal

(more than 100 years with current proved reserves and consumption rate), its widespread

availability and less-volatile price compared to the other fossil fuels [8, 45, 46]. Thus, coal

has emerged as the most widely used fossil fuel for large-scale power generation, though

natural gas use is also increasing, mostly in localities of availability due to the fact that it

is more environmentally friendly [5].

Coal is not only the most used fossil fuel for power generation but it is, unfortunately, the

most polluting fuel due to its heavy carbon content per unit of energy released. Carbon

content is 15.3 tC/TJ for natural gas, while it is almost double, 25.8 to 28.9, for different

types of coal [47]. Carbon dioxide emissions from coal for heat and power production

were 8.9 Gt CO2 in 2011, about 28.5% of the global anthropogenic CO2 emissions [3].

Given the continued need to use coal as primary fuel and requirements to limit its CO2

and conventional emissions, a genuine demand for the development of reliable and low-

emission coal technology has been generated. In addition, some political actions have

been taken which are in favor of clean coal technologies. New regulations which enforce

the construction of new coal-fired power plants with CCS demonstration or CCS ready

capability are among those [27]. However, it should be mentioned that due to low costs

for CO2 allowances, there is still not enough pressure on owners to build plants with CO2

capture.

3.2. Coal-fired power generation

The major coal-based power generation technologies available today are pulverized coal

combustion (PCC), fluidized bed combustion (FBC) and IGCC. This sub-section will

briefly touch on PCC and FBC technologies, while the rest of this chapter will focus on

IGCC.

PCC technology has been dominating coal-fired electricity generation worldwide for

almost 100 years. Figure 3.3 illustrates the block flow diagram of the typical pulverized

coal-fired plant (with post-combustion CO2 capture unit). Typical operating parameters of

pulverized coal plants using a sub-critical steam cycle are 163 bar pressure and a

temperature of 538 °C for both superheat and reheat [48]. The efficiency of a steam cycle

is a function of the steam pressure, superheat and reheat temperatures, which are all


dependent to the advances in materials that are selected for the boiler and turbine and

pipework connecting them [49]. In order to achieve higher technical performance and

lower emissions, supercritical and ultra-supercritical pulverized coal plants have been

developed. These plants are operated beyond the critical point of water, i.e. 221 bar and

374 °C [49]. Supercritical and ultra-supercritical technologies are more beneficial,

avoiding surface tension between liquid and gas phase and eliminating the use of a drum

for separation of water and steam in sub-critical plants. They are also better suited to

frequent load variations compared to sub-critical boilers. The typical pressure range of

SCPC is more than 245 bar, with the temperature in excess of 550 °C for both superheat

and reheat steam, and the temperature range of ultra-supercritical pulverized coal plants

(USCPC) is around 600°C or higher [48].

Although the share of SCPC and USCPC plants currently under construction or planned is

increasing, sub-critical technology has still continued to dominate coal-fired power plants.

However, the share of supercritical and ultra-supercritical plants might be increased with

stricter requirements for CO2 emissions [50].

CO2 product

Stack

Coal and ash handling

CoalPulverized coal boiler

HP

turbineIP

turbine

LP

turbine

Electrostatic precipitator

FGD

Condenser

Feedwater heater system

Oxidation air

Effluent Gypsum

Wa

ter

Limestone

DeNOx plant

Flue gas

Flue gas

Air

Ammonia

Capture unit

Fly ash

Bottom ash

Pre-heated air

Steam/water to and from capture plant

Flue gas

Figure 3.3. Block flow diagram of typical pulverized coal-fired plant with CO2 capture


The other coal-based plant, i.e. FBC technology, contributes in niche applications, e.g. in

the combustion of low quality coals [51]. This technology offers both atmospheric and

high pressure operation [52]. A fluidized bed combustion system is generally

characterized by acceptable availability and fuel flexibility and has a good emissions

performance. Its emissions control is usually cheaper than that of PCC technology.

Although development efforts have been focused on scaling up the technology, the

capacity of this technology is far behind the conventional PCC plants [53]. Similar to

SCPC and USCPC technologies, the development of advance materials to cope with

higher pressure and temperature will improve the technical performance of this

technology [27].

Carbon dioxide emissions can be captured from both the abovementioned technologies,

i.e. PCC and FBC, using oxy-fuel and post-combustion methods. However, challenges

including the parasitic effects of CCS using post-combustion (refer to Chapter 2) require

technical progress such as achieving higher plant efficiency.

The other alternative coal-fired technology is the IGCC power system. The integrated

gasification combined cycle is currently one of the most promising technologies for the

efficient use of coal. This technology enables the conversion of coal (and other solid or

liquid fuels) into synthetic gas fuel, while still maintaining ambitious emissions targets

and high efficiency. IGCC technology benefits from its widely known environmental

credentials such as low emissions of sulfur dioxide (SO2) and nitrogen oxides (NOx) [54].

Although this technology suffers from high capital costs and is perceived to be more

complex than other technologies, e.g. pulverized coal plants, its significantly better

emissions performance is of high interest for future large-scale deployment [27, 49]. In

addition, the IGCC technology offers co-gasification of biomass1, good performance with

lower grade coals and other feedstock [55], as well as co-production of H2 and electricity

[56].

Moreover, IGCC technology is technically well suited for CO2 capture. If CCS becomes

mandatory for the next generation of fossil-based power plants, high-efficient pre-

combustion carbon capture methods can be incorporated into the IGCC system. The

additional cost due to the capture unit will be significant but probably lower than for PCC

1 The biomass co-gasification can be utilized to achieve even a CO2-free or CO2-negative condition

when CO2 capture is integrated into the cycle.


systems [57]. Regardless of the lack of demonstration activities for IGCC plants with CO2

capture, every component of this system has been commercially utilized in other

industries, such as chemical industries, petrochemical complexes, etc. The heart of the

power generation unit, i.e. gas turbine technology, suited to an IGCC system with and

without carbon capture unit, when the diluted syngas is used, is also currently available on

the market [58, 59].

3.3. IGCC power plant’s components

An IGCC power plant consists of several components which can be categorized in

different sub-systems depending on their main processes. The main sub-systems of an

IGCC plant are as follows:

Coal receiving and storage unit;

air separation unit;

coal milling, drying, and gasification;

syngas cleaning and conversion unit;

water-gas shift reaction unit (in a plant with CO2 capture unit);

acid gas removal (AGR) unit;

CO2 compression and dehydration (in a plant with CO2 capture unit); and

power island consisting of a gas turbine and a heat recovery steam generator

(HRSG), steam turbine, generator, auxiliaries, etc.

With the exception of coal receiving and storage units, process descriptions of the state-

of-the-art technologies for main sub-systems together with currently potential alternative

technologies for each sub-system will be presented here.

3.3.1. Air separation

Oxygen supply to the gasifier represents a major part of the energy consumption and

capital costs of any IGCC power plant. The technology currently used for oxygen

production is the cryogenic separation of the air by distillation, a mature technology used

for over 100 years.

In a typical cryogenic air separation unit (refer to Figure 3.4), the air is initially

compressed to a pressure of about 5 bar [18]. It is then purified using multiple fixed bed

adsorption units to remove water, CO2, N2O and trace hydrocarbons. Such components


could accumulate to undesirable levels in the cryogenic parts such as the reboiler-

condenser, causing a blockage (due to freezing of CO2 and H2O) and other safety issues

for the plant operation. The adsorption units are regenerated by either temperature or

pressure swing with a low pressure N2 stream. Then, the air is cooled to about its dew

point by heat transfer with returning products (O2 and N2) in the main heat exchanger. The

air is finally separated into oxygen, nitrogen and, optionally, argon (Ar) streams in the

separation part. The separation process depends on the relative volatility of the more

volatile components (N2 and Ar) relative to less volatile O2. A basic arrangement for the

separation part involves a double distillation column which has a reboiler-condenser

between two columns [60]. The O2 product can be withdrawn from the base of the low

pressure column (upper column in Figure 3.4) either as a liquid or a gas.

Filter

Main

heat exchanger

Pre-

treatment

GOX

Air

GAN

Product

compression

Low pressure

column

High pressure

column

Sub-

cooler

MAC

Expander

Reboiler/condenser

Figure 3.4. Schematic configuration of the cryogenic air separation unit

The main parameter controlling the power consumption of a cryogenic ASU is the main

air compressor (MAC) discharge pressure, which is inherently affected by the pressure


balance and reboiler-condenser design. Consequently, numerous alternatives for the

configuration of heat exchange, distillation, compression and pumping exist to minimize

the energy consumption of an air separation unit. The second important parameter

affecting power consumption is the number of product streams and their purity. The

higher purity of the O2 product (typically higher than 97%) requires a higher number of

separation stages, which results in higher MAC discharge pressure, capital and operational

costs [60]; hence, there is a trade-off between capital cost and power consumption and the

purity of oxygen.

Generally, the main areas to reduce specific energy consumption and costs are:

Efficiency improvement by integration of ASU with other sub-systems such as

GT compressor;

development of other air separation technologies to reduce specific energy

consumption for O2 production (kWh per unit of O2 product); and

improvement of basic components of cryogenic ASU.

3.3.1.1. Cryogenic ASU and power island integration options

The power generation block of an IGCC plant could be integrated with the air separation

unit (refer to Figure 3.5) through the following ways:

Gas turbine air extraction (full or partial air integration) to supply the ASU; and

N2 supply from the ASU to the GT for dilution purposes (NOx control), for

turbine cooling, for GT power augmentation, and for increase of steam

generation in the HRSG.

Air extracted from a GT compressor can be used to partially or fully supply the

requirements of the ASU, which can be defined according to the following equation:

Air − side integration = Air to ASU from the GT

Total Air to ASU (Eq. 3.1)

Full GT-ASU integration means that the feed air for the ASU is completely supplied by

the gas turbine air compressor [61]. The integration between the ASU and the gas turbine

can significantly affect GT performance [62], which will be discussed later in this chapter.

Most European IGCC designs have selected full GT-ASU integration targeting maximum

overall plant efficiency [63]. However, this integration option generates some operation

problems. The main difficulty is control of the ASU when the GT operates at variable


load. Increase of GT power output may result in an increased GT compressor discharge

pressure, which causes a pressure rise of the air delivered to the ASU. Consequently, the

boiling pressure and temperature of the liquids in the ASU will be elevated, meaning that

liquids in the columns will be sub-cooled. The net vapor flows will then be reduced, while

the GT combustor requires higher fuel flow for the increased power production and vice

versa. This problem may be efficiently resolved utilizing an expansion turbine before air

injection to the ASU to maintain the discharge pressure of the GT compressor similar to

that required by the ASU. The other problem with full air integration arises during start-up

of the ASU and the gasification system. Gasification needs O2 and N2 (depending on the

technology selected for gasification) to produce syngas (i.e. the GT fuel). Therefore, the

gas turbine should operate on NG or liquid fuels to supply the initial amount of air, or a

supplementary air compressor for start-up of the ASU should be considered.

Partial air integration means that only a part of the air required for the ASU is supplied

from the GT compressor and the rest is provided by a supplementary compressor. This

configuration allows the GT system to be started after the start-up of the ASU and

gasification processes. The amount of air flow to be withdrawn from the GT compressor

depends on the air flow required for the plant start-up (to be supplied by a separate

compressor) and the amount of air available from the GT (based on the GT design [64]

and the prevailing atmospheric conditions). The optimal situation is to ensure that the

overall loading of the GT expander is maximized (choked). The required thermal energy

input of the GT shows a substantial increase in fuel gas flow in the case of using diluted

syngas fuel due to its significantly lower calorific value compared to that of NG. The

additional fuel flow (compared to the NG case) possibly results in bleeding of the GT

compressor air to avoid an increase in flow rate expanding in the GT expander, which is

already maximized. Consequently, this is the available air feed which could be allocated

to the ASU [60].


Air

O2

Air separation

unit

Stack

To atmosphere

Air

Heat recovery

steam generator

Air

HP DGAN

LP DGAN (and H2O)

N2

LP DGAN

Syngas fuel

To gasification

Heat integration

LP DGAN

Figure 3.5. Integration options of the ASU and the power island

The zero supply of air from the GT compressor to the ASU (or non-integrated air-side

GT-ASU) is usually only optimum when higher operational flexibility, availability, and

reliability of the overall IGCC system is the main concern [65]. However, this option may

be also applied under circumstances when the air flow from the GT compressor is limited

(e.g. due to the re-allocation of the GT compressor air for cooling purposes of expander’s

parts) [60] and there is no need for dilution using N2 coming from the ASU.

In addition to air-side GT-ASU integration, high pressure (HP) diluent gaseous nitrogen

(DGAN) from the ASU can be integrated into the GT as diluent to control NOx emissions

[66]. Nitrogen could be compressed and then heated by the extracted air feed stream from

the GT in the case of partial or full air integration. It should be mentioned that, in the most

recently developed GTs, the margin allowing for extra fuel (or added N2) is limited and

depends on atmospheric conditions [60]. N2 injection could be performed directly to the

combustor or as a mixture with the syngas. This nitrogen can also contribute to increased

power output from the expander [62]. Low pressure (LP) diluent gaseous nitrogen

(DGAN) is commonly used in the ASU as a source to cool the compressed air feed stream

from the GT [67]. Low pressure DGAN together with chilled water from the ASU could

be fed to the inlet of the gas turbine compressor to reduce the bulk air temperature and

thereby increase the air mass flow rate to achieve higher GT power output. The use of


nitrogen as diluent also provides the opportunity to exploit higher steam generation in the

HRSG due to the lower dew point of flue gases containing higher amounts of N2.

3.3.1.2. Other ASU technologies

The other important oxygen production technologies are adsorption, polymeric membrane

and ion transport membrane processes. Ongoing research and development will continue

to improve both the economy and the energy efficiency of these technologies. Unlike

cryogenic plants, which need approximately two hours to produce O2 and N2 from a cold-

condition start-up, adsorption and membrane systems can be started and powered up to

full load within a few minutes [68]. Adsorption and polymeric membrane systems are less

complex and more passive compared to cryogenic systems. However, neither technology

could yet compete with cryogenics for large-scale O2 production, especially at high

purities. Moreover, neither technology is capable of directly producing argon [69].

Ion transport membrane technology is a breakthrough ASU technology and the most

promising alternative to cryogenic technology for the production of large quantities of

oxygen. Compressed high-temperature air (at about discharge pressure of GT compressor

and 800-900 °C) is electrochemically passed through highly selective ceramic membranes

at high flux. Oxygen on the feed side (i.e. air) is ionized on the surface of the membrane

and diffuses through the membrane as ions forming oxygen molecules on the permeate

side [60]. The primary advantage of such technology is its significant potential for capital

costs reduction compared to cryogenic systems [70]. This potential could be up to 30%

compared to cryogenics in IGCC application [71]. Furthermore, ITM offers the possibility

of providing O2 with a less adverse effect on the efficiency of the power plant than the

cryogenic system, although this performance improvement is not strong (in the range of a

few decimal points) [72]. However, similar to other non-cryogenic technologies, ITM has

shortcomings concerning the production of pure and liquid by-products [69]. Moreover,

this technology needs to be commercially developed and integrated into the IGCC system

[73].

3.3.2. Gasification

The gasification process is one of the most important parts of the IGCC system and has

gained special significance in the context of future generation IGCC plants with CO2

capture. This process is to convert coal (can also be other feedstock, e.g. biomass, liquid


fuels, etc.) through sub-stoichiometric reaction with oxidant agents, either air or O2 at a

temperature exceeding 700 °C to produce a synthetic gaseous product [41]. Compared to

conventional pulverized coal combustion, gasification offers great opportunities for both

higher efficiency and improved capture of pollutants. The commercial gasification

technologies can be classified into three categories according to the flow geometry:

entrained-flow, fluidized bed, and moving bed gasification technologies [74]. In most

existing industrial plants, including IGCC power plants, the entrained-flow gasifiers have

had extensive operating experience [75]. Thus, the description of other main categories,

i.e. fluidized bed and moving bed are excluded here and can be found in references [41,

74].

3.3.2.1. Entrained-flow gasifiers

Entrained-flow gasifiers allow high operating pressures (20-80 bar) and temperatures

(1200-1600 °C). The high pressure and temperature environment of the gasifier facilitates

the gasification of the fed coal [76]. However, challenges corresponding to measurement

techniques and instrumentation due to the rigid environment, and possible problems with

slag handling and removal still need more development [77, 78].

High operating temperatures enable a favorable slagging process to remove ash and

render gasification almost tar-free. The released heat results in the melting of the ash

content and the production of molten, inert slag (eventually as the only solid waste).

Meanwhile, and under extremely hot conditions, the carbon content in the coal is

converted mainly to CO due to the reducing environment of the gasifier. This type of

gasifier typically provides a high H2/CO ratio syngas. Apart from these combustible

compounds, products typical for combustion, CO2 and H2O, are also produced. Steam or

other compounds are added to the gasifier to moderate the hot temperature of the process.

Further details such as dominant reactions within the gasifier can be found in Paper III of

this thesis.

The oxidant agent can be oxygen or air. Amongst the various gasification technologies,

oxygen-blown gasification is an attractive process for the production of high calorific

value syngas (mainly due to its high H2 content). The plant’s components (gasifier and

downstream equipment) are also much smaller than that with the air-blown technology

due to oxygen combustion in the gasifier. On the other hand, the absence of a large ASU

in air-blown gasification offers some advantages in terms of capital and operating costs


and efficiency. However, the increase in the capital costs associated with a less effective

capture process (due to the removal of CO2 from a larger volume syngas diluted by N2 in

air) offsets the reduced power consumption of an air-blown system [79].

The feedstock can be fed either dry (using N2 as a conveying gas) or wet (using slurry

water) into the entrained-flow gasifier. In a dry-fed system, there is no need for water

evaporation (like for those slurry systems) in the gasifier, leading to high cold gas

efficiencies 1 compared to (single stage) slurry-fed entrained-flow gasifiers [80]. In slurry-

fed gasifiers, pulverized coal is mixed with water to produce a slurry feed. The typical

range of slurry (ratio of solid to whole mixture) varies from 35 to 70 wt%, depending on

the coal’s characteristics [65, 81, 82]. The slurry type of gasifier utilizes a slurry pump to

feed the slurry into the gasifier, enabling the process to have a higher operating pressure

compared to dry-fed systems. High operating pressures result in a more efficient CO2

separation due to the high partial pressure of CO2 in the syngas. In slurry-fed gasifiers

some CO and H2 burning is required to vaporize the slurry water. The syngas, therefore,

has a relatively high content of the combustion products (i.e. CO2 and H2O), which is

again suitable for the operation of downstream shift reaction and CO2 capture units. The

relatively high operating pressure of slurry-fed gasifiers compared to dry-fed gasifiers

results in a higher partial pressure of CO2 and consequently a lesser energy penalty due to

the removal process [83]. However, the ratio of hydrogen sulfide (H2S) to CO2 is higher in

dry-fed gasifiers, which improves sulfur recovery using a conventional absorption system

unit [84]. In addition, the dry-fed gasifiers show better performance when operating on

low quality fuels (with low calorific values) compared to the slurry-fed. Moreover, the

quality of produced syngas in dry-fed gasifiers is relatively constant compared to slurry-

fed types, even when low calorific fuel is gasified.

The aforementioned features of entrained-flow gasifiers are very desirable for large-scale

power generation. Hence, almost all the commercially useful coal gasifiers deployed for

large-scale power generation are of this type. Some of the leading companies in the power

sector have patented their gasification technologies, such as Shell Coal Gasification

Process (SCGP), General Electric (GE) gasifier (formerly Texaco), and ConocoPhillips

(E-GasTM) gasifier for O2-blown and Mitsubishi Heavy Industry (MHI) for air-blown

1 This term will be introduced later in this section.


entrained-flow type. The main characteristics of commonly used oxygen-blown and air-

blown entrained-flow gasification technologies are shown in Table 3.1.

Table 3.1. The main characteristics of various commercial gasifiers

Specification SCGP GE/Texaco E-GasTM MHI

Flow regime Entrained-flow Entrained-flow Entrained-flow Entrained-flow

Type of ash Slag Slag Slag Slag

Oxidant O2-blown O2-blown O2-blown Air-blown

Dry/slurry Dry-fed Slurry-fed Slurry-fed Dry-fed

Feed type PC PC PC PC

Pressurization Lock hopper Slurry pump Slurry pump Lock hopper

Number of stages Single Single Double Double

Slag removal

system

Lock-hopper Lock-hopper Continuous

pressure let-

down system

[41]

Lock-hopper

Flow direction Upward flow Downward flow Upward flow Upward flow

Boiler position Side-fired Top-fired Side-fired Side-fired

Quenching type Quenching with

recycle gas and

radiant cooler

Full water quench,

radiant cooler, and

radiant/convective

coolers

Two-stage

gasification

Two-stage

gasification

Reactor type Membrane-wall

[80]

Refractory-lined Refractory-lined Membrane-wall

Cold gas

efficiency

78-83% [80] 69-77% [85] 71-80% [85] 70-75% [85]

Carbon conversion Above 99% [80] Above 96% Above 99% [86] Above 99%

[76]

Availability targets 92%[87] 88-90% [83] 92% Not available

3.3.2.2. Gasification performance

Coal properties and characteristics such as ash content and reactivity are amongst the most

important parameters affecting the performance of gasifiers in IGCC application. The

effects of important coal properties on the performance of the gasification process are

briefly presented here. In addition, cold gas efficiency, which is an indicator of

gasification performance, is also introduced later.


3.3.2.2.1. Coal quality

There are various types of coal, and each has specific properties. Coal is typically

classified based on the content of fixed carbon and volatile matters. Table 3.2 shows the

four classes of coal with their characteristics and thermal properties [41].

Table 3.2. Coal classification

Class Volatile matter (wt%) Fixed carbon (wt%) HHV (MJ/kg)

Anthracite <8 >92 36-37

Bituminous 8-22 78-92 32-36

Sub-bituminous 22-27 73-78 28-32

Brown coal (lignite) 27-35 65-73 26-28

An advantage of entrained-flow gasification is its fuel flexibility. This type of gasifier

allows the choice of a wide range of feedstock with different prices, including low-rank

coals with lower prices. The main specifications of low-rank coals (e.g. lignite coals) are

typically high levels of ash, moisture, sulfur, chlorine and alkali metals as well as low ash

melting point [55]. It is estimated that 53% of global coal reserves consist of average and

low-rank coals, i.e. sub-bituminous and lignite [8]. Even though an entrained-flow gasifier

can process a wide range of feedstock [65, 78], the feedstock characteristics significantly

influence the gasification performance [56, 78]. The existing gasifiers show a substantial

increase in cost combined with a drastic reduction in performance operating on low-rank

feedstock, e.g. lignite coals [83]. Nevertheless, the utilization of such types of coals can

broaden the range of suppliers and consequently improve the security of the energy supply

[55].

The main parameters for selection of coal type in IGCC plants are ash content, slag

viscosity and coal reactivity. A low ash content coal is favorable for IGCC power plants

since it produces a lower fly ash and lower bottom slag that can result in a possible

plugging of exit pipes and downstream heat exchangers [78]. The slag viscosity directly

determines the operating conditions of the gasifier. Higher slag viscosity induces the

possibility of a blockage of the slagging system and also requires a higher gasification

temperature, which decreases the lifetime of the refractory materials. In order to have a

continuous slag tapping process, a viscosity less than 25 Pa.s (250 Poise) is required [41,

88]. The viscosity of the slag tends to be high at high concentrations of Al2O3 and SiO2.

Conversely, the viscosity has a tendency to be low if the CaO, MgO and FeO contents are

high [55, 88]. The slag viscosity needs to be reduced when it is higher than the


abovementioned critical value. Utilizing a fluxing agent (such as limestone) or mixing

with a coal which has a lower slag viscosity are the main solutions for lowering the

viscosity. Coal reactivity determines the amount of required oxidant agent for gasification.

The lower coal reactivity results in a higher injection of oxidant agent and consequently

lower gasifier performance. In summary, the best coal type for IGCC to reduce operation

difficulties and shutdowns appears to be one which contains low ash, has low slag

viscosity and high coal reactivity [74, 78].

The secondary parameters for coal selection are coal water and sulfur contents. Generally,

coal containing lower surface moisture would be beneficial in terms of lower drying cost

in dry-fed gasifiers and lower oxygen consumption in slurry-fed gasifiers [78]. A higher

sulfur content results in a higher loss of H2 content produced within the process, such as

H2S, and has a detrimental effect on electricity production.

3.3.2.2.2. Cold gas efficiency

One of the main parameters to determine gasifier performance is cold gas efficiency. This

parameter is an indication which shows how much of the energy input has been recovered

as chemical energy in syngas [78]. The cold gas efficiency is defined as:

ηcg = LHVsgQsg

LHVcimci (Eq. 3.2)

The cold gas efficiency of a single-stage slurry-fed entrained-flow gasifier is lower than

that for dry-fed gasifiers (refer to Table 3.1). A slurry-fed gasifier requires 20-25% more

O2 for vaporization compared to a dry-fed gasifier due to the higher water content

(because of slurry) [76]. Therefore, more carbon in coal is oxidized to CO2 in the slurry-

fed gasifier, which reduces the cold gas efficiency. The problem is even larger when the

coal rank is low. The higher moisture content of the coal is not useful for the slurry’s

transport properties and a large amount of water is still required for the slurry.

Consequently, the overall efficiency of the plant is reduced by an increase in the ASU size

and higher auxiliary power demand. This water content results in a higher H2/CO ratio

(details concerning the gasification’s CO-shift reaction are available in Paper III). On the

contrary, the dry-fed gasifier can handle a wide range of feedstock such as any type of

coal with a relatively lower effect on the produced syngas’ properties and cold gas

efficiency [80].


3.3.3. Syngas cleaning and conversion

Raw syngas produced in a gasifier contains many impurities such as particulate matters

(PM), heavy metals, undesirable gaseous components such as acid gases, etc. It also

contains a high amount of carbon monoxide, which needs to be converted to carbon

dioxide for CO2 capture application; hence, cleaning, conditioning and conversion of

syngas is required for its efficient use in IGCC applications.

3.3.3.1. Syngas cleaning

The cleaning of the syngas produced in the gasifier is unavoidable before its combustion

in a gas turbine to protect the GT and to keep the pollutant emissions below the

environmental restriction levels [89]. The cleaning process consists of the removal of ash

and particulates, as well as control of ammonia (NH3) and heavy metals (such as mercury,

arsenic, selenium, etc.). It should be mentioned that the separation of H2S and carbonyl

sulfide COS is excluded here and will be described later in Section 3.3.3.3 (Acid gas

removal).

Most of the coal ash is removed from the gasifier as slag in all entrained-flow gasification

technologies. The remaining ash in syngas is captured in the downstream equipment. The

clean-up configuration strongly depends on the gasification process. Ash and PM control

consists of cyclones, candle filters and a syngas scrubber in the case of the SCGP and the

E-GasTM gasifiers, while it consists of a water quench and a syngas scrubber for the GE

gasifier [90]. De-dusted syngas exiting the water wash scrubber is almost free of

chlorides, NH3, SO2 and PM. Water used for quenching purpose or scrubbing is then sent

to a sour water stripper for treatment. For mercury removal efficiency, the design target is

about 90-95% [90], although environmental targets (if available) for mercury control

differ, based on the local regulations [91, 92]. Mercury removal is typically performed via

an adsorption process. Sulfur-impregnated activated carbon is used as adsorbent and the

lifetime of the adsorption bed is up to two years. This process is performed prior to the

acid gas removal unit in power plants with and without CO2 capture.

Conventional syngas cleaning commonly consits of multi-stage pollutants’ separation.

Advanced syngas clean-up technologies are thus being developed to eliminate several

plant components for contaminants control [77]. Such clean-up processes will be


concisely presented in Section 3.3.3.5 (Advanced syngas cleaning and conversion), since

they simultaneously remove H2S in addition to other pollutants and convert syngas.

3.3.3.2. Water-gas shift reaction

The produced syngas from commercial gasification technologies for IGCC application

contains high amounts of CO (25–50%) [93]. In IGCC power plants with CO2 capture, the

water-gas shift (WGS) process is the first step in converting the gasifier product into a

high hydrogen content syngas. This process is a moderate exothermic reaction, which is

used to convert CO as a component of the syngas into CO2. This is carried out by shifting

the CO with steam over a catalyst bed (Reaction 3.1).

CO(g) + H2O(g)(44

KJ

mole)

↔ CO2(g) + H2(g) (Reaction 3.1)

The reaction is equilibrium limited, implying the dependency of CO conversion on

reaction temperature, which is thermodynamically favored at low temperatures. On the

other hand, WGS reaction is kinetically favored at high temperatures (higher catalyst

activity as well as faster reaction is achieved at higher temperatures). Therefore, this

reaction is typically designed in two sequential reactors, where the first reactor (operating

at a higher temperature) converts the bulk of CO and the second reactor (operating at a

lower temperature) increases the overall CO conversion [94, 95]. However, factors such

as desired CO2 capture efficiency, sulfur emission limit (will be described later), coal

quality, gasifier design, etc. change the number of reaction stages and process design [96].

The operating temperatures of each stage are determined by catalyst type used in the

reactors, the amount of steam injected to the syngas stream and heat integration with other

components. The temperature range is between 150 and 530 °C [96, 97].

The reactor can be located either upstream (sour shift) or downstream (sweet shift) of the

acid gas removal unit (Figure 3.6). The location depends on the type of catalysts used for

the reaction. Some catalysts such as Fe, Cr or Cu-based are poisoned by a small amount of

sulfur compounds (higher than a few ppm levels) in the syngas. Hence, such catalysts

should be utilized after separation of sulfur compounds [97]. In contrast, Co or Mo-based

catalysts have the advantage that the sulfur compounds do not need to be separated from

the syngas prior to the WGS unit [98]. It has to be borne in mind that such catalysts need a

minimum level of sulfur compounds to operate actively. Shift catalysts based on


molybdenum sulfide need a certain H2S concentration to stabilize the catalytic active

phase (higher than 100 ppm depending on the temperature level). The sulfur levels

required by catalysts may not be reached with low sulfur coals. Therefore, coal

characteristics are also a key element to be considered for efficient WGS design [99].

Fuel Raw

syngas

O2

Air

Slag

Gas

cleaningGasification

ASU

Stack

To atmosphere

AirGas turbine

HP IP/LP

Heat recovery steam generator

Compressed CO2

HT shift LT shift

H2S

removal

Syngas

Steam

High CO2 & H2 content

CO2

capture

WGS

SweetSour

Figure 3.6. Schematic configuration of the IGCC plant with sour or sweet WGS unit

In order to protect the catalytic bed from carbon deposit, to control the reaction

temperature, as well as to increase equilibrium conversion of CO to CO2, the WGS

reaction requires a large amount of steam (much larger than stoichiometric requirement)

[100]. Syngas produced in dry-fed gasifiers (e.g. SCGP and Siemens Fuel Gasification

(SFG) technologies) has lower water content and requires an injection of a considerable

amount of steam (mostly from the steam cycle) to ensure acceptable CO conversion. On

the contrary, syngas produced in slurry-fed gasifiers (e.g. GE gasifier) has higher water

content and requires lower supplementary steam injection. However, higher CO2 content

in the syngas produced in such gasifiers changes the equilibrium reaction direction to a

backward WGS reaction. Hence, it requires higher residence time for the reactor to reach

the targeted conversion of carbon monoxide.


For IGCC power plants with CO2 capture, a sour WGS (SWGS) reaction may be a better

option. This helps to avoid additional cooling of the syngas required by the conventional

AGR unit (refer to the next section) upstream of the WGS unit and then reheating to the

level required for the catalyst’s activation in the WGS unit. It is also beneficial in order to

postpone the water condensation that occurs during the conventional AGR process

downstream of the WGS unit, as the WGS unit requires the existence of a considerable

amount of steam.

Despite the extensive ongoing research into finding improved catalysts [101], innovative

WGS configuration has also been investigated in order to reach a higher technical

performance of the WGS unit in IGCC application. An advanced WGS reaction

configuration equipped with syngas splitting has been utilized to feed four WGS reactors

in a staged configuration with intermediate water and synthesis gas quenches. The

potential of such a configuration for steam reduction is significant (54%), while it is

moderate for a reduction in efficiency penalty (2.7%) compared to the conventional WGS

[102]. However, the increased number of reaction units as well as the amount of water

quench should be optimized to balance the steam reduction with the higher capital costs.

These higher capital costs compared to the conventional unit are not only associated to a

higher number of reaction units but to the overall larger volume caused by a lower

thermodynamic driving force for CO conversion [100].

3.3.3.3. Acid gas removal

In IGCC plants, the sulfur content of the coal is mainly converted to H2S and COS due to

the highly reducing conditions of the gasifier [89]. Such gaseous components can produce

acidic solutions after dissolving in water and hence, are corrosive under moist conditions.

The combustion process converts H2S and COS to sulfur oxides, which are precursors of

acid rain. Their emissions to the atmosphere are, thus, limited by stringent environmental

regulations. Acid gases must, therefore, be removed from the syngas prior to the gas

turbine to avoid GT damage and to comply with legislation [103].

The removal of acid gases from the gaseous streams has been widely practiced using the

gas-liquid scrubbing process. This process consists of three solvent-based methods

including physical, chemical and hybrid (physical/chemical) solvents. Though some of the

current IGCC plants (without CO2 capture) have utilized chemical solvents (mainly

amine-based solvents), physical solvents (e.g. Selexol or Rectisol) are the most preferred


choice for the IGCC application with CO2 capture [104]. The reasons are high partial

pressure of acid gases in the syngas, highly efficient sulfur removal process and moderate

operation costs offered by these solvents, and low desorption heat for solvent regeneration

[105-107]. Figure 3.7 schematically highlights the better performance of physical solvents

than chemical solvents at a higher partial pressure of acid gases (based on the data

available in [107]). As shown in Figure 3.7, the solubility of acid gases in a physical

solvent follows Henry’s law and increases linearly, unlike the chemical solvents which

plateau at a higher partial pressure of acid gases [45].

Figure 3.7. Schematic comparison between loading characteristics of chemical (monoethanolamine

(MEA)) and physical (Selexol) solvents

Different physical solvents for absorption processes have their own advantages and

disadvantages. In this regard, the following criteria should be considered for the selection

of a proper solvent [104, 107-109]:

High loading capacity for different acid gases and high thermal stability;

low vapor pressure for minimal solvent losses and low viscosity;

non-reactive as well as non-corrosive;

high availability with a reasonable price;

low degradation rates; and

low health, safety, and environmental impacts.

Solv

ent

load

ing

Partial pressure

Physical solvents Chemical solvents


Amongst several physical solvents, Selexol (dimethyl ethers of polyethylene glycol), has

been extensively employed for acid gas removal. Its main advantages are high H2S

solubility, low vapor pressure, wide operating conditions, chemical stability, non-toxicity

and biodegradable material [107]. The characteristics of Selexol solvent are presented in

Table 3.3, below [107, 108].

Table 3.3. Characteristics of Selexol

Gas Unit Value Remark

H2 solubility - a 0.047

CO solubility - a 0.10

CO2 solubility - a 3.63

COS solubility - a 8.46

H2S solubility - a 32.4

Chemical formula - CH3(CH2CH20)nCH3 3 ≤ n ≤ 9 Density kg/m3 1030 at 25 °C

Molecular weight g/mol 280

Vapor pressure mbar 9.7e-4 at 25 °C

Viscosity Pa.s 5.8e-3 at 25 °C

a Solubility ( gas volume

Selexol volume) at 25 °C and 1 atm.

According to Table 3.3, solubility of both H2S and CO2 is much greater than CO and H2,

which results in a limited co-absorption of such combustible gases. Hence, Selexol offers

a good match prior to the GT in the IGCC application. Selexol’s potential for H2S

removal is greater than that of CO2, since the solubility of H2S in Selexol is about nine

times higher than that of CO2. In IGCC plants with CO2 capture, where both H2S and CO2

should be removed, the Selexol process typically takes place in two successive and

typically independent absorption-regeneration stages, in which the H2S is first removed

from the shifted syngas and consequently the CO2 is separated in the second stage of

absorption. The process is similar in principle to what was presented for CO2 capture

using an absorption process in Chapter 2 (Technical background). The syngas enters from

the bottom of the first absorption column, where the H2S is removed by a counter-current

flow of the solvent. The H2S-rich solvent is then thermally regenerated in a stripper. The

regenerated solvent is cooled, pressurized and recycled back to the top of the H2S

absorber, while acid gases are sent to a sulfur recovery unit (SRU). The H2S-lean syngas

enters the second absorber for CO2 removal. Similar to the first stage, the CO2-rich

solvent exits the absorber bottom and then passes through a few flash drums in series.

Carbon dioxide is released from the physical solvent as a result of stepwise pressure


reduction, unlike the chemical solvents which need significant thermal energy input [107].

The CO2 released from flash drums goes to the compression unit, while the clean and

CO2-lean syngas is sent to the GT. The CO2-lean solvent (after the flash drums) is also

cooled, pressurized and recycled back to the absorption column.

In order to achieve higher sulfur removal (more than 99%) from the syngas in IGCC

plants, it is necessary to add a COS hydrolysis unit to convert COS to H2S in the case of

CO2 capture trip, according to Reaction 3.2 [104, 110, 111].

COS(g) + H2O(g)(33.6

KJ

mole)

↔ H2S(g) + CO2(g) (Reaction 3.2)

In the case of using a sour WGS reaction unit (IGCC with CO2 capture), COS hydrolysis

is directly carried out in the WGS unit, avoiding a dedicated reactor compared to the

IGCC plant without CO2 capture [112].

3.3.3.4. Sulfur recovery unit

The AGR process results in three product streams, i.e. the fuel gas to the GT, a CO2-rich

stream and an acid gas stream. The acid gas stream from the AGR unit cannot be directly

vented to the atmosphere, according to stringent environmental regulations [104]. A sulfur

recovery unit is, therefore, required to treat the acid gas stream and recover sulfur (with

more than 99% recovery) as a by-product. The conventional SRU typically is based on the

Claus process for oxidizing H2S, obtaining elemental sulfur. The Claus process

catalytically converts H2S to elemental sulfur by the following reactions:

H2S +32⁄ O2 → SO2 + H2O (Reaction 3.3)

2H2S + SO2 ↔ 32⁄ S2 + 2H2O (Reaction 3.4)

The Reaction (3.4), the Claus reaction, is equilibrium limited. The overall reaction is:

3H2S +32⁄ O2 ↔

32⁄ S2 + 3H2O (Reaction 3.5)

The oxygen required for the Claus combustion is supplied by the ASU without any major

penalty on the overall plant efficiency [113]. Since the Claus reaction is exothermic, HP


steam production usually follows the Claus furnace. Moreover, LP steam is raised in the

condenser downstream of the HP steam recovery section [104].

To reach more than 99.8% sulfur removal efficiency, the tail gas from the Claus plant

needs to be further cleaned-up, an exercise which is widely practiced using a Shell Claus

off-gas treating (SCOT) unit. The SCOT unit treats the Claus tail gas by employing a

dedicated absorption unit (typically amine-based) and recycles the resulting acid gas to

the AGR unit. The tail gas treating (TGT) can also be performed by recycling the Claus

tail gas to the AGR unit [104].

3.3.3.5. Advanced syngas cleaning and conversion

In general, advanced gas cleaning and conversion processes are under investigation to

enhance both the technical and the economic performance of IGCC plants with CO2

capture [65]. Most of the reaserch activities have focused on the development of reliable

adsorption, membrane, improved scrubbing, and hybrid technologies.

In the case of IGCC plants with CO2 capture, the syngas exiting the conventional gas

cleaning needs to be heated up to certain limits for downstream sour WGS reaction. It

requires cooling down again for H2S separation in the AGR unit, which typically operates

at near-ambient temperature. The clean syngas may be reheated before combustion in the

GT. These repeated heating and cooling processes cause the inherent energy losses and

have detrimental effects on the plant’s overall efficiency [99]. To perform the removal of

H2S and multi contaminants in fewer unit operations, and to avoid the penalties associated

with syngas cooling and heating, a warm (hot) gas cleaning process is being developed to

operate at high temperatures (250-700 °C). Such a cleaning method employs sorbents

(typically metallic type e.g. Zn-based) to remove H2S or alkali species [103]. Significant

capital cost redcution and efficiency improvement could be achieved by replacing the cold

gas clean-up systems with warm systems [77]. The use of warm gas cleaning may also

allow heat extraction from IGCC power plants that could be beneficial for combined heat

and power (CHP) application [114]. However, the low duarbility and thermal stability of

the sorbents increases the operation costs and reduces the avaialability of such processes

[42]. In addition, such technologies still require a considerable time frame to be

commercially developed for large-scale implementation in IGCC power plants [42, 99].


To reduce the penalty of the capture process, advanced technologies such as membrane

separation are also being developed. Membrane technology has attracted the attention of

the research community due to its process simplicity, which can separate different gas

components through a continuous process. Different kinds of membranes can selectively

separate either H2 or CO2. The combination of warm gas clean-up technology (~480 °C)

with CO2 separation by membrane technology is projected to reduce the cost of electricity

by 14% [77]. Membrane technology can also be integrated into the system in order to

enhance WGS reaction either by the permeation of CO2 (according to Figure 3.8) or H2

[18, 115].

Membrane

High pressure side

Sweep flow

Syngas

(CO, H2, CO2)

H2O

Permeate CO2

in sweep flow

CO2 CO2 CO2 CO2

Retentate

H2, H2O (CO, CO2)

Low pressure side

CO2 + H2CO + H2O

Catalyst particle

Figure 3.8. Operating principle of an enhanced WGS reactor by membrane technology

For scrubbing process in the AGR unit, research activities are foccused on the

improvement of the acid gases’ loading to achieve better techno-economic performance.

Solvents that could show a good performance for acid gases at higher temperatures are

highly required in order to avoid the cooling necessary for current scrubbing agents. Some

salty compounds such as ionic liquids (ILs), which are at the early stage of development,

could be suitable alternatives for the current physical/chemical solvents for CO2

absoprtion. They can opperate at high temperatures (up to 200 °C), which is a good match

for the warm gas clean-up process [116].

Another promising concept for pre-combustion CO2 capture is the sorption-enhanced

water-gas shift (SEWGS) process. Simultaneous removal of CO2 in the WGS reactor will

enhance the conversion of carbon monoxide [94]. This system offers a higher CO2 capture

rate, higher H2 recovery in the fuel, simultaneous separation of H2S with CO2 and avoids

the cooling required by conventional AGR and CO2 capture [113]. The process comprises

of multiple sorbents beds (containing WGS catalysts), operated in parallel, that adsorb


CO2 at high temperature and pressure and release it at lower pressure. The combination of

CO conversion and instantaneous CO2 removal enhances H2 production and thereby the

purity of the fuel feeding the GT combustor. A separate CO2 stream (mixed with H2S) can

be recovered from the sorbents by regenerating the bed. Regeneration is carried out by a

pressure swing, producing a low-pressure CO2-rich stream. The CO2 stream, which

contains certain amount of H2S, needs to be further treated for the removal of H2S from

CO2 for final compression and storage [113]. The COE for the IGCC plant using SEWGS

can be reduced by 4%, while the overall efficiency can be improved by 2-3% compared to

the conventional IGCC plants with solvent-scrubbing CO2 capture [117]. However,

similarly to other sorbent-based cleaning methods, practical issues such as handling and

regeneration of the solid sorbent materials need to be addressed by ongoing research [42].

3.3.4. CO2 compression and dehydration

Carbon dioxide captured at a power plant can be stored in depleted oil and gas reservoirs

and deep saline formation or utilized for enhanced oil and gas recovery [18]. The captured

CO2 can be transported by several means including ships, pipeline, railways or roads.

Amongst those, however, ships and pipelines are more cost-effective for the transportation

of substantial amounts of CO2, depending on the distance to storage sites [18]. In order to

provide an optimum condition for transportation of large amounts of CO2, it is necessary

to transform gaseous CO2 into a phase comprising less volume and more density, i.e. a

liquid, solid or supercritical state. For pipeline transportation, the suitable condition is in

the supercritical region, as shown in Figure 3.9 (data for triple and critical points are from

[118]). Being above supercritical pressure eliminates the risk for the two-phase flow

regime due to temperature variations along the pipeline [18]. Recompression stages are

commonly considered in order to keep the pressure over supercritical pressure and to

overcome the pressure drops whenever the length of CO2 pipeline is more than 150 km

[119]. For tank transportation (e.g. ship), the most economically feasible condition is to

keep the CO2 in the liquid state at about 7 bar and -50 °C [119, 120]. Irrespective of the

choice of transportation, CO2 compression has a negative impact on the plant’s technical

and economic performance. The loss of overall plant efficiency associated with CO2

compression is approximately 5 percentage points. Considering such a unit for an IGCC

plant with CO2 capture increases the capital costs and cost of electricity by approximately

10% [65].


LiquidSolidSupercritical

region

Vapor

Tc = 31.0 ºC

pc = 73.8 bar

Temperature, T (ºC)

Pre

ssu

re, p

(b

ar)

5.2

-56.6

Triple point

Critical point

Saturation line

Melting line

Figure 3.9. The schematic temperature-pressure diagram for CO2

There are several compression alternatives to reach the required pressure of the CO2 for

transportation/storage [121]. In reality, a process closer to isothermal compression, such

as that which occurs in compression with intercooling, is beneficial to reduce the

compression power demand [122]. Inter-cooled compressors offer smaller sized

compression units and hence reduce costs and increase overall plant efficiency by

appropriate heat integration with other sub-systems at higher costs [122]. A further

reduction in the demand for power to pressurize the CO2 could be accomplished by

eliminating the final stage of the inter-cooled compressor using a less power-, cost-

intensive pumping process [121]. Initial compression to the condition where the CO2 is

transformed to a liquid state is carried on by the intercooled compressor, while the pump

is utilized to reach the final pressure.

In addition to compression, CO2 needs to be treated for the removal of accompanying

water to prevent the risk of corrosion and the formation of gas hydrates in the


transportation pipeline [120]. In addition to water vapor, the CO2 stream from the AGR

unit of the IGCC plants with CO2 capture contains minor species such as N2, Ar, H2, CO

and traces of H2S [107]. All these impurities have a negative impact on the compression

power demand, although these effects are marginal due to their trace existence [123].

Dehydration can be accomplished using an absorption process, vapor-liquid separator

drums or an adsorption process [122]. Maximum allowable water content of the CO2

stream is a critical factor in order to select a suitable dehydration process [120]. Often, a

dehydration unit based on glycol solvents such as tri-ethylene glycol (TEG) is considered

to absorb water from the CO2 stream for IGCC application with CO2 capture [43]. It

should be mentioned that the saturated water content first decreases by the increased

pressure of the high-purity CO2 stream then increases again at pressures above 60 bar

[107]. Thus, the optimum pressure and location of the dehydration unit to remove water

content (i.e. the lowest saturated water content) is about 60 bar at 25 °C [124].

3.3.5. Gas turbine

Due to the continuous need for coal utilization in power generation, the development of

reliable, environmentally friendly and cost-competitive gas turbine technologies for

hydrogen-rich syngas combustion is highly essential. The performance of the GT varies

with changes in the properties of the fuel gas [65]. The behavior of the gas turbine

changes with the transformation from NG (as conventional fuel for the GT industry) to a

H2-rich syngas, which is a typical fuel in IGCC plants with CO2 capture. The current

section presents various operational challenges and effects of using syngas instead of NG

on the existing gas turbine.

3.3.5.1. Combustion process

The state-of-the-art combustion technology for NG operation is dry low NOx (DLN) pre-

mixed burners. Such burners principally work at lean condition by forcing more air than

stoichiometric in the primary combustion zone, which results in moderate flame

temperatures [125]. Unfortunately, the available pre-mixed technology could not comply

with flammability limits for H2-rich fuels, which are much larger than those for natural

gas [126]. Moreover, high hydrogen content syngas has higher adiabatic flame

temperature, higher flame speed, and higher flashback potential compared to NG,

complicating the use of a combustor that is designed using NG design criteria [60, 127].

The SOA combustion technology for burning H2-rich syngas (25-40 vol%) is the diffusion


flame burner [125]. Note that this value could be much higher in an IGCC plant with CO2

capture, depending on the performance of upstream operation units. In general, diffusion

flame burners produce considerably more NOx than the pre-mixed combustors for NG

combustion and this is exacerbated when burning high hydrogen content fuels which is

typical for IGCC power plants with CO2 capture [27, 127].

Stoichiometric adiabatic flame temperature is a representative indicator for NOx

formation in diffusion flame combustors [126]. In order to lower the flame temperature

(down to about 2300 K [125]) and, consequently, to minimize NOx formation (25-45

ppmvd @ 15% O2 [125]), hydrogen-rich syngas is normally mixed with a diluent gas such

as nitrogen [128]. There are several methods to control NOx emissions from diffusion

flame burners of gas turbines including:

Saturation with water [126], steam or N2 injection [60], and combination of

saturation, steam and N2 injection [128]; and

use of selective catalytic reduction (SCR) in the bottoming cycle [126].

Irrespective of the method selected for controlling NOx emissions, all strategies work on

the basis of lowering the adiabatic flame temperature [126]. Nitrogen dilution is generally

recognized as the most efficient method due to its availability in conventional IGCC

plants [60]. It results in reduction of water consumption, though it increases auxiliary

power requirements (for N2 compression) [66]. Steam injection or syngas saturation with

water causes a higher convective heat transfer coefficient between combustion products

(hot stream) and the expander blade materials due to the change in hot stream composition

compared to an undiluted case. Accordingly, the blade metal temperature will increase at

a given turbine inlet temperature (TIT), geometry and cooling flow, which results in faster

life consumption of the blades [125]. In order to keep the same blade metal temperature,

TIT is commonly de-rated (reduced) [129] or new geometry and design should be adopted

to increase cooling flows. In the case of using SCR in the HRSG unit, a highly efficient

upstream AGR process (COS+H2S < 20 ppmv) needs to be employed to prevent

ammonium sulfate from fouling due to the presence of SOx in the flue gas [104]. In

addition to the higher costs induced by the SCR technology, a larger HRSG is required for

such a process [125].

As mentioned earlier, N2 is typically used as diluent in conventional IGCC plants with

cryogenic ASU. In this regard, the presence of a large amount of N2 in the syngas derived


from an air-blown IGCC plant is advantageous to minimize N2 dilution [126]. The coal

feeding system into the gasifier also has some effects on the NOx formation. The required

steam for NOx control in IGCC plants with slurry-fed gasifiers (e.g. GE and E-GasTM) is

considerably lower than that for dry-fed gasifiers due to the greater water content of the

syngas in slurry systems [64].

3.3.5.2. Turbo-machinery

Syngas property significantly affects GT operation. Syngas combustion results in different

product composition and thermo-physical properties (such as heat transfer coefficients)

compared to NG combustion. The fuel change (from NG to syngas) leads to [125]:

Different expansion line (enthalpy drop) in the expander;

change in the hot gas flow rate at the expander inlet; and

different cooling flow required for expander blades.

As a consequence, there a new compressor design might be needed to match the new

turbine characteristics, or compressor re-design might be considered to provide different

cooling flows.

The isentropic enthalpy drop in the expander for a H2-rich syngas is higher than for NG.

This drop will be significantly increased by steam dilution or water saturation to the

minimum required level for NOx emissions. If the working fluid is assumed to be an ideal

gas, the isentropic enthalpy drop can be evaluated using the following equation:

∆ℎ𝑖𝑠 = ∫ 𝑐𝑝𝑇𝑖𝑇𝑜,𝑖𝑠

(𝑇)𝑑𝑇 = 𝑐��(𝑇𝑖 − 𝑇𝑜,𝑖𝑠) (Eq. 3.3)

According to Equation 3.3, isentropic enthalpy drop is a function of average 𝑐𝑝 and

temperature drop through the expansion. The 𝑐��is enhanced by fuel transformation from

NG to H2-rich syngas and increases even more in the case of steam or water dilution. The

temperature drop is influenced by the change in isentropic exponent (𝛾) according to

isentropic 𝑝 − 𝑇 relation. Assuming constant expander inlet pressure, inlet temperature

and outlet pressure, the temperature drop reduces by an increase of 𝑐�� and simultaneous

reduction in 𝛾. Consequently, turbine outlet temperature (TOT) is also increased, which

threatens the lifetime of the expander blades. TOT increase is intensified in the case of

water saturation or steam injection. In the case of N2 dilution, the change in isentropic


enthalpy drop from NG combustion remains almost constant with an increase in N2

dilution as the hot gas already contains a considerable amount of N2 from the combustion

air [125].

The heating value of the produced syngas in IGCC plants is lower than that of NG, a

commonly used fuel for GT design [62]. This results in a higher flow rate of the fuel gas

to the GT to reach the same order of TIT and thereby a similar efficiency level at a given

compressed air flow [130]. The flow rate of the hot gas stream into the expander further

increases by the dilution process (in the case of SOA combustion technology, i.e.

diffusion flame burners). This increase is exacerbated in the case of N2 dilution, which

requires more injection to lower the adiabatic flame temperature and thereby NOx

formation due to its lower 𝑐𝑝 value compared to steam [125]. Irrespective of dilution type

and use of undiluted syngas, increased fuel flow rate:

Affects the compressor/expander matching [126];

induces higher back pressure to the compressor [125]; and

reduces available surge margin [130].

An increase in pressure ratio adversely affects the expander blade wall temperature. The

mass flow of the cooling stream increases by pressure ratio due to the higher cooling flow

density. The enhanced density results in higher convective heat transfer coefficients for

both fluid and outer blade wall. The higher heat transfer coefficient of the cooling stream

could not compensate for the higher outer blade wall heat transfer coefficient, which

increases the blade wall temperature beyond its admissible level [125]. The lifetime of the

turbine materials will then be shorter than normal operation (NG operation). The cooling

flow temperature also rises by the higher pressure ratio, which results in less effective

cooling [130]. In the case of using an existing GT, which is originally designed for NG,

the following options are available to improve GT operation for syngas fuel.

Allowing the pressure to increase up to the minimum surge margin level or

adding one or more high pressure (rear) stages to the compressor in order to

increase the available surge margin [130] at the price of higher costs [127].

Keeping the existing compressor design while widening the swallowing capacity

of the expander without increasing the pressure ratio, although it results in

higher blade wall temperature [130].

Partially closing the compressor variable inlet guide vanes (VIGV), which can

compensate for part of the higher hot gas flow rate [125].


De-rating the TIT which has a negative effect on the performance of the GT.

The reduction of TIT can marginally diminish the problem of higher pressure

ratio and consequently surge margin [130].

Air bleeding from the GT compressor to the ASU to maintain the pressure ratio

increase [62]. As mentioned earlier, this option results in higher overall plant

efficiency but reduces the operational flexibility, more specifically during

transient conditions [63]. Note that the higher degree of air-side integration leads

to improved surge margin and reduced pressure ratio at a given TIT and amount

of diluent and vice versa [130]. Effects of lower integration degree on the blade

wall temperature are similar to that presented for higher hot gas flow and

pressure ratio and hence, are not repeated again.

3.3.5.3. Materials

The combustion of H2-rich syngas results in higher heat transfer to the hot section

materials. The other major material concern, applicable to any coal-derived syngas, is the

need to protect the gas turbine from the corrosive effects of sulfur compounds [131],

alkali metal salts [132], and fly ash deposition [133]. The existence of such compounds

coupled with high temperature media can boost hot corrosion of metallic alloys [132] and

results in extensive thermal barrier coating (TBC) spallation [133].

Advanced turbine aerodynamic and cooling schemes are, therefore, required to maintain

the lifetime of the hot path at existing gas turbines. Otherwise, advanced high temperature

low conductivity TBC materials and superalloys need to be incorporated into the expander

hot path for the combustion of syngas [127].

3.3.5.4. Commercial syngas-fueled gas turbine

The original equipment manufacturers (OEMs) simultaneously improve their GT

technology for NG operation and perform required developments to enable syngas

operation and thus the integration of GTs into IGCC plants [63]. There are many

commercially available heavy-duty GT models originally designed for NG operation with

different modifications (e.g. different burner design) for syngas application. Amongst

those are Siemens (E and F frames), GE (EB and FB models), and MHI (e.g. M701DA)

[58, 59, 63, 134]. Nearly all these models use diluted syngas (using water saturation, N2,

or steam injection), and all are equipped with diffusion flame burners. The general

specifications of different commercially available 50 Hz F-frame gas turbine models


suitable for syngas operation are shown in Table 3.4. Please note that available data are

based on NG operation.

Table 3.4. Main specifications of two commercial 50 Hz gas turbine models for syngas operation

Parameter Unit 9FB a [135] SGT5-4000F [136]

OEM - General Electric Siemens

TIT °C 1360 [126] 1265 b

COT °C 1454 [126] 1500 b

TOT °C 623 577

Pressure ratio (𝛽) - 19.7 [137] 18.2

Exhaust flow rate kg/s 745 692

Gross power output MW 338 292

Gross efficicency (𝜂𝑔𝑟𝑜𝑠𝑠) % 40.0+ 39.8

Power output (combined cycle) c MW 510 423 [138]

Heat rate c kJ/kWh 5894 6164 [138]

Net thermal plant efficiency (𝜂𝑡ℎ) d % 60.0+ 58.4 [138]

Number of compresssion stages - 14 15 e

Number of expansion stages - 4 4 a 2011 model. b According to personal comminucation.

c Value represents 1×1 combined cycle configuration. d Value is LHV basis and represents 1×1 configuration. e The modified SGT5-4000F has an additional compressor rear stage in order to accommodate

higher back-pressure caused by diluted syngas in the case of zero or low air-side integration

with ASU [63].

3.3.5.5. Advanced hydrogen turbine technology

One of the most important on-going research and development (R&D) programs is the

development of fuel flexible hydrogen turbine technology, which has great potential for

the further development of IGCC plants through improved thermal efficiency [127]. Most

recently, many R&D activities have focused on the development of low NOx gas turbine

technology for undiluted hydrogen-rich syngas operation [73]. A report by the U.S.

Department of Energy (DOE) confirms that significantly higher overall efficiency (1.3

HHV%) and lower specific plant costs (9%) can be achieved by the deployment of such

technology in IGCC plants with CO2 capture [72]. In addition, novel aerodynamic

designs, advanced cooling schemes, advanced TBC systems and superalloys are under

development to further enhance GT performance [127]. The use of advanced gas turbine

technologies operating at elevated firing temperatures and pressure ratios such as H-class

machines will also significantly improve the overall efficiency of IGCC plants with CO2


capture [65]. Utilizing such GT technologies (60+% efficiency for NG operation) will

tackle the increasing GHG emissions from another area, i.e. energy efficiency [64, 128].

3.3.6. Bottoming cycle

The gas turbine exhaust gas is used to produce steam in an HRSG for electricity

generation in steam turbines. The process is quite similar to that of the conventional

bottoming cycle in natural gas combined cycles, with few changes in terms of thermal

energy inputs and outputs. The bottoming cycles in existing IGCC plants are typically

based on a triple-pressure level design with reheat consisting of an HRSG, steam turbine

(ST), condenser, and associated auxiliary pumps. The HRSG section includes

economizers, evaporators, super-heaters, and re-heaters for the three pressure levels. The

HP steam turbine inlet conditions in the existing IGCC units are about 100-120 bar and

520-540 °C with 520-540 °C reheat inlet temperature for the intermediate pressure (IP)

stage [139].

The steam turbine power output changes significantly in IGCC plants compared to that in

conventional combined cycles due to the many interactions between HRSG and other sub-

systems. The primary thermal energy input to the HRSG is from the GT exhaust gas,

which enters at about 560-590 °C [139]. The other energy inputs are HP, IP, or LP steams

generated in the gasifier, syngas coolers and WGS unit, depending on the heat integration

scheme between different process units. The HRSG supplies the high and intermediate

pressure boiler feed water (BFW) used in the gasifier, syngas cooler’s water-gas shift

process, the IP steam used in the WGS and the LP steam used in the AGR unit (i.e. for the

solvent regeneration). In IGCC plants with capture, the ST power output decreases due to

the extraction of steam for the WGS reaction unit. Consequently, the WGS unit is

typically viewed as a burden on the steam cycle [96]. In addition to steam production and

consumption, the operation of the steam cycle is dependent on ambient temperature which

imposes a vacuum at the condenser and, therefore, controls the performance of the steam

turbine [43].

3.4. Current IGCC power plants status

Seven IGCC power plants have been operated on coal as main feedstock (refer to Table

3.5), but none has been equipped with a CO2 capture unit [27, 49, 79]. Although


operational experience from the current plants has proven the viability of IGCC

technology, the demonstration of a full-scale IGCC plant with integrated CO2 capture unit

is highly essential. Some of the European IGCC plants, even without CO2 capture, are

simply not economically viable under current electricity market conditions. Buggenum

IGCC plant has recently been decommissioned, and Puertollano plant is at risk of closure.

Therefore, further IGCC deployment is tightly connected with its competitiveness against

other power generation technologies. Important areas which have tremendous effects on

the economy of this technology, that should therefore be improved or developed, include

[27]:

Higher plant availability and reliability for all types of coals;

cheaper solutions e.g. quench gasification for low grade coals;

development of highly efficient multi-pollutant gas clean-up systems; and

development of gas turbine technology burning hydrogen-rich fuels.

In addition to the coal IGCC plants mentioned in Table 3.5, many IGCC plants with and

without CO2 capture have been in the evaluation, planning, and construction phases,

especially in the USA and China [140, 141]. However, only a few, such as Kemper

County (Mississippi, USA) and GreenGen (China), show significant progress due to the

sustainability of government incentives and supports [142, 143].


Table 3.5. Specification of the operating coal-based IGCC power plants

Name Buggenum

[27, 49]

Wabash River

[27, 49]

Vresova

[27]

Polk

County [27,

49]

Puertollano

[27, 49]

Nakoso

[27, 49]

Edwardsport

[144, 145]

Location The

Netherlands

Indiana, USA Czech

Republic

Florida,

USA

Spain Japan Indiana,

USA

Start 1994 1995 1996 1996 1998 2007 2013

Gasifier SCGP E-GasTM Lurgi (26

fixed-bed

gasifiers)

GE Prenflo MHI GE

Feed Dry Slurry Dry Slurry Dry Dry Slurry

Oxidant O2 O2 O2 O2 O2 Air O2

GT Siemens

V94.2

(SGT5-

2000E)

GE 7FA GE 9E GE 7FA Siemens

V94.3

(SGT5-

4000F)

MHI

M701DA

GE 7FB

Air-side

integration

Full Zero Zero Zero Full Partial Partial

Diluent

(NOx

control)

Saturation,

N2 dilution

Saturation

(>20 vol%)

[139]

Steam

injection

N2 dilution,

saturation

[66]

Saturation,

N2 dilution

Without

dilution,

with SCR

N2 dilution

Net output

(MWe)

253 262 350 250 300 250 618

Efficiency

(LHV%)

43.0 40.0 Not

available

36.7 42 42.0 a ~ 44.0 a

[146] a estimated value.

61

4. H2-IGCC power plant

The current chapter briefly presents the main objectives of the European co-financed Low

Emission Gas Turbine Technology for Hydrogen-rich Syngas (H2-IGCC) project, as well

as its multiple research areas together with its main outcomes. Furthermore, the selected

IGCC configuration with CO2 capture consisting of several sub-systems is briefly

described. This configuration represents a realistic and practical integration of various

state-of-the-art technologies for different components of the plant. Limitations which have

arisen from the selection of each technology and operating mode compared to other

alternatives are also presented. As the focus of the H2-IGCC project was on the

development of a combustor for burning undiluted high H2 content syngas fuels in gas

turbine technology, various challenges tackled by different sub-project groups are briefly

summarized. Finally, the methodology for the performance analysis of the selected IGCC

plant with CO2 capture is described. Different software tools used for thermodynamic

modeling, together with reasons for the selection of each tool as well as boundary

conditions of the entire cycle and the gas turbine, are then presented.

4.1. H2-IGCC project

As mentioned previously in Chapter 3, current GT technology (preliminary developed for

natural gas and used) in IGCC application with CO2 capture suffers from several

challenges. Amongst those are the wide variation of fuel composition compared to NG,

increased hot gas flow to the expander, increased heat transfer between the hot gas and

expander materials, high NOx emissions from diffusion flame burners, and high dilution

rate to control NOx emissions.

62 H2-IGCC power plant

In November 2009, the H2-IGCC project was started, aiming at the knowledge

development necessary to overcome the abovementioned drawbacks, while burning H2-

rich fuels. The overall objective was to provide and demonstrate technical solutions which

allow the use of SOA highly efficient, reliable GTs in the next generation of IGCC plants

after introducing CO2 capture. The goal was to enable the combustion of undiluted H2-

rich syngas with low NOx emissions and also to allow for high fuel flexibility by enabling

the burning of back-up fuels (e.g. NG) with limited adverse effects to reliability and

availability. Twenty-four partners including academia and manufacturers, as well as plant

operators from ten European countries, worked together to achieve the abovementioned

goals. The project was divided into four major research areas, namely, combustion,

materials, turbo-machinery and system analysis. Figure 4.11 shows different research

areas with their overlaps on a schematic configuration of the IGCC plant with CO2

capture.

Stack

To atmosphere

HP IP/LP


Coal Raw

syngas

O2

Air

Slag

Gas

cleaningGasification

ASU

Compressed CO2

SWGS,

H2S removal,

CO2 capture

Turbo-machinery

System analysis

Materials

Combustion

Figure 4.1. The structure of the H2-IGCC project

1 The GT image is courtesy of Siemens SGT5-4000F gas turbine.

H2-IGCC power plant 63

Different technical sub-projects (research areas) had various main objectives, as detailed

below [147]:

Combustion group aimed to develop and demonstrate a safe and low emission

pre-mixed combustion technology for undiluted H2-rich syngas.

Materials group aimed to develop and demonstrate improved materials with

advanced coatings able to protect base materials of the blades and combustor

against the potentially more aggressive temperature and composition of the

exhaust gas.

Turbo-machinery group aimed to provide required design for the

compressor/expander aerodynamics and cooling schemes to cope with changed

fluid properties of the hot gas.

System analysis group aimed to evaluate optimum IGCC plant configurations

and to establish guidelines for optimized full-scale integration. Moreover, a

detailed systems analysis needed to be performed to generate realistic techno-

economic results for IGCC plants with pre-combustion carbon capture.

As the main target of the project was to develop and demonstrate a reliable and low

emission combustion technology, great efforts have been dedicated to the GT block. Note

that the successful implementation of this project could only be realized by intensive

collaboration between project partners due to the cross-disciplinary nature of the project’s

tasks and objectives. The interactions between the system analysis group and other project

groups (please refer to Figure 4.1) can be summarized as follows:

Syngas composition and mass flow, total mass flow (cold/hot path), turbine inlet

temperature and pressure from the system analysis group to the combustion

group, necessary for successful experimental campaigns and burner designs;

total mass flow (cold/hot path), turbine inlet temperature and pressure from the

system analysis group to the materials group, required for the selection of

materials and coatings as well as testing of the blades;

syngas composition and mass flow, total mass flow (cold/hot path), turbine inlet

temperature and pressure from the system analysis group to the turbo-machinery

group, necessary for modifying the GT designs (compressor and expander

aerodynamics);

flue gas composition and nitrogen demand (if any) for dilution from the

combustion group to the system analysis group, which influenced the steam

cycle calculations;

flue gas temperature and mass flow from the turbo-machinery group to the

system analysis group, which influenced performance analysis of the steam

cycle; and


gas turbine characteristics (expander and compressor maps, cooling flows, TIT,

combustor outlet temperature) from the turbo-machinery group to the system

analysis group, required for thermodynamic modeling of the GT.

The importance of an appropriate sub-system selection and integration, as well as overall

system analysis, should be clearly highlighted. It should be underlined that every decision

made at the entire system level had some impacts on the component targeted by the H2-

IGCC project (i.e. the gas turbine) and vice versa. Amongst those decisions, but not

limited to them, are:

Employing the current SOA technologies1 with respect to both the gas turbine

and also the entire IGCC system;

selecting a proper degree of integration between GT and ASU to achieve higher

flexibility, availability, and operability of the plant; and

defining fuel flexibility targets considering both planned and sudden changes in

fuel composition due to trip of the carbon capture unit or a failure upstream of

the gas turbine.

4.2. System integration

The thermodynamic performance calculations required the establishment of a reference

IGCC plant with carbon capture. This was performed based on a comprehensive review of

the present IGCC technology as well as openly available data. The results of

thermodynamic simulations of the baseline case have been published in Paper I.

The configuration (and input data/settings) of the plant has then been improved,

incorporating more realistic performance data reflecting industrial experiences from the

operation of similar plants during the project’s development (for details see Paper II). The

major sub-systems and the way in which they were integrated into the cycle are presented

here. Further information can be found in Papers I-III. In addition, the current section

briefly reviews the pros and cons of such sub-systems in terms of the operability and

thermodynamic performance of the overall IGCC plant.

1 Most of improved technologies for different sub-systems (e.g. ITM, hot gas clean-up, etc.) are not

likely to be commercially available in the time frame for plants discussed within the H2-IGCC

project, i.e. 2020.


4.2.1. Cryogenic air separation unit

The ASU is the most power-demanding auxiliary unit in the IGCC plant, and the level of

its integration to other sub-systems has to be properly analyzed with respect to costs,

efficiency, operational flexibility and plant availability.

Operating experience from Buggenum IGCC plant by an industrial partner of the H2-

IGCC project (NUON/Vattenfall) confirmed that a fully-integrated GT-ASU solution

adversely affects the availability of the plant. Therefore, a stand-alone ASU was

considered for the H2-IGCC project. The advantage obtained by selecting no air-side

integration between the GT and the ASU is also driven by higher plant operability.

However, it should be noted that the overall plant efficiency increases with the degree of

integration due to the higher isentropic efficiency of the GT compressor [113]. Lower

efficiency of the non-integrated GT-ASU case could be balanced with the selection of an

inter-cooled MAC to achieve similar overall equivalent compression work compared to a

fully-integrated GT-ASU case. Furthermore, as there is no need for injection of diluent

gaseous nitrogen into the GT for the dry-low NOx combustion, heat integration between

the GT compressor bleed air and DGAN from the ASU is not an option in order to

enhance the overall plant efficiency. Using undiluted syngas in the GT has also resulted in

the selection of a low pressure ASU, where O2 and N2 are produced at near atmospheric

pressure, as there is no need to reduce the compression work required for injection of

DGAN into the GT.

Due to the high competitiveness within the oxygen production industry, compressors’

characteristics, performance data, and detailed cost of cryogenic air separation plants are

difficult to obtain. Consequently, the performance data for main air, pure gaseous

nitrogen, and gaseous oxygen compressors, as well as for a number of inter-cooling stages

for all ASU compressors, have been gathered from H2-IGCC industrial partners based on

currently available technologies (presented in Paper II). The purity of the final product of

the ASU (95 mol% for O2) reflects an economic choice, maintaining the balance between

higher capital expenditure and higher efficiency loss. Moreover, as the combustion

process in the GT uses air as the oxidant agent, additional N2 and Ar in the syngas

produced by the gasifier does not make any major difference compared to when higher

purity O2 is produced by the ASU.


4.2.2. Gasification

The gasification technology is based on the Shell Coal Gasification Process. Such a

technology was selected due to its highest cold gas efficiency and its operating pressure

level. A key parameter governing the overall plant pressure is the operating pressure of

the GT combustor. The pressure prior to the combustion chamber was fixed at about 30

bar to overcome the pressure loss over the fuel valves for pre-mixing of fuel and air in the

combustor. The pressure of the gasification block was then calculated and fixed at 45 bar,

considering all pressure losses from the gasifier to the combustion chamber and

eliminating any supplementary syngas compression. The conventional Shell gasifier had a

slightly lower pressure (~ 42 bar) at the time the gasification technology was selected (in

2010). However, the fast pace of technology improvement could result in higher operating

pressures (e.g. 45 bar) of dry-fed gasifiers in the period of 2015-2020, when the results of

the H2-IGCC project could be commercially demonstrated. The adoption of SCGP

technology was also justified by the availability of a validated gasification model

provided by a member of the consortium, Nuon/Vattenfall, who operated the Buggenum

IGCC plant. An assessment of the impact and behavior of various gasification

technologies fed by different coal types and qualities on the overall technical performance

of the IGCC plant with CO2 capture was investigated and has been presented in Paper III.

A relatively cheaper slurry-fed gasification technology could be an appropriate substitute

for the SCGP technology, more specifically when high quality coal reserves are available.

Nevertheless, dry-fed gasifiers can offer more stable performance, even when fed by low

quality coals or biomass.

4.2.3. Syngas conversion

A sour water-gas shift unit has been selected for modeling the IGCC cycle with CO2

capture. This type of shift reaction helps to avoid the additional cooling of the syngas

required by conventional AGR units and then reheating to the level required for the

catalyst’s activation in the SWGS unit. It is also beneficial in order to postpone the water

condensation, which occurs during the conventional AGR process downstream of the

SWGS unit, as the SWGS unit requires the existence of a considerable amount of steam. It

should be noted that the dry-feed characteristics of the Shell gasifier required the injection

of a considerable amount of steam, which adversely affects the steam turbine power


output. The selection of sour shift reaction was also motivated by industrial partners of the

project.

In order to increase the lifetime of the shift catalyst by eliminating the carbon deposition,

a large amount of steam injection, indicated by a high steam to CO ratio (i.e. 2.4 molar

basis), has been considered.

4.2.4. Acid gas removal

A double-stage physical absorption system using Selexol was selected for the H2S and

CO2 removal from the shifted syngas. The heat required for the regeneration of the solvent

from the acid gas has been provided from the low quality heat, which must be rejected

downstream of the SWGS before the conventional Selexol unit.

The CO2 capture target for simulations has been set to be 90%, as it was found to be an

optimal capture efficiency for IGCC power plants [65]. In order to reach this target, co-

absorption of CO2 with H2S should be minimized. This has been achieved by use of the

pre-loaded solvent in the AGR unit. However, using the pre-loaded solvent may have an

adverse effect on the H2S recovery through the decrease in temperature rise within the

absorber column [108]. Furthermore, the solubility data presented in Table 3.3 (see

Chapter 3) may be differentiated due to the higher interactions between polar compounds

such as CO2 and H2S in the pre-loaded solvent [104].

In the absorption process, a part of the combustible constituent of the syngas, i.e. H2 and

CO, are also co-absorbed by the rich solvent. Lowering the pressure to separate CO2 or

H2S from the rich solvent will result in a loss of the combustible gases. Therefore,

products of the first flash drums after H2S and CO2 absorbers are compressed and recycled

to the absorbers to minimize the CO and H2 slips. The high CO2/H2S ratio in the syngas

from the SWGS unit together with a requirement for 90% CO2 capture efficiency resulted

in the production of an unsuitable acid gas stream to the Claus plant due to increased co-

absorption of CO2. Therefore, an acid gas enrichment unit was considered in order to

reach a higher H2S content (> 35 mol%) of the acid gas stream.

H2S removed in the AGR section is sent to the sulfur recovery unit, which has not been

modeled in this work. However, the oxygen required for the Claus plant has been

considered for the calculation of the capital costs of the ASU. Furthermore, net steam


required for the SRU has been assumed to be zero, as the heat required to keep the sulfur

molten and to regenerate the SCOT solvent is balanced by the steam raised by H2S

combustion in the Claus plant, according to [113].

4.2.5. Gas turbine

The baseline GT design has been selected considering the best available gas turbine

technologies. Accordingly, a Siemens SGT5-4000F/Ansaldo Energia V94.3A gas turbine

was chosen, as the manufacturers are partners of the H2-IGCC project. Suitable values for

relevant parameters (e.g. for pressure ratio, gross power, etc.) have been selected, taking

the present SOA technology and the OEMs available data into consideration.

As mentioned in Section 4.2.2 (gasification), one of the most important interactions

between the overall IGCC system and the GT is the required fuel pressure at the GT fuel

valves. The inlet pressure of the fuel upstream of the combustor is dictated by the

compressor outlet pressure. Higher inlet pressure to the fuel valves compared to

compressor outlet pressure should be considered to compensate for a certain pressure loss

between the fuel valves and nozzles. The flame temperature and thereby NOx emissions

are principally controlled by premixing the fuel and air in dry low NOx burners. Such

burners are equipped with a certain number of swirlers to stabilize the flame and to create

the necessary turbulent conditions. This eventually results in higher pressure loss in pre-

mixed burners compared to diffusion flame burners. Therefore, a high pressure loss (~10

bar) through the fuel injection system has been considered for the H2-IGCC project.

Syngas can be preheated (up to 200-300 °C) in the IGCC plant prior to the GT

combustion to increase overall plant efficiency, exploiting available waste heat. The

selection of preheating temperature is a compromise between the thermodynamic benefits

at higher temperatures and the operational risks for handling hydrogen-rich, high

temperature syngas (compared to NG) as well as higher fuel system costs [126]. However,

lowering the risk for auto-ignition of H2-rich syngas, this alternative was considered

neither in simulation tasks nor in experimental tests within the H2-IGCC project.

As previously mentioned, for IGCC plants with CO2 capture, either syngas dilution (with

N2 or steam) or syngas saturation (with water) is often considered to control the NOx

emissions from the diffusion flame burners. However, as the goal of the project was to

develop a pre-mixed combustor for the combustion of “undiluted” hydrogen-rich syngas,


this strategy was not applicable. Once H2-rich syngas was considered as the GT fuel in the

existing GT (i.e. SGT5-4000F/Ansaldo Energia V94.3A) designed for NG operation, the

operating parameters and performance of the GT deviated from the original design.

Therefore, a full off-design analysis was performed in order to realistically simulate those

changes. An existing compressor model was improved using a characteristics map

provided within the H2-IGCC project. The turbine off-design operation was modeled

considering a constant swallowing capacity at choking condition, which is a reasonable

assumption for heavy duty gas turbines:

Swallowing capacity = Constant = ��𝑖√𝑇𝑖

𝜅 𝐴𝑖 𝑝𝑖 (Eq. 4.1)

where,

𝜅 = √𝛾

𝑅(2

𝛾+1)

𝛾+1

𝛾−1 (Eq. 4.2)

The sizing of the entire IGCC plant is governed by the gas turbine as it requires a specific

amount of fuel depending on the fuel composition. The operating condition of the GT has

been determined by matching the operating characteristics of the compressor and the

expander. Thus, if the gas flow rate, e.g. due to the change of syngas composition, varies

at the expander inlet, the operating condition of the GT adapts to this change. This could

result in a change of pressure ratio, even at similar firing temperatures.

When using H2-rich syngas, gas turbine power output increased due to the higher hot gas

flow expanding in the turbine at a certain TIT compared to the NG operation. It should be

highlighted that, in the case of using slurry-fed gasifiers (or water saturation in diffusion

flame burners), the potential for enhanced power output is higher. This is because of the

higher enthalpy drop through the expander due to the higher H2O content in the syngas

and consequently in the flue gas, according to [126].

As shown in Eq. 4.1, the syngas flow rate at the expander inlet is proportional to the

square root of the temperature. In the GT designed for NG in IGCC application, once the

fuel flow rate is increased due to the change in upstream operations (e.g. slip of CO2

capture unit) or transformation of fuel gas, the compressor stability and expander hot gas

path could be affected. Different alternatives to solve various problems incurred by the


introduction of H2-rich syngas instead of NG are reviewed in Paper IV. As mentioned

previously in Chapter 3, to maintain the GT operation’s stability and safety, TIT could be

de-rated (refer to Eq. 4.1) at the expense of lower GT efficiency.

The addition of one or more high pressure stages to the end of the compressor can resolve

the problem of reduced surge margin due to the higher mass flow of the H2-rich fuel

compared to NG [125]. The turbo-machinery group of the H2-IGCC project has

investigated this option, and the results of their calculation showed that the stable

operation of the compressor could be maintained by just adding one rear stage. The other

strategy adopted by the H2-IGCC project was to modify the turbine, i.e. re-staggering or

opening up the expander nozzle guide vanes (NGVs) in order to increase the swallowing

capacity of the expander. This strategy reflects the fact that industry prefers modifications

to the expander side as it has fewer stages and requires less effort compared to the

compressor. Nevertheless, extensive modifications to the expander should be avoided as

they will be costly and are unlikely to be accepted by the industry. Hence, only

modifications to the first stator of the turbine were followed as the main alternative by the

project.

Note that the modifications could be minor in the case of using an integrated GT-ASU

(air-side). The proper degree of integration could result in just a change of cooling scheme

and no modifications to the expander/compressor designs, as pointed out in [130].

Therefore, the opportunity to keep the NG-designed GT for operation on H2-rich syngas

has been lost by selecting a non-integrated GT-ASU to achieve simpler operation of the

plant, higher reliability and the possibility to run the GT only on NG. The zero integration

necessitated modifications to both expander hot gas path and cooling scheme to keep the

blade wall temperature under its prescribed level provided by the materials group (895 °C

for the 1st expander stator).

4.3. System performance analysis

One of the most important criteria for supporting any decision for investment in a

technology (here, the IGCC technology) is to analyze its performance both technically and

economically. The methodology for technical performance analysis is presented here,

while the method for economic evaluation will be given in the next chapter.


For the field of power generation, thermodynamic analyses by means of computer-aided

tools have become the most widely used practice. In this regard, thermodynamic

simulations by heat and mass balance programs are cost-effective and fast. In order to

obtain realistic performance indicators, different heat and mass balance programs have

been utilized by this project; these are briefly presented here.

4.3.1. Software tools

The entire IGCC power plant with CO2 capture (and also the NGCC with CO2 capture for

the techno-economic assessments) was modeled by simulation of several sub-systems

mentioned in Chapter 3. Each sub-system’s model and embedded characteristics represent

commercially available technologies, as each major component/sub-system of the IGCC

plant has been broadly utilized in industrial and power generation applications. Access to

the experienced utility owners and operators of similar plants in the H2-IGCC project

provided realistic performance characteristics for the relevant components.

As the main focus of the project was on the gas turbine, IPSEpro software tool, a

commercial heat and mass balance program by SimTech [148], was initially selected for

the modeling of the entire plant as well as the turbo-machinery parts. This choice was

made to reduce the number of software tools and thereby data exchanges between them. It

should be noted that most commercial heat and mass balance programs provide a limited

number of component models and relevant details. Furthermore, the necessary

modifications to the component models are often difficult as access to the source code of

the models and their underlying assumptions is restricted. The main feature of the

IPSEpro software is its component-by-component approach. This capability enables the

modeling of virtually any type of power plant by the integration of basic modules such as

expander, compressor, combustor, steam section, heat exchanger, etc. In addition, the

performance of each component (e.g. gas turbine, HRSG, steam turbine, and pumping

units) can be effectively predicted at their design and off-design points by means of

embedded component characteristics. Though the calculation process does not include the

dimensional design of any components, it is accurate enough to estimate system level

performance of the power block. Moreover, different parameters can be calibrated to

reproduce the performance of advanced gas turbines as realistically as possible. However,

this software suffers from some limitations, including upper limit of the operating

pressure of gaseous streams, as well as lack of enough chemical elements generated


during coal gasification. Moreover, simulation results for the acid gas removal showed a

considerable difference compared to the results from Aspen Plus, as well as results from

an industrial partner’s simulator (ProMax). This was justified by the differentiated

solubility data of Selexol solvent, which was only based on a certain operating

temperature and pressure and for non-, pre-loaded solvent in IPSEpro.

The mentioned limitations, as well as the specific capabilities of different tools to model

certain sub-systems, resulted in the use of a combination of different software tools,

including IPSEpro, for simulation tasks. In addition to IPSEpro, two main software tools

have been employed to establish the thermodynamic models of the power plant system

and thereby to analyze the thermodynamic performance in this thesis as follows:

Enssim: simulation tool developed by Enssim Software [149]; and

Aspen Plus: commercial process engineering software by Aspen Tech [150].

This approach has been selected to obtain reliable results and to utilize the possibility of

incorporating detailed component characteristics into relevant sub-system models. Even

though different software tools have been used for the simulation of different sub-systems,

proper matching between those tools enables simulation of the entire plant. Data exchange

between software tools was performed manually to find the optimal match, which was a

time-consuming process. A combination of the following simulation tools was used to

model the IGCC and NGCC power plants as follows:

Detailed modeling of the gasification block including various processes, e.g. coal

milling and drying (CMD), gasification, raw syngas cooling and scrubbing, was

performed using the Enssim software tool. Selection of this software was

justified by the fact that a validated gasification model against real plant

operational data was provided by Nuon/Vattenfall that could simulate the process

with a high level of accuracy. The validation results for the Shell gasifier are

available in Paper III. It should be noted that the interface between simulations

performed by the author of this thesis and the Enssim software was only at the

level of data and information exchange to modify the existing gasification model

and to simulate the entire IGCC system.

The air separation unit was modeled using Aspen Plus. The Peng-Robinson (PR)

equation-of-state (EOS) was selected as the properties’ method.

The sour water-gas shift reaction was modeled in Aspen Plus using PR EOS.

The acid gas removal unit was modeled in Aspen Plus. Two different equations-

of-state, i.e. Peng-Robinson and perturbed-chain statistical associating fluid


theory (PC-SAFT), were used for simulation. However, based on a

benchmarking study with one of the industrial partners, the simulation using PC-

SAFT equation-of-state was selected.

For IGCC plant without CO2 capture, the COS hydrolysis unit and H2S removal

(i.e. AGR unit) was modeled in Aspen Plus, using PR EOS and PC-SAFT EOS,

respectively.

The compression of captured CO2 and dehydration of CO2 stream were modeled

in Aspen Plus, using PR EOS and Schwarzentruber and Renon (SR polar)

equation-of-state, respectively.

The power block, including the GT, and the triple-pressure steam cycle were

modeled in IPSEpro.

The NGCC including the gas turbine, the triple-pressure steam cycle, and the

amine plant for CO2 removal were modeled using IPSEpro software.

O2 & N2

Steam

Coal milling

and drying

Gasification

Raw syngas

cooling

Syngas

scrubbing

Enssim

SteamWater

Raw syngas

WaterSWGS

ASU

H2S removal

and

CO2 capture

CO2

compression

and

dehydration

Aspen

H2-rich syngas

Gas turbine

HRSG

Steam

turbine

IPSEpro

Figure 4.2. Schematic figure of the interface and parameter exchange between different software

tools

As shown in Figure 4.2, the software tools had various interactions with each other,

including the amount of O2 and high pressure N2 from the ASU to the gasifier;

intermediate and high pressure BFW from the HRSG to the gasifier; the high,


intermediate, and low pressure BFW and IP steam from the HRSG to the SWGS; the

composition and operating parameters of the produced syngas from the gasification block

to the SWGS; the composition and the operating parameters of the syngas from the gas

cleaning unit to the GT; the required syngas flow by the GT to the upstream units; and

different BFW flows and steam flows to the HRSG.

The calculation of the syngas fuel composition was performed by Aspen Plus software. It

was then manually transferred into the IPSEpro gas turbine model. The input parameters

to IPSEpro include the composition of the syngas, any inputs or bleeds of steam or hot

water. Once the fuel flow was determined by the IPSEpro GT model, the backward

calculations were performed to update the coal flow, ASU duties, auxiliary compression

and pumping power demands, etc. Heat integration was finally performed between the

Aspen Plus and IPSEpro models, where heating and cooling streams was required. Given

the final values for heating and cooling inputs, the calculation of the steam turbine power

output and HRSG duties was carried out using the IPSEpro HRSG model.

4.3.2. Boundary conditions

In this section the basic assumptions for thermodynamic calculations are presented,

including the ambient conditions, characteristics of the fuels, and boundary conditions of

the gas turbine as the main focus of this project.

4.3.2.1. Ambient conditions

For gas turbine modeling within the H2-IGCC project (and this thesis), ISO standard was

used as a standard choice in the power industry, as shown in Table 4.1.

4.3.2.2. Feedstock properties

The design feedstock for simulation of the IGCC power plant is a mixture of various trade

coals on the world market (mainly Russia, but also USA, Colombia and South Africa).

The composition and thermal properties of the design coal (bituminous coal) and the

natural gas (used in NGCC simulation) are listed in Table 4.2.


Table 4.1. Ambient conditions and air composition

Parameter/ component Unit Value

Ambient air pressure bar 1.013

Ambient air temperature °C 15

Relative humidity % 60

Air composition

N2 wt% 75.10

O2 wt% 23.01

Ar wt% 1.21

H2O wt% 0.63

CO2 wt% 0.05

Table 4.2. Composition and thermal properties of bituminous coal and natural gas

Fuel type Parameter/ component Unit Value

Coal

Proximate analysis (dry basis)

Moisture wt% 10

Ash wt% 12.50

Volatile matter wt% 27.00

Fixed carbon wt% 50.50

LHV MJ/kg 25.10

HHV MJ/kg 26.20

Ultimate analysis (as received)

C wt% 64.10

H wt% 5.02

N wt% 0.70

O wt% 16.09

S wt% 1.50

Cl wt% 0.09

Main ash composition

SiO2 wt% 55.00

Al2O3 wt% 24.00

Fe2O3 wt% 5.50

CaO wt% 4.50

Natural gas

CH4 wt% 95.53

C3H8 wt% 4.02

CO2 wt% 0.40

N2 wt% 0.05

LHV MJ/kg 49.70


4.3.2.3. Gas turbine boundaries and performance

Different assumptions made for thermodynamic modeling of various sub-systems of the

selected IGCC cycle with CO2 capture have been presented in Papers I-III and hence are

not given here. However, the general assumptions for the thermodynamic modeling of the

gas turbine designed for H2-rich syngas operation, which have not been presented in the

previous papers, are listed in the following Table 4.3.

Table 4.3. Technical assumptions for the modeling of the gas turbine

Parameter Unit Value

Compressor

Air flow at the compressor inlet kg/s 685.2

Air flow at the compressor outlet kg/s 497.0

Pressure ratio - 18.2

Cooling flow 1st stator kg/s 45.7

Cooling flow 1st rotor kg/s 42.8

Cooling flow 2nd stator kg/s 31.5

Cooling flow 2nd rotor kg/s 24.5

Cooling flow 3rd stator kg/s 12.8

Cooling flow 3rd rotor kg/s 17.2

Low pressure cooling flow a kg/s 13.7

Compressor isentropic efficiency % 89.0

Mechanical efficiency % 88.7

Expander

Combustor outlet temperature ᵒC 1500

Turbine inlet temperature ᵒC 1265

Expander isentropic efficiency % 92.9

Expander total inlet pressure bar 17.9

Expander static outlet pressure bar 1.1

Mechanical efficiency % 88.7

Gas turbine

Exhaust flow rate kg/s 709

Exhaust temperature ᵒC 574 a This cooling flow shows a part of the cooling flow which does not go

through the expander and was assumed for cooling of the shaft and

bearings.


The compressor characteristics map, which relates the compressor mass flow, pressure

ratio, and isentropic efficiency, has been implemented in the compressor model. The

compression power demand was then calculated based on the operating points on the

compressor map. Figure 4.3 shows the generic characteristics map used for modeling the

GT compressor.

(a)

(b)

Figure 4.3. Generic compressor characteristics maps, (a) pressure ratio versus corrected mass flow

and (b) isentropic efficiency versus pressure ratio, for different IGV positions

The targeted lumped surface temperature provided by the materials group of the H2-IGCC

project is presented in Table 4.4. It should be mentioned that the equations for the

calculation of the metal temperature have not been incorporated into the GT model.

Hence, the provided data are presented here just to give an overview of the temperature

figures at the expander side, where only the first three stages are cooled with the cooling

flows.

8

10

12

14

16

18

20

22

85 90 95 100 105 110 115 120

Pre

ssure

ratio [

-]

Corrected mass flow [-]

IGV100%IGV 90%

IGV 80%

IGV 70%

IGV 60%

IGV 50%

90%

91%

92%

93%

94%

95%

8 10 12 14 16 18 20 22

Isentr

opic

effic

iency

(%)

Pressure ratio [-]


Table 4.4. Targeted surface lumped temperatures


1st stator °C 895

1st rotor °C 879

2nd stator °C 820

2nd rotor °C 807

3rd stator °C 787

3rd rotor °C 757

4th stator °C 772

4th rotor °C 771

The temperature increase for cooling air between extraction and injection due to the heat

loss from the combustion chamber has been set to be zero for the HP cooling flow (for 1st

stator and rotor) and 20 °C for the cooling flows to the 2nd and 3rd stators and rotors, as

shown in Figure 4.4.

Air

Compressor

VIGV 1-5 6-9 10-13 14-15 S2S1 R1 R2 S3 R3 S4 R4

Expander

Fuel

20 ºC temperature increase

No temperature

increase

Shaft cooling

Exhaust gas

Figure 4.4. Temperature increase for the cooling flows

The calculation of system performance was started using a change of NG to H2-rich

syngas, given the fact that the gas turbine model was able to calculate off-design behavior.

Nevertheless, during an extensive iterative process within the H2-IGCC project, the model

was improved to represent a gas turbine designed for operating on undiluted H2-rich

syngas. During the evolutionary calculation process, off-design operations were

considered to be limited only to the GT and not to the HRSG and steam turbine. This


could be justified as the gas turbine is extremely sensitive to its design, while the HRSG

and the steam turbine are more flexible and can be adapted to different operating

conditions.

During the modeling and experimental activities in the H2-IGCC project, the following

limits have been considered for continuous operation of the gas turbine and not during

start-up or shut-down.

SO2 emissions from the gas turbine were considered to be less than 10 ppmvd at

15% O2. This resulted in 99.9% removal of the sulfur content by the acid gas

removal unit.

NOx emissions from the gas turbine were considered to be less than 25 ppmvd at

15% O2.

CO emissions from the gas turbine were considered to be less than 10 ppmvd at

15% O2.

Unburned hydrocarbons (UHC) from the gas turbine have been considered to be

less than 10 ppmvd at 15% O2.

Ambient air

We

Fuel

Wc Wst

Upstream

sub-systems

Gas TurbineSteam

Turbine

Waux

Wp

Figure 4.5. The boundary for efficiency calculation of the entire IGCC plant

Figure 4.5 shows the boundary for efficiency of the whole IGCC plant, which is

calculated by the following Equation 4.3, considering the mechanical losses, generator

loss, and all auxiliaries.

𝜂𝑛𝑒𝑡 =(𝑊𝑒+𝑊𝑐) 𝜂𝑚 𝜂𝑒𝑙+𝑊𝑠𝑡 𝜂𝑚 𝜂𝑒𝑙+𝑊𝑝,𝐻𝑅𝑆𝐺+ 𝑊𝑎𝑢𝑥

��𝑐𝑖 . 𝐿𝐻𝑉𝑐𝑖× 100 (Eq. 4.3)

81

5. Economic evaluation

Widespread utilization of any power generation technology depends heavily on its

economic viability in addition to its technical benefits. The demonstration of a new power

plant’s competitive position, compared to other potential technologies, is therefore

essential to attract market attention.

In this regard, a comprehensive cost estimating methodology was adopted and adjusted to

reality, based on the feedback from industrial partners within the H2-IGCC project. In

addition, a techno-economic comparative study was performed to highlight the economic

feasibility as well as the advantages/disadvantages of the IGCC plant compared to other

competing fossil-fuel power plants. One important goal of this chapter is to provide a brief

description of different steps in order to perform the techno-economic evaluation of the

selected energy conversion systems.

5.1. Cost estimating methodology

A complete analysis of any electricity generating system is carried out by an evaluation of

current and future projected costs as well as its performance characteristics. Techno-

economic assessments play an important role in determining the competitiveness of a

selected technology against existing/reference technologies by evaluation of CAPEX and

OPEX in addition to the technical indicators. Such assessments are crucial to investigate

whether and under what circumstances investment in the selected technology is

economically viable. The economic evaluation consists of different stages. Estimations of

capital costs, operation and maintenance (O&M) costs, and fuel costs are necessary to

calculate the cost of electricity (COE).

82 Economic evaluation

Economic assessments are not definite and rely on the underlying assumptions as well as

on the choice of selected parameters. There are significant differences in the cost

estimating methods and basis of the calculations employed by various authors and

organizations performing economic assessments of fossil-fuel power plants with CO2

capture [151]. These inconsistencies complicate a fair comparison between the COEs for

different fossil-fuel power plants using different CO2 capture options from various

publishing sources. However, a cost comparison between different alternative systems

based on the same sort of assumptions and methodology is valid even in the presence of

uncertainty in absolute costs of the plant’s components.

Various publicly available reports by different organizations presented their recommended

approaches for cost estimation of power plants [73, 90, 152, 153]. Amongst these reports,

two publicly available reports have been initially selected as sources for equipment cost

data and reference cost estimating methodologies. These two reports are from the

European Benchmarking Task Force (EBTF) under the EU-FP7 CAESAR project [153]

and the National Energy Technology Laboratory (NETL) of the U.S. Department of

Energy (DOE) [90, 154]. The benefit of choosing these two studies from different

organizations was to highlight the effects of different costing methodologies (e.g. different

cost layers and assumptions) and various electricity market conditions (i.e. European and

American types) on the projected capital investments. The methodology used for Paper V

is based on the same methodology used in [90], while the methodology used for Paper VI

is based on what is presented in [153]. Although these reports share many common

features, the final cost estimating method selected for this work is based on the study

provided by the EBTF report [153]. This selection can be justified by the enhancement of

the exploitation of the results achieved during implementation of other European-funded

projects.

A set of assumptions has then been made in order to evaluate the economic indicators of

the selected cycle, i.e. the H2-IGCC plant with CO2 capture, on a consistent basis. The

economic viability of the selected cycle has been measured through the cost of electricity.

This cost indicator is a standard metric used in the assessment of project economics,

which represents the revenue per unit of electricity that must be met to reach breakeven

over the lifetime of a plant. In other words, it is the selling price of electricity that

generates a zero profit. For this purpose, the net present value (NPV) or discounted cash

flow (DCF) computations have been carried out in order to place expenditures that occur

Economic evaluation 83

in different time periods on a common value basis. In addition to cost estimation for the

selected H2-IGCC plant, other alternative fossil-fuel power plants, i.e. a super-critical

pulverized coal plant and a natural gas combined cycle, have been techno-economically

evaluated, and the results have been published in Papers V and VI. The main purpose of

these articles was to compare the technical and economic performance of the selected

power plants. Special emphasis was placed on constructing a set of realistic parameters,

ensuring that the comparison is performed in a consistent and fair way. In Paper VI, in

addition to COE, different aforementioned plants were economically compared using the

cost of CO2 avoided, which will be described later in this chapter. Moreover, economic

sensitivity analyses of the selected plants were investigated, considering the realistic

variation of the most uncertain parameters.

5.1.1. Costing scope

The performed techno-economic studies focus on the commercial installation of each

plant (or nth-of-a-kind technology) and do not cover the costs for the demonstration plants.

The following general considerations have also been taken into account in the techno-

economic studies performed:

The assessments carried out for this project were based on the reference years of

2012 and 2013.

The power plant boundary was defined as the total power plant facility within the

“fence line”. Moreover, site-specific considerations were not taken into account,

and cost estimations were based on a complete power plant on a generic

greenfield site.

Coal receiving and water supply systems were within the battery limit.

Costs associated with CO2 transport, storage, and monitoring were included in

the reported cost of electricity for Paper V, while only the CO2 compression cost

was included in Paper VI.

All performance data are based on nominal base-load operation under clean and

new conditions

Due to large uncertainties in the available cost data for some cost elements, they were

excluded from the assessments. Hence, any labor incentives; costs associated with plant’s

decommissioning; costs associated with the transmission networks, handling distribution


network and administration of supply; as well as all taxes (with the exception of property

taxes) were excluded from the assessments.

5.1.2. Capital costs

The following sub-sections firstly present the method and equations used for overall

capital costs assessment and then the equations used for costing any component/sub-

system of the selected IGCC plant.

5.1.2.1. Step-count costing method

The capital cost assessment for the IGCC plant was based on a bottom-up approach

(BUA). The BUA is the step-count exponential costing method using dominant

parameters or a combination of parameters derived from the mass and energy balance

simulation. The capital costs levels is illustrated in Figure 5.1, showing that there are three

main levels, i.e. total direct plant costs (TDPC), engineering, procurement and

construction costs (EPCC), and total plant costs (TPC).

Figure 5.1. Capital costs levels and their elements for a bottom-up costing approach

The following equations show the calculation method for total equipment costs (TEC) and

TDPC, respectively. Table 5.1 lists various sub-systems and plant components which

were systematically grouped according to their processes in the IGCC plant.


TEC = ∑ 𝐶𝑗𝑛𝑗=1 (Eq. 5.1)

TDPC = ∑ 𝐶𝑗𝑛𝑗=1 + ∑ 𝐼𝑗

𝑛𝑗=1 (Eq. 5.2)

Table 5.1. Major plant components of the IGCC plant with CO2 capture

# Plant components

1 Coal handling

2 Gasifier

3 Gas turbine

4 Steam turbine

5 Heat recovery steam generator

6 Low temperature heat recovery

7 Cooling

8 Air separation unit

9 Ash handling

10 Acid gas removal

11 Gas cleaning

12 Water treatment

13 Sour water-gas shift

14 Claus burner

15 SELEXOL plant

16 CO2 compression

The engineering, procurement and construction costs were calculated using the following

equation:

EPCC = TDPC + IC (Eq. 5.3)

The indirect costs (IC) were considered for the integration of the individual modules into

the entire plant, such as costs for piping/valves, civil works, instrumentations, and

electrical installations. The indirect costs can be simplified as a fixed percentage of the

TDPC. An example of the simplified indirect costs with relevant assumptions is shown in

Table 5.2.

The total plant costs are the sum of EPCC, owner costs (OC) and contingencies (process

and project contingencies), which is shown in the following equation:

TPC = EPCC + OC + Cproc,c + Cproj,c (Eq. 5.4)


Table 5.2. Breakdown of the indirect costs

Indirect costs % of TDPC

Yard improvement 1.5

Service facilities 2.0

Engineering/consultancy costs 4.5

Building 4.0

Miscellaneous 2.0

Total indirect costs 14.0

5.1.2.2. Capacity adjustment

The capital costs for plant components could be found in the open literature. However,

these data could not be used unless they were made consistent by using correction of size

and the reference year. Calculation of the equipment cost for a certain plant, based on

utilization of the cost data for different component sizes, could be performed using the

following equation:

C𝑗 = C𝑗,𝑟𝑒𝑓 (𝑆𝑗𝑆𝑗,𝑟𝑒𝑓⁄ )

𝑓

(Eq. 5.5)

The term (𝑓), cost scaling exponent, incorporates economies of scale in the equation and

indicates that the percentage change in cost is smaller than the percentage change in size

for each major component. The typical values of the scaling exponent for power utilities

vary between 0.6-0.7 [155].

5.1.2.3. Price fluctuations

The economic evaluation, based on the cost data found in the literature, should consider

the economic ups and downs (market fluctuations) from the date of the original cost data

to the current time. The cost adjustments are necessary since equipment cost estimates

correspond to a specific time. All the cost data used in the economic evaluation need to be

brought to the same reference year to reflect the market conditions for that specific year.

The adjustment for price fluctuations of equipment, materials, and labor over time could

be performed using a suitable cost index (CI) such as the Chemical Engineering Plant

Cost Index (CEPCI), the Marshall and Swift (M&S) cost index, etc. The cost index ratio

(IR) for a component is achieved by using the following equation:

𝐼𝑅 =𝐶𝐼𝑢𝑏𝑦

𝐶𝐼𝑜𝑏𝑦 (Eq. 5.6)


The updated cost for a component from its original base year could be then adjusted using

the following equation which is derived from Eq. 5.5 and Eq. 5.6.

C𝑗 = C𝑗,𝑟𝑒𝑓 (𝑆𝑗𝑆𝑗,𝑟𝑒𝑓⁄ )

𝑓

. 𝐼𝑅 (Eq. 5.7)

5.1.2.4. Currency exchange

In the economic calculations carried out, all figures extracted from the literature given in

different currencies (e.g. US$ or €) were recalculated to the desired currency using the

universal currency conversion XE rates [156].

5.1.3. Operation and maintenance (O&M) costs

The operations and maintenance costs are the costs associated with operating and

maintaining the power plants over their expected lifetimes. These costs usually include:

Operating labor;

maintenance (materials and labor);

consumables;

waste disposal and management; and

co-product/by-product credits (negative costs for any co/by-products sold can be

considered).

The abovementioned costs are classified in two categories: the fixed O&M costs, which

are independent of the plant output (products) such as labor cost, overheads, insurance,

and property taxes; the O&M costs that vary proportionally to the plant output are

variable costs. These costs include consumables (such as water, chemicals, solvent, and

catalysts) and waste disposal.

5.1.4. Fuel cost

The fuel cost, similar to variable O&M costs, is dependent on the plant output. Although

the coal cost, based on mine-mouth coal prices, has been stable over recent years, the

market price shows significant variation. The price for the bituminous coal was, therefore,

based on the market price. The fuel quantity, for the fuel cost calculation, was taken from


simulation results, and the corresponding cost was determined on the basis of yearly

consumption.

5.1.5. CO2 cost measures

A variety of measures are used in the literature to report the cost of CO2 capture and

storage systems for power plants. The most common measures include the cost of CO2

avoided and cost of CO2 captured [18].

The cost of CO2 avoided compares a plant with carbon capture with a reference plant

without capture and quantifies the cost of avoiding CO2 emissions for the provision of

electricity, which is defined as:

𝐶𝑜𝑠𝑡 𝑜𝑓 𝐶𝑂2 𝑎𝑣𝑜𝑖𝑑𝑒𝑑 [€/𝑡𝐶𝑂2] =𝐶𝑂𝐸𝑐𝑎𝑝𝑡𝑢𝑟𝑒−𝐶𝑂𝐸𝑟𝑒𝑓 [€/𝑀𝑊ℎ]

𝐶𝑂2𝑠,𝑟𝑒𝑓−𝐶𝑂2𝑠,𝑐𝑎𝑝𝑡𝑢𝑟𝑒 [𝑡𝐶𝑂2/𝑀𝑊ℎ] (Eq. 5.8)

where 𝐶𝑂2𝑠 is tonne of CO2 emissions to the atmosphere per MWh (based on the net

capacity of each power plant), and the subscripts “𝑐𝑎𝑝𝑡𝑢𝑟𝑒” and “𝑟𝑒𝑓” refer to plants

with capture and without capture (or reference plant), respectively. It should be

highlighted that the cost of CO2 avoided can be more comprehensive, incorporating the

costs associated with CO2 capture, transport and storage rather than only considering the

capture part. However, the boundary conditions for this study did not include transport

and storage steps, as these areas are different research fields that could not be covered by

the H2-IGCC project.

As shown in Eq. 5.8, calculation of the cost of CO2 avoided requires the definition of a

reference plant. This could be an identical/similar plant of the same type as the plant with

CO2 capture or a different plant type. The choice of an identical/similar reference plant is

typically made to quantify the cost of CO2 avoidance for a particular technology. Such a

choice is also made assuming that the investigated technology has a similar chance to be

built in future under a no-carbon-constraint scenario [157].

Another important cost measure is the cost of CO2 captured for a particular capture

technology in a specific type of power plant [18]. This measure is to quantify only the cost

of capturing CO2 and the economic viability of a CO2 capture system could be evaluated


using this measure compared to the CO2 market price as an industrial commodity [42].

The cost of CO2 captured for a power plant is defined as:

𝐶𝑜𝑠𝑡 𝑜𝑓 𝐶𝑂2 𝑐𝑎𝑝𝑡𝑢𝑟𝑒𝑑 [€/𝑡𝐶𝑂2] =𝐶𝑂𝐸𝑐𝑎𝑝𝑡𝑢𝑟𝑒−𝐶𝑂𝐸𝑟𝑒𝑓 [€/𝑀𝑊ℎ]

𝐶𝑂2𝑠,𝑐𝑎𝑝𝑡𝑢𝑟𝑒𝑑 [𝑡𝐶𝑂2/𝑀𝑊ℎ] (Eq. 5.9)

where the subscript “𝑐𝑎𝑝𝑡𝑢𝑟𝑒𝑑” shows the total mass of CO2 captured per net MWh for

the power plant with capture. It should be noted that, in this case, the reference plant is the

same type as the plant with capture unit.

The cost of CO2 captured is always lower than the cost of CO2 avoided, mainly because

the efficiency penalty caused by the CO2 capture unit means that more CO2 is captured

than avoided per net MWh generated (see also Figure 5.2). The values illustrated in

Figure 5.2 are based on the selected IGCC cycle with and without capture unit in Paper

VI.

0

100

200

300

400

500

600

700

800

Reference plant Plant with capture

CO

2p

rod

uce

d (k

g/M

Wh

)

CO2 emitted CO2 captured

CO

2 a

void

ed

0

10

20

30

40

50

60

Cost of CO2 captured Cost of CO2 avoided

€/t

CO

2

Figure 5.2. The relationship between the CO2 emitted, avoided and captured (left) and the cost of

CO2 captured and avoided (right)

5.2. Uncertainty in the economic results

Generally, some degree of uncertainty is expected in economic and technical performance

data for any technology. Additional uncertainties are commonly encountered in executing

a project which results in an increase in cost [158]. Uncertainty reflects lack of

knowledge/experience about the precise value(s) of one or more parameters affecting the


economic (or technical) performance of a technology [157]. In any case, the most mature

technologies show the smallest range of uncertainty compared to what is demonstrated by

the new technologies.

The IGCC technology is a complex energy conversion system. Moreover, operating

experience with IGCC power plants is limited compared to e.g. NGCC and SCPC plants.

In addition, currently there is no pre-combustion carbon capture system operating on a

commercial scale. As a consequence, there are substantial uncertainties associated with

cost data and technical performance for any economic assessment related to IGCC plants

with CO2 capture [65]. The most important uncertainty factors or sources of uncertainties

in the economic assessments carried out are summarized below:

The current and expected heat and electricity market conditions can have a major

impact on the capital costs of the plants, as well as financial assumptions such as

discount rate. With the current market condition for fossil-fuel power plants,

which is considered a volatile market, a low capacity factor can be considered

due to the increased share of renewable energy sources; a high discount rate may

be applied as investors try to gain a return on their investments as fast as they

can. In addition, assumptions about market prices for e.g. chemicals, catalysts,

etc. are uncertain.

Different technical assumptions such as process design assumptions and

parameters used for simulation such as equipment sizing parameters,

requirements for catalysts, chemicals and consumables are also sources of

uncertainty in the economic results.

As no existing full-scale carbon capture plant has been integrated into a power

plant on a commercial scale, any estimates have been made from scaling up from

prototypes or detailed bottom-up engineering estimates. Therefore, there is a

high degree of uncertainty in the cost data of the CO2 capture systems, including

capital costs and O&M costs, apart from technical performance such as the

additional energy consumption required for the capture unit.

There is uncertainty as to how the state of technology of all CO2 capture systems

(including pre-combustion) will be developed in the future, even though it is

expected that the costs of capture technologies will decrease in future [34].

However, this cost reduction is strongly connected to experience gained by more

demonstration plants and incremental technological improvements.


The IGCC technology is not currently a widely deployed technology so the cost

of IGCC plant itself (even without CO2 capture unit) is somewhat uncertain.

There is also the possibility that substantially cheaper technologies may become

commercially available (e.g. ITM for O2 production in IGCC cycles).

Given all these sources for uncertainties in economic (as well as technical) results,

performing a sensitivity analysis is a way to examine the effects of uncertainties (or

variability) in key parameters on the economic results. Therefore, such analyses were

carried out in order to disclose the effect of a plant’s capacity factor (or load factor) and

fuel price on the economic attributes of the selected IGCC plant.

93

6. Concluding remarks

The ever-increasing demand for electricity has been faced with a global concern, i.e.

increasing worldwide GHG emissions. Several potential pathways to mitigate these

emissions have been investigated during recent years. The most important ones, having

substantial impacts, are increase in the renewable energy share in the power mix, increase

in energy efficiency, and carbon capture and storage.

As one of the leading stakeholders, the European Union set a 20% reduction in GHG

emissions (compared to 1990 level) by 2020 and has included CCS in the portfolio of

technologies to meet this target. Accordingly, many R&D projects were financed by the

Directorate-General for Energy (European Commission) under the Sixth and Seventh

Framework Programmes including the Low Emission Gas Turbine Technology for

Hydrogen-rich Syngas (H2-IGCC) project in 2009. As mentioned earlier, this PhD study

has been carried out as a part of the research activities under the framework of the H2-

IGCC project. The following sub-chapters will summarize the main findings/conclusions

of this work and the scientific contributions of this study as well as offering some

suggestions for further investigations which can be accomplished by future research

activities.

6.1. Conclusions

The two important driving forces for defining, obtaining financial support for, and

implementing the H2-IGCC project were the continuing need to use coal as primary fuel

for the security of the energy supply and the requirements to curb CO2 emissions. The

electricity supply must be secured by utilizing various environmentally-friendly

technologies in every modern society. Undoubtedly, IGCC plants can contribute to the

94 Concluding remarks

security of the electricity supply under stringent emission regulations. However, it should

be clearly underlined that electricity must be supplied at an affordable cost so that the

global competitiveness of countries/regions is not affected in negative way. The techno-

economic results presented by this study showed that the three fossil-fuel power

generation alternatives without CO2 capture perform quite similarly with respect to the

cost of electricity. However, IGCC and SCPC are advantageous among plants without

capture based on underlying assumptions. The marginal difference in the cost of

electricity was within the level of uncertainties in the assessment of investment costs.

Therefore, other main drivers, apart from the cost of electricity, affect the selection of a

power generation technology including:

operational flexibility and availability;

compatibility with grid requirements assuming much higher share of renewable

energy sources in future energy mix and the risks for underperformance;

compatibility with utilities’ experience;

availability and diversity of equipment and technology suppliers;

various aspects relevant to health, safety and environment (HSE); and

potential for future improvements.

Given these criteria, opportunities for substantial economically attractive investments in

IGCC plants without CO2 capture remain questionable. Under current electricity market

conditions, new investments even in “standard” fossil-fuel power plants, i.e. pulverized

coal and NG simple and combined cycles (without CO2 capture), are foreseen to be

limited in Europe. This is mainly due to the increasing share of renewable energy sources

in the European power mix, which has had a tremendous impact on operating strategies

and the profitability of fossil-fuel power plants. Anyhow, intermittent RE requires

reliable-, fast balancing/backup power plants as well as large storage capacity. Hence, gas

turbine cycles fueled with NG, which are much faster, are superior compared to coal-

based plants (e.g. IGCC and SCPC). However, the reduction in the coal price in Europe,

mainly due to coal import from the USA as well as inexpensive costs for carbon

emissions, has recently resulted in the increased use of old coal plants (which have

already repaid their investment costs) in this region, compared to costly, high-efficiency

and low emission NGCC plants.

Concluding remarks 95

The limited or non-existent tendency of European power market might change from

standard fossil-fuel plants to IGCC plants in a carbon-constrained future when CCS

technologies will play an important role in the mitigation of GHG emissions. In this

context, the value of CO2 credits should be established with certainty, and appropriate

regulations on the required CO2 quality, storage access, monitoring of the storage sites,

etc. should be introduced. Even then, the IGCC technology with CO2 capture should

prove its competitive position against other low-carbon emissions technologies with

respect to issues like economic viability, operability, availability and reliability at a high

share of renewable energies in the global power mix. Assuming all these issues will be

resolved by policy changes and technological improvements, the findings of the current

thesis indicated that higher carbon prices should be set for the economic benefits of cycles

with capture compared to their reference plants (i.e. without capture).

Given all the aforementioned uncertainties and challenges facing the application of IGCC

technology, the precautionary principle suggests that doing nothing is not the best choice.

Indeed, it is quite clear that investigations such as those presented by this work are highly

necessary, especially when political and market conditions are being changed to force new

fossil plants to be built only with CO2 capture. Perhaps under these assumptions, and

given the need to keep the electricity supply versatile (energy diversity), IGCC application

will still be limited in some localities with abundant coal reserves such as China and the

USA.

In addition to aspects related to the aforementioned general view, such as current market

condition, economic viability, and the risk of CCS deployment, technological aspects of

the H2-IGCC project also need to be presented. Theses aspects include the application of

pre-mixed combustion for H2-rich syngas, knowledge built within the field of system

analysis, and techno-economic assessment.

It is questionable whether and under what condition the technology proposed in this thesis

for the combustion of H2-rich syngas can be employed in gas turbines specifically for

IGCC application in the near future. However, rapid changes in the global structure of

heat and electricity supply and demand have a tremendous impact on the application of

combustion technology developed within the H2-IGCC project. Likewise, via the

application of power-to-gas to reach the maximum utilization of renewable energy

sources, the hydrogen produced needs to be stored, perhaps in the existing NG pipelines.


This will assist the existing infrastructure (e.g. pipelines) to be maintained and the carbon

footprint to be reduced. Knowledge built in this project will then enable the use of pre-

mixed combustion technology for high H2 content natural gas in the gas turbines, which is

amongst the options to balance/back-up renewable energies.

With respect to the system analysis performed for this project, the knowledge built will be

helpful in taking a holistic approach to analyzing any other energy conversion systems. In

addition, the level of detail in every component of the system was appropriate to provide

the necessary boundary conditions and data for combustor design, gas turbine design and

techno-economic assessment. However, it should be highlighted that different types of

optimizations are still required for successful utilization of the IGCC technology, such as

heat integration, cost-benefit optimization, desired level of integration, etc.

The cost estimate presented in this work clearly confirmed the considerable negative

impact of applying CO2 capture systems in different power plants, as the total investment

and cost of electricity are much higher compared to the same plant type without CO2

capture. Accordingly, in order to make power plants with CO2 capture economically

attractive, the cost of emitting CO2 must be much higher than the current cost for CO2

allowances. Finally, it should be noted that the economic calculations performed here are

relevant based on data available today and underlying assumptions. Such uncertainties

should be kept in mind when interpreting the outcomes of this thesis.

6.2. Scientific contributions

The research work presented in this thesis places emphasis on the development of

technical solutions to allow the use of highly efficient gas turbine technology in the IGCC

plants with CO2 capture suitable for combusting undiluted H2-rich syngas. The two major

contributions of this study are:

1. System analysis and integration: system analysis using detailed validated models

provides highly valuable contributions concerning low cost, reliable results prior

to any piloting and demonstration activities. In this regard, system integration

alternatives with a high degree of complexity in both the IGCC plant and the

integrated pre-combustion carbon capture were evaluated. This has shed light on

the pros and cons of various alternatives, paving the way for future


implementation of the most efficient and practical system integration

alternatives.

2. Techno-economic model and assessments: the available techno-economic

approaches for the power plant were thoroughly reviewed, and the most suitable

method was selected. Accordingly, correction/adjustment of these methodologies

was carried out. Realistic cost and performance data supported by the industrial

partners of the project were then used to establish a solid base for a comparative

techno-economic study. The tool developed in the Microsoft Excel environment

provided the opportunity to update and modify any underlying assumptions and

enabled the economic evaluation of the IGCC plant with carbon capture as well

as its main competitors with a good level of accuracy.

The following list presents the other secondary contributions, which enhance the current

knowledge in this field:

i. An undiluted H2-rich syngas was used for the gas turbine modeling and

simulation, and the plant’s configuration was established and modified compared

to what is available in the literature.

ii. A non-integrated ASU-GT was selected to provide more availability and

flexibility to the operation of the IGCC plant. The plant’s overall performance

data could be marginally better in more integrated layouts but at the expense of

additional costs as well as less availability.

iii. Different gasification technologies have been investigated and integrated into the

selected IGCC configuration in order to explore the most appropriate option for

the application of pre-combustion CO2 capture in IGCC plants.

iv. Fuel flexibility targets in the gas turbine, with respect to fuel change due to slip

of CO2 capture unit, could not be accomplished using an identical combustor

designed for H2-rich syngas. This was mainly due to the large difference between

thermal properties of the H2-rich syngas and the syngas produced in the non-

capture IGCC plant.

v. The use of existing gas turbine technology, which is designed for NG operation,

would not be appropriate for handling H2-rich syngas. In this regard, a new gas

turbine was designed by other partners, involving some modifications, mainly in

the expander. Accordingly, the boundary conditions generated were used to

update the GT model and the overall IGCC plant.


6.3. Suggestions for further research

The following topics from different perspectives, i.e. a holistic view on energy conversion

systems to a detailed technological level, are considered by the author as an appropriate

continuation in this field and thus recommended for further research:

In the context of fossil-fuel energy conversion systems

vi. An investigation into the operating strategies of newly built or existing fossil-fuel

power plants under current market conditions is highly essential. Therefore, a

techno-economic study on existing fossil-based technologies for power

generation could be performed, defining different scenarios for increasing the

share of renewable energies and the need for fossil-fuel plants as a back-

up/balancing option. The major difference from the underlying assumptions

made for the current study would then be operating at part load rather than at

base load. The cyclic operation of the fossil-fuel power plants and its effects on

maintenance costs and lifetime consumption of different parts could be

incorporated to improve such an analysis.

In the context of system integration and analysis of the IGCC power plants

vii. In order to achieve better performance indicators of the IGCC plant, alternative

technologies listed in this thesis, such as ITM for air separation or SEWGS for

shift reaction and CO2 capture, could be integrated into the cycle. However, the

efficiency improvements should be evaluated against the economic implications

and operational challenges. It should be highlighted that different types of

optimizations, such as heat integration, cost-benefit optimization, and desired

level of integration, are required to make the IGCC technology ready for future

application.

viii. In order to have appropriate control over the simulation and modeling of such an

integrated and complex energy conversion system (i.e. IGCC system with CO2

capture), integrating software tools could be beneficial. For this purpose, it could

be an option to generate dynamic link library files, assuming that all software

tools used for this study are available. This option provides all the benefits which

could be gained by using each and every one of the previously mentioned

software tools. In the case of performing a simple techno-economic analysis, it


would be beneficial to simulate the whole system in e.g. IPSEpro or ASPEN

Plus, assuming the level of uncertainties in the cost assessments.

In the context of hydrogen-rich fueled gas turbine

The dynamic behavior and off-design conditions of the gas turbine when it is fed by a

hydrogen-rich syngas need to be investigated. Off-design modeling of such gas turbines

will be very useful, especially when the gas turbine technology is used as a back-up or

balancing power option for renewable energy sources. Power-to-gas technologies might

be considered for storing a part of intermittent RE and then high hydrogen content NG

might be used as a fuel for GTs, perhaps not at the base load condition.

101

7. Summary of appended papers

This chapter briefly presents the main findings of the papers appended to this thesis.

These papers are mainly related to the establishment of the baseline IGCC plant for the

purpose of system analysis; an investigation of the effects of coal quality and gasification

process type on the overall performance of the selected IGCC plant; a study of the effects

of fuel flexibility on the performance of the selected gas turbine; and techno-economic

comparatives studies on different fossil-fuel power plants including the selected IGCC

plant.

Paper I Development of H2-rich syngas fuelled GT for future IGCC power plants –

Establishment of a baseline, Presented at ASME Turbo Expo 2011, GT2011-45701,

Vancouver, Canada, June 2011.

This paper presents the establishment of two baseline IGCC power plants, i.e. with and

without pre-combustion CO2 capture. For this purpose, different sub-systems including

gas cleaning, gas turbine, steam turbine, heat recovery steam generator along with the

inputs from the industrial partners Vattenfall/Nuon and E.ON were integrated. The gas

turbine used for this study is based on Ansaldo Energia 94.3A without any dilution of the

syngas. The main goal of this study was to provide a baseline for further investigations

incorporating the necessary changes/modifications related to the gas turbine during the

lifetime of the H2-IGCC project. The secondary objective was to provide the potential of

burning undiluted H2-rich syngas and its effects on enhancement of the efficiency of the

IGCC power plants with CO2 capture.

102 Summary of appended papers

The analysis shows that the combustion of H2-rich syngas has the potential for increasing

the overall IGCC efficiency compared to data available in the literature for IGCC plants

with diluted syngas and CO2 capture. The overall efficiencies of the plants are 37.4% and

47.2% (LHV basis) respectively for the IGCC plant with CO2 capture and for non-capture

IGCC. The difference between two configurations, IGCC with and without CO2 capture,

results in two completely different syngas compositions. Preliminary results of this study

show that combustion of undiluted H2-rich syngas does not impose any significant effects

on the gas turbine, at least from a system perspective. However, the large change in fuel

flow in the case of non-capture IGCC plant generates some challenges for both the

combustion process and the turbo-machinery.

Paper II An EU initiative for future generation of IGCC power plants using hydrogen-

rich syngas: Simulation results for the baseline configuration, Applied Energy, Vol. 99,

pages 280-290, June 2012.

This paper is in continuation of Paper I to investigate the use of undiluted H2-rich syngas

in the IGCC plant with CO2 capture. However, simulation of the gas cleaning part of the

IGCC plant including the acid gas removal unit and the CO2 capture system was

performed using ASPEN Plus, unlike Paper I which was in IPSEpro. The main reason for

this was the specific capabilities of ASPEN Plus to simulate gas cleaning processes.

Moreover, additional plant’s components were integrated into the system to provide more

comprehensive and practical plant layout.

The paper presents a detailed thermodynamic model of the baseline IGCC plant with and

without CO2 capture. Realistic performance indicators verified by the operators of

similar/relevant plants were used, as compared to Paper I, which was mainly based on

data available in the literature. In addition to changes in performance indicators of some

plant’s components, some information on the GT provided by other partners was

incorporated into the GT model.

Results revealed that the effects of these changes/modifications on the model presented in

Paper I were negative in terms of the overall plant efficiency. The estimated overall

efficiency of the IGCC power plant without carbon capture is 46.3%, while it is 36.3% for

the plant with carbon capture, somewhat lower than the results presented in Paper I. The

Summary of appended papers 103

results confirm the fact that a significant penalty on efficiency (21.6% relative) is

associated with the capture of CO2.

Through comparison with other published studies, more integration of sub-systems

indicated some potential for better efficiency, although probably at the expense of lower

reliability. Using undiluted syngas in the GT significantly improves GT power. However,

some challenges related to the unstable operating condition of the GT combustor and

compressor, as well as reduced lifetime of the blades of the existing gas turbines when

using undiluted H2-rich syngas, should be addressed by future studies.

Paper III Estimation of performance variation of future generation IGCC with coal

quality and gasification process – Simulation results of EU H2-IGCC project, Applied

Energy, Vol. 113, pages 452-462, August 2013.

This paper presents the effects of gasifier type and coal quality on the overall performance

of the baseline configuration of the IGCC plant. In this regard, four commercially

available gasifiers from Shell, GE, Siemens, and ConocoPhillips have been considered for

this comparative study. The effects of three different types of coals on these gasifiers, as

well as on the overall performance of the IGCC plant, have been investigated. Utilizing

validated models against existing plant data for simulation of gasification block resulted

in more reliable results.

The results confirm that the coal quality considerably influences the cold gas efficiency

for slurry-fed gasifiers, while dry-fed gasifiers are relatively insensitive to the quality of

the input coal. Amongst slurry-fed gasifiers, the coal quality has the greatest impact on the

performance of the GE gasifier. The cold gas efficiency of the GE gasifier gasifying

lignite coal is 29% lower than gasifying bituminous coal. It is also shown that dry-fed

gasifiers are advantageous compared to slurry-fed types with respect to constant quality of

produced syngas even when low-rank coal is gasified. Based on the findings of this paper,

slurry-fed gasifiers investigated in this study, i.e. GE and ConocoPhillips, are suitable for

bituminous and sub-bituminous coals, while dry-fed gasifiers, i.e. Shell and Siemens,

show a relatively constant behavior for a wider range of coal quality.


The higher water content of the produced syngas from slurry-fed gasifiers results in an

enhanced ST power output due to reduction of the steam extraction from the steam cycle

for the water-gas shift reaction. However, this power increase cannot compensate for the

increase of ASU power demand and results in lower system efficiency for low-rank coal.

Paper IV Fuel change effects on the gas turbine performance in IGCC application,

Presented at 13th International Conference on Clean Energy (ICEE-2014), Istanbul,

Turkey, June 2014.

The effect of fuel change (i.e. from NG to H2-rich syngas and clean syngas) for the

selected GT is reported in this paper. This study focused on the operation of the gas

turbine as a stand-alone unit. The results of this paper proved the preliminary findings of

Paper I, showing that operation on undiluted H2-rich fuel (syngas produced in the IGCC

plant with CO2 capture) is feasible. However, a reduced surge margin should be accepted

without significant changes made to the gas turbine compared to the NG-fired engine. It

should be noted that the challenges concerning pre-mixed combustion of the H2-rich fuel

and different heat transfer rate to the expander materials when operated with H2-rich fuel

are not within the scope of this study.

The GT operation on clean syngas (i.e. syngas produced in the IGCC plant without CO2

capture) results in a significantly low surge margin and high turbine outlet temperature,

which needs different operating conditions and/or engine modification options to be

considered. When operating with a fuel with low calorific value, such as clean syngas,

expected operational hours are very important for the selection of appropriate operating

conditions or modification options. Although several modification options as well as

operating strategies have been suggested in this paper with regard to clean syngas

operation, reduced efficiency and compressor stability can be tolerated for limited

operational hours with clean syngas.

The results revealed that the effect of the altered VIGV angle on maintaining a reasonable

surge margin is not significant for the selected GT. In order to have a minor modification

of the GT compared to the design case engine for clean syngas operation, decreasing the

TIT and keeping the TOT similar to the reference case (NG-fired GT) with fully open

VIGV is a plausible option. However, results show a significant reduction of efficiency


and power output. Concluding this paper, using clean syngas requires major modifications

on the GT, including additional compressor stages, air bleed from compressor outlet, and

expander re-staggering, which resulted in putting this option (i.e. operation on the clean

syngas) aside within the H2-IGCC project.

Paper V Techno-economic evaluation of an IGCC power plant with carbon capture,

Presented at ASME Turbo Expo 2013, GT2013-95486, San Antonio, Texas, USA, June

2013.

This paper presents a techno-economic analysis for the selected IGCC plant configuration

with CO2 capture using the cost data and methodology of the U.S. Department of Energy.

The main objective was to generate a database using publicly available literature to

calculate the COE for the IGCC plant. The secondary objective was to compare the COE

for the IGCC plant with other fossil fuel competing technologies, i.e. NGCC and SCPC

plants, all with CO2 capture system. In this paper, the methodology used for the economic

evaluation of the plant, as well as relevant assumptions, calculation methods, and

economic figures are described.

The COE for the IGCC plant with CO2 capture is projected to be 160 US$/MWh. It

should be noted that all economic results are strongly dependent on presented

assumptions. Therefore, a sensitivity analysis was also carried out, showing that the most

influential parameter amongst selected parameters on the COE is the capacity factor. The

fuel price was the second ranked parameter. As the selected IGCC plant is considered

with CO2 capture, most of the CO2 produced is actually captured. Moreover, the costs for

CO2 allowances are very low. Therefore, the effect of CO2 allowances’ costs on the COE

is negligible. Finally, a comparative study was carried out to highlight the cost difference

between various power generation technologies, i.e. IGCC, SCPC, and NGCC plants with

CCS. The total overnight costs for IGCC, SCPC, and NGCC with CO2 capture are

estimated at 4677, 4065, and 1669 US$/kW, respectively.

The results revealed that the investment cost in the IGCC plant is projected to be more

than double that for the NGCC plant. However, other aspects such as the security of the

energy supply may encourage investors to select IGCC plants. Moreover, it is shown that

with the higher capacity factor and CO2 allowances’ cost, which is plausible in the coming


years, the IGCC plant could attract more investments compared to the SCPC plant.

Furthermore, income from poly-generation applications might also improve the economic

viability of future IGCC plants.

Paper VI Techno-economic assessment of fossil fuel power plants with CO2 capture ‒

Results of EU H2-IGCC project, International Journal of Hydrogen Energy, Vol. 39,

pages 16771-16784, September 2014.

In this paper the thermodynamic performance indicators of various power plants,

including IGCC, advanced supercritical pulverized coal, and natural gas combined cycle

power plants are presented. The technical indicators of the selected IGCC plant and

NGCC with and without CO2 capture unit are based on the simulations carried out during

the lifetime of the H2-IGCC project. These indicators for the SCPC were adopted from

literature.

Results confirm that the NGCC is the most efficient plant, while the advanced SCPC plant

is the least efficient plant amongst non-capture cases. This trend is similar for the plants

with capture unit. The relative efficiency penalties associated with the capture deployment

(compared to the identical plant with CO2 capture) are 24%, 27%, and 16% for the

selected IGCC, advanced SCPC, and NGCC plants, respectively.

In this article, a comparative study was also conducted, comparing the COE and the cost

of CO2 avoided for the mentioned fossil-based power plants. The economic performance

indicators of each plant were estimated using the model developed in the Microsoft. Excel

environment. It is very important to take into account that such a techno-economic

analysis cannot provide an absolute result, since the cost data and assumptions are

uncertain by nature.

The COE for the IGCC plant with and without capture is 91 and 59 €/MWh, respectively.

The COE for the advanced SCPC is 96 and 59 €/MWh for the capture and non-capture

cases, respectively. The COE for the NGCC with and without capture is 61 and 91

€/MWh, respectively. The results show that the least capital-intensive plant is the NGCC

plant without CO2 capture. However, the high fuel costs for this plant decrease the gap

between the COE for this plant compared to that for the other plants. The COE for the


NGCC technology was the most sensitive to changes in the fuel price amongst other

COEs for different technologies. However, the COE for the NGCC technology was also

the least sensitive to variations of the plant’s capacity factor. The estimated costs of CO2

avoided for the IGCC, SCPC, and NGCC technologies are 51, 57, 99 (€/t CO2 avoided).

Results highlighted that, based purely on the COE for different plants, it cannot be

concluded which technology is better and more cost-effective than other technologies,

considering the level of uncertainty in the economic results of this study (+/-30%). Other

main drivers such as proven technology and operational flexibility will, therefore, play an

important role in the widespread utilization of these technologies.

109

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Paper I

Development of H2-rich Syngas fuelled GT for future IGCC

power plants – establishment of a baseline

Nikolett Sipöcz, Mohammad Mansouri, Peter Breuhaus,

Mohsen Assadi

Presented at ASME Turbo Expo 2011, Vancouver, Canada,

June 2011

Copyright © 2011 by ASME

1

DEVELOPMENT OF H2-RICH SYNGAS FUELLED GT FOR FUTURE IGCC POWER PLANTS – ESTABLISHMENT OF A BASELINE

1Department of Mechanical- and

Structural Engineering and

Materials Science


4036 Stavanger, Norway

2International Research Institute of

Stavanger (IRIS)

Postbox 8046


ABSTRACT As part of the European Union (EU) funded H2-IGCC

project this work presents the establishment of a baseline

Integrated Gasification Combined Cycle (IGCC) power plant

configuration under a new set of boundary conditions such as

the combustion of undiluted hydrogen-rich syngas and high

fuel flexibility. This means solving the problems with high NOx

emitting diffusion burners, as this technology requires the

costly dilution of the syngas with high flow rates of N2 and/or

H2O. An overall goal of the project is to provide an IGCC configuration with a state-of-the-art (SOA) gas turbine (GT)

with minor modifications to the existing SOA GT and with the

ability to operate on a variety of fuels (H2-rich, syngas and

natural gas) to meet the requirements of a future clean power

generation. Therefore a detailed thermodynamic analysis of a

SOA IGCC plant based on Shell gasification technology and

Siemens/Ansaldo gas turbine with and without CO2 capture is

presented. A special emphasis has been dedicated to evaluate at

an intermediate stage of the project the GT performance and

identify current technical constraints for the realization of the

targeted fuel flexibility. The work shows that introduction of the low calorific fuel

(H2 rich fuel more than 89 mol% H2) has rather small impact on

the gas turbine from the system level study point of view. The

study has indicated that the combustion of undiluted syngas has

the potential of increasing the overall IGCC efficiency.

1 INTRODUCTION The continued need to use coal as primary fuel

engenders both increased interest and concern while, in

connection with coal gasification, generating a sincere demand

for the development of reliable, low-emission, cost-competitive

gas turbine technologies for hydrogen-rich syngas combustion.

Integrated gasification combined cycle is currently one of the

most attractive technologies for the use of coal with high

efficiency and it offers the greatest fuel flexibility among the

most advanced technologies for power production. In addition,

gasification also provides an opportunity to control and reduce

gaseous pollutant emissions such as NOx and SOx. It in addition

offers one of the least costly approaches to concentrate carbon

dioxide (CO2) at high pressure to facilitate CO2 capture and storage (CCS). However, coal-based IGCC plants have still not

achieved any commercial breakthrough, even though research

and development of IGCC plant technology began 40 years

ago. The currently six IGCC power plants in the world,

operating on coal as primary feedstock are demonstration plants

with capacities of 250-400 MW [1].

The design and operational experiences along with the

technical limitations of current state-of-the art IGCC power

plants have been reported in the recent past [2]-[5]. Important

contribution to field highlighting the two design variables

affecting the gas turbine operation i.e. the integration level of the ASU and the nitrogen supply ratio for dilution of the syngas

has been presented by Kim et al [6]. These two parameters do

also have an influence on the turbine metal temperature. It has

been shown that low integration degree designs cause

overheating of the turbine metal due to higher pressure ratios.

Overheating of the turbine metal also becomes more severe as

the heating value of the syngas decreases. As a consequence of

the increased fuel flow the pressure ratio is increased, which in

turn gives higher temperature of the extracted air for turbine

cooling [7]. Even though higher integration levels results in a

higher IGCC efficiency [6] the operational experience from

Nikolett Sipöcz1, Mohammad Mansouri

1, Peter Breuhaus

2, Mohsen Assadi

1

Proceedings of ASME Turbo Expo 2011 GT2011

June 6-10, 2011, Vancouver, British Columbia, Canada

GT2011-45701


2

Buggenum has shown that the highly integrated design layouts

are problematic and has a negative effect on the plant

availability.

With the last years growing concern about greenhouse

gas emissions the near-term implementation of pre-combustion

CO2 capture technologies in IGCC applications has drawn increased R&D interest [8]-[11]. One of the most promising

alternatives to the pre-combustion technology in IGCC power

plants is the oxy-combustion IGCC [12], [13], having the

potential of increasing both efficiency and environmental

characteristics of coal power plants. However, the large oxygen

consumption and required re-design of the gas turbine are still

the main drawbacks [13]. Accordingly, this CO2 abatement

technology along with membranes, adsorption onto solids and

cryogenic separation are different in terms of efficiency and

cost compared to chemical or physical absorption of CO2 and

thus the realization of these are within the mid-long term time

frame. Nevertheless, the capital costs associated with current SOA IGCC is a major challenge, especially compared to natural

gas combined cycles. Adding the costs for implementing any

near term CCS technology makes the challenge even greater

[14]-[17]. In this context the high operational costs, coming at

the top of the investment, is another drawback deriving from

the currently low reliability and availability of the gasifier,

reduced efficiency due to de-rating of the gas turbine, and the

required syngas pre-treatment in terms of dilution.

Although IGCC offer significant advantages over

pulverized coal (PC) plants in terms of cost effective reduction

of CO2 emissions, the main challenges including cost, compatibility with alternative technologies and the insecurity of

the implementation of any future CCS remain critical obstacles

for widespread commercialization [18]. Numerous research

projects such as Australia’s COAL21 National Action Plan, the

European funded Clean Coal Technology activities under the 7th

Framework Program, and the Canadian Clean Coal Technology

Roadmap have thus been released in recent years. They are

aiming at reducing these barriers by focusing on new coal

feeding systems, novel H2 production and purification

processes, and CO2 management [19].

In addition to capture, CCS involves two other major

components: transport and storage. One of the biggest uncertainties in the CCS chain is finding suitable sites for the

storage of CO2 close to the emissions sources. Other storage

issues that need be addressed are: storage capacity estimation,

the potential for storage e.g. in deep saline reservoirs,

understanding the CO2 trapping mechanisms and quantifying

the risks of CO2 geological storage. Even though considerable

progress has been made in understanding many of these issues

trough the many research and demonstration projects around

the world i.e. Sleipner, Weiburn, In Salah and Otway to

mention a few, the regulatory framework and incentives for a

near term implementation of CCS is still to be solved [20]-[22]. As a part of the EU funded H2-IGCC project this work

presents the establishment of a baseline IGCC power plant

configuration under a set of new boundary conditions. An

overall goal of the project is to provide an IGCC configuration

with a SOA GT with minor modifications to the existing SOA

GT and with the ability to operate on a variety of fuels (H2-rich,

syngas and natural gas) to meet the requirements of a future

clean power generation. Therefore a detailed thermodynamic

analysis of a SOA IGCC plant based on Shell gasification

technology and Siemens/Ansaldo gas turbine with and without CO2 capture is presented. A special emphasis has been

dedicated to evaluate the GT performance and identify current

technical constraints for the realization of the targeted fuel

flexibility.

2 H2-IGCC PROJECT One of the largest barriers towards the usage of syngas

in current IGCC power plants is its inherently variation in

composition and heating value. At the same time the high

content of H2 in syngas derived from gasification of coal

complicates the application of pre-mix burners (Dry Low

Emission of Dry Low NOx burners) , which is current SOA in natural gas fired GTs. The restriction of using DLE burners is

due to the higher reactivity of H2 compared to natural gas. For

this reason GTs in existing IGCC power plants are utilizing

high NOx emitting diffusion burners that also requires the

hydrogen-rich syngas to be diluted with nitrogen or

water/steam to control the higher adiabatic flame temperature.

Given these limitations the overall objective of the H2-

IGCC project is to provide and demonstrate technical solutions

which will allow the use of SOA highly efficient, reliable GTs

in the next generation of IGCC plants. The goal is to enable

combustion of undiluted hydrogen-rich syngas with low NOx

emissions and also allowing for high fuel flexibility by enabling

the burning of back-up fuels, such as natural gas, without

adversely affecting the reliability and availability.

The project is divided into the following four technical

subprojects (SP)[23]:

Combustion (SP1) – development and demonstration

of safe and low emission combustion technology for

undiluted, hydrogen-rich syngas.

Materials (SP2) – development and demonstration of

improved materials systems with advanced coatings

able to protect base blade and combustor materials

against the different and potentially more aggressive temperatures and compositions of exhaust gases.

Turbomachinery (SP3) – investigation of modified

compressor/turbine aerodynamics and hot path cooling

in order to manage the increased mass flow rate of fuel

and the increased heat transfer of exhaust gases.

System Analysis (SP4) – evaluation of optimum

IGCC plant configurations and establishment of

guidelines for optimized full scale integration while

providing detailed system analysis to generate realistic

techno-economical results for future gas turbine based

IGCC plants with CCS.


3

3 METHODOLOGY This work covers the description of the current

thermodynamic model set-up of the whole IGCC cycle

including important aspects of assumptions and limitations as

well as a discussion of the results. A special emphasis in this

regards has been given to the GT since this component is the major of the overall H2-IGCC project.

The thermodynamic model set up, described by the mass

and energy balances of the IGCC plant with gasification of coal

and pre-combustion CO2 capture has been established based on

commercially available technology:

oxygen-blown, entrained flow coal gasifier (Shell

technology),

sour water-gas-shift (WGS) reactors,

physical absorption using Selexol solvent for acid gas

removal (AGR),

power island consisting of a 300 MW single shaft gas

turbine based on the Ansaldo Energia 94.3A with a conventional triple-pressure steam cycle as the

bottoming cycle.

The focus of utilizing SOA technology is an important

element of the overall project. Thus the foundation of the

reference IGCC layout provides a fairly conservative baseline

for future studies. At the end of the project the goal is to find

the optimum combination of commercial gasification units with

modified gas turbines, incorporating solutions to the technical

challenges of burning undiluted hydrogen-rich syngas at an

appropriate level of integration.

Modelling of the IGCC power plant has been made using three different modelling tools:

Enssim – Simulation tool developed by Enssim

Software.

Aspen HYSYS – Commercial process simulator by

AspenTech [24].

IPSEpro- Commercial heat and mass balance

programme by SimTech [25].

The reason for using a combination of several

simulation tools is that each of the selected tools have shown

advantages when simulating different parts of the IGCC plant

in terms of providing reliable results and the possibility of incorporating detailed component characteristics. Hence, the

simulation tool among these three satisfying these requirements

for each sub-system to the greatest extent has been selected as

described below:

The detailed modelling of the Shell gasification

process including the process components: coal

milling and drying, gasification, raw syngas cooling

and scrubbing have been performed by Nuon using the

Enssim modelling tool.

The required compression work in the air separation

unit (ASU) has been calculated using Aspen HYSYS (Peng-Robinson equation of state (EOS)).

The syngas cleaning downstream the wet scrubber has

been modelled by first simulate the mixing of raw

syngas and steam in Aspen HYSYS (Peng-Robinson

EOS) while the subsequent shift and two stage acid

gas removal has been performed in the heat and mass

balance program IPSEpro. In the case when no capture

of CO2 takes place the syngas leaving the wet scrubber

is bypassed to the H2S absorber before entering the power island (without any dilution).

The clean syngas leaving the CO2 absorber/H2S

absorber is directed to the GT, which together with the

triple-pressure steam cycle is modelled in IPSEpro.

The CO2 captured in the second absorber in the AGR

process is compressed in a seven-stage intercooled

compressor and finally pumped to appropriate

transportation conditions. This part has also been

completed using the Aspen HYSYS modelling tool

(Peng-Robinson EOS).

Data exchange between these codes was done manually and iterated for optimal match.

Even though three different tools have been used for

simulating the whole IGCC power plant with as well as without

CO2 capture, the main platform for the simulations is IPSEpro

and the aim is to be able to simulate the whole IGCC except

from the gasification island in the IPSEpro environment by

solving current limitation in terms of pressure of pure gaseous

streams. The main reason for using IPSEpro as basis for the

simulations is the comprehensive model library, which has been

developed as a result of many years work within the research

group of University of Stavanger. This includes detailed and sophisticated models of various power plant components that

have been developed due to the main advantage of IPSEpro,

allowing for introducing new and modified components in a

very straight-forward and flexible manner. This advantage is

very important in this project as the GT model will need to be

adapted to certain changes based on the results from the

different SPs. IPSEpro also provides additional benefits in

terms of thermo-economical optimization features that will be

of major significance to achieve the overall project target of

finding optimum combination of commercial gasification units

with modified gas turbines and appropriate level of integration.

The schematic outline of the IGCC with CO2 capture is illustrated in Figure 1.

4 IGCC POWER PLANT DESIGN 4.1 Coal input

Bituminous coal being a mixture of various trade coals

on the world market (mainly Russia, but also USA, Columbia

and South Africa) with the composition according to Table 1. It

is milled and dried to a moisture level of 2%wt, and fed to the

gasifier by means of lockhopper pressurization using

pressurized N2 as conveying gas. Heat for drying is provided by

burning approximately 0.9% of the shifted syngas. The amount of coal needed is determined by the thermal power required by

the gas turbine model, based on the Ansaldo Energia 94.3A GT.

The resulting coal input is within the range of 1’008 -1’110

MWLHV.


4

Table 1 – Composition (% by weight) and heating value of as received

of the Bituminous coal used in the calculations.

C 64.10 Moisture 10 H 3.90 Ash 12.50 N 0.70

O 7.21 kJ/kg

S 1.50 HHV 26195 Cl 0.09 LHV 25100

4.2 Air separation unit

The ASU is a stand-alone unit generating oxygen with

a purity of 95mol% (with 2% N2 and 3% Ar) from air supplied

by the non integrated main air compressor (MAC). Selection of

the non- integrated MAC was motivated by negative experiences concerning plant availability, from partially or fully

integrated ASU systems. The MAC is a seven-stage intercooled

MAC

ASU

GOX compressor

PGAN compressor

O2

N2

ambient air

Waste N2

M

M

M

Wet Scrubber

Coal milling & drying

Slag

Fly Ash

A

A

M

Make-up water

HT WGS

LT WGS

B

B

Demister

ambient air

C

C

D

E

D

D

EFF, G

G

liquified CO2

CO2 flash drums

H2S removal

CO2

removal

H

H

HRSG

gas turbine

HP IP/LP

Condenser

Gasifier

Syngas

Cooler

M

Claus/SCOT

Raw syngas

H2-rich syngas

I

I

M

F

Figure 1 – Plant schematic of the Shell IGCC with CO2 capture and conventional WGS

compressor with a discharge pressure of 5.5 bara. The gaseous

oxygen (GOX) is compressed to 55 bara in a nine-stage

intercooled compressor and fed to the gasifier while the pure

gaseous nitrogen (PGAN) is compressed to 80 bara in a ten-

stage intercooled compressor used for fuel feeding to the

gasifier. Since the GT is operated on undiluted syngas all

remaining nitrogen from the ASU not needed in the gasification

island is vented to the atmosphere. For further technical assumptions for the air separation unit please see Table A1 in

Annex 1.

4.3 Gasification, syngas cooling and scrubbing The gasification of the coal is taking place in an O2-

blown, entrained flow gasifier based on the technology licensed

by Shell [26]. The gasification process (technical assumptions

presented in Table A2 in Annex 1), in which the milled and

dried coal is gasified in the presence of intermediate pressure

(IP) steam and oxygen is modelled assuming full equilibrium at

45 bara and 1600 °C. This condition determines the composition of the raw syngas and it is achieved by adjusting

the O2 to coal mass ratio while setting the heat loss to the

membrane wall to 2.5% (LHV). The single pass and overall


5

carbon conversion rate is 99.3% (no recycling of fly ash) and

the fine particles that are not captured as fly ash by the ceramic

filter (after syngas cooling) leave the bottom of the gasifier as

vitreous slag.

The raw syngas from the gasifier is first cooled to 900

°C by adding a stream of recycled, cooled, ash-free syngas in order to lower the gas temperature below the ash melting point.

The raw syngas is then further cooled to 340 °C in syngas

coolers that evaporate high pressure (HP) and IP pressure boiler

feedwater to produce HP steam for the steam cycle and IP

steam to be used in the water-gas-shift process. After passing

the dry particulate filters removing the fly ash, a small part of

the raw syngas is recycled back (0.84%) for cooling the raw

syngas exiting the gasifier. The rest is sent to the wet scrubber

for removal of species soluble in water, and trace particulate

matter such as unconverted carbon, slag and metals. The

quenched and cleaned syngas leaving the scrubber has a

temperature and pressure of 165 °C and 43 bara respectively. However, the dry-feed characteristics for the Shell gasifier

leaves the raw syngas with a relatively low steam-to-CO ratio

thus requiring injection of steam to insure adequate CO to CO2

conversion during the WGS. The IP steam for this purpose is

partly supplied from the syngas cooler, but since the

requirement is larger than the amount generated in the gasifier

the rest is bled from the HP/IP turbine crossover. In order to

promote the WGS reaction sufficiently and to avoid carbon

formation on the WGS catalyst the steam-to CO ratio has been

adjusted to 2.4 (molar basis).

4.4 Water-gas-shift

The water-gas-shift process is the reaction used to

convert most of the CO in the raw syngas into CO2, by shifting

the CO with water over a bed of catalyst. Besides CO2

hydrogen is generated in this reaction (Eq.1). In IGCC

applications with CO2 capture this is the first step in order to

convert the gasifier product into a hydrogen-rich-syngas. The

CO converter is located upstream of the AGR unit (sour shift)

and is arranged as two reactors in series to meet higher CO2

capture rates. The WGS reaction is exothermic (44 KJ/moleCO)

and it is thermodynamically favoured at lower temperatures, where reaction rates are comparatively slow. However, catalyst

activity is in general higher at high temperatures.

(1)

The scrubbed and steam mixed syngas is pre-heated to

250 °C before entering the first stage of the WGS unit. The syngas leaving the first high temperature (HT) reactor is cooled

down from the equilibrium temperature of 463 °C to 250 °C by

generating HP steam and it then enters the low temperature

(LT) WGS reactor. The warm syngas leaving the second reactor

at an equilibrium temperature of 278 °C is cooled to 25°C by

means of preheating the raw syngas entering the first WGS

reactor and by preheating HP boiler feedwater. The resulting

overall adiabatic conversion of CO to CO2 and H2 in the WGS

process is 98.9% (molar basis). The cooled shifted syngas is

passed through a demister before being sent to the acid-gas

removal. The total pressure loss of the syngas from the exit of

the wet scrubber to the exit of the demister is 9.1%.

4.5 Acid gas removal During gasification, sulphur in the raw coal is converted to H2S and COS. Nevertheless, in the CO2 capture

case most of the COS is converted to H2S during the WGS

reaction. The H2S and CO2 are removed from the shifted syngas

in a two-stage physical absorption system using dimethyl ether

of polyethylene glycol also known as Selexol. The syngas

enters the first absorption column in which the H2S is removed

by a counter current flow of the solvent. The acid gases in the

rich solution exiting the bottom of the absorber column is

flashed and then stripped off in a regenerator for which heat

(approximately 13.6 MWth) is provided from steam bled from

the LP steam turbine. The regenerated solvent is cooled and

recycled back to the top of the absorber while H2S is sent to a sulphur recovery unit including a Claus plant for oxidizing H2S

to elemental sulphur and a Shell Claus off gas treating (SCOT)

plant for tail gas cleanup.

After leaving the H2S absorber the syngas enters the

second absorber for removal of CO2. Similar to the removal of

H2S the CO2 is absorbed by the solvent flowing downwards the

column and exits the bottom of the column with the CO2 solved

in the solution. This collected rich CO2 solvent exiting the

bottom of the tower is passed through four flash drums

connected in series, where CO2 is released as a result of

lowering the pressure. The lean solvent leaving the last flash drum is pumped and returned back to the top of the absorber

column. The release of the pressure of the rich solvent between

the column and the different flash drums is achieved by

hydraulic turbines. In this way part of the solvent pumping

power could be recovered. The solubility of CO and H2 in

Selexol is low, but not negligible, hence in order to minimize

the amount of H2 and CO that are co-absorbed with the CO2 in

the absorber and thereby lowering the heating value of the fuel.

The gas leaving the first flash drum is recycled back to the

absorber column, since virtually all H2 and CO absorbed is

released in this drum. The CO2 released in the flash drums two

to four is sent to compression. The CO2 removal rate in the AGR unit is 96.3% (molar basis), though, the overall CO2

capture rate as defined in Eq. 4 is 88.6% (molar basis).

(4)

In the case when CO2 is vented, the raw syngas

leaving the wet scrubber is passed through the demister before

entering the H2S absorber. The rich solution leaving the bottom

of the column is regenerated and the sulphur is stripped off

using IP steam produced in the gasification island. Since this

amount is only partly sufficient the rest is extracted from the

HRSG. However, since the solvent flow rate in this case is


6

considerably lower (the flow rate of dry raw syngas is lower

than that of dry shifted) the thermal heat input is 3.6 MWth

lower than for the case with CO2 capture. The H2S poor syngas

exiting the absorber top is passed to the GT combustor. For

further technical assumptions for the AGR unit please see Table

A3 in Annex 1.

4.6 CO2 compression

The CO2 collected in the flash drums in the CO2

removal process is compressed in a seven-stage intercooled

compressor to 60 bara, liquified and then pumped up to final

pressure of 150 bara. The compressor/pumping approach has

been evaluated in a previous work by the authors and found to

be the most efficient approach [27].

4.7 Gas turbine model

The gas turbine model has been modelled based on

internal project information exchange with the working group focussing on the GT design (SP3). This information included

initial performance calculation results of a lumped

turbomachinery model of the GT, Ansaldo Energia 94.3A, with

a first version of the compressor map and some turbine data.

All information received was based on natural gas as fuel. The

control algorithm currently adopted when burning undiluted

hydrogen-rich syngas and cleaned syngas is without any major

modifications to the natural gas operation:

The turbine inlet temperature (TIT) was fixed to 1331

°C.

The compressor variable inlet guide vanes (VIGV) are

slightly closed to adjust for the increased fuel flow by

reducing the air mass flow.

Due to the increased fuel flow the model adjusts the

pressure ratio accordingly.

The GT models used at current state have some limitations

for off-design calculations, as only subsections of the

compressor- and turbine maps are implemented, there is no

detailed modelling of the cooling flows, etc., but will be

handled as soon as more information from other teams within

the project will be available. Nevertheless, the current model is

built up accordingly:

Compressor model – In terms of the speed lines, a

characteristic has been used which is, according to the authors,

reflecting state of the art characteristics Besides, cooling air

extraction at different pressure level has not been considered as

this information was not available at this time. However

extractions are already part of the model and can be activated when needed. It is planned that the characteristic currently in

use is going to be replaced as soon as a more detailed version of

the compressor map is available.

Combustor model – The fuel composition to the combustor

was calculated using the detailed models described above (4.1 -

4.5). Besides, a pressure loss reflecting current state of the art technology was used. This will also be updated later on

according to the results provided by the working group for

combustion. Fuel pre-heating has not been included, but will be

considered in the optimization of the whole IGGC plant.

Turbine model - The turbine part has been modelled using a

simplified approach based on the input received. The turbine

model used in this work has been assumed with a constant hot

gas flow, even though the real turbine is cooled and cooling air

is mixed into the hot gas at different stages this was not

considered in the existing model. In order to never the less

cover the overall performance of the turbine the turbine-, inlet

temperature and efficiency are calculated in terms of virtual

measures according to following equations:

(2)

and

(3)

This has been done to match the data received from the

turbomachinery working group. By doing so the general

expansion in the turbine (mainly the pressure ratio and

therefore also the power consumption in the compressor) as

well as the overall power output was met. The technical

assumptions for the GT are presented in Table A4 in Annex 1.

The above described simplifications are an often used

approach in the early stage simulation of a GT process. These

models are going to be replaced by more detailed ones as soon

as this information will become available.

4.8 Heat recovery steam generator design Downstream the GT is a three pressure level heat

recovery steam generator (HRSG) with reheat. The admission

levels have been set according to internal discussions and

agreements within SP4. The superheating temperature has been

set to 530 °C in order to meet the GT exhaust temperature and

the required amount of HP steam needed to be superheated. The

heat integration represents somewhat a first approach and has

not been optimized. The assumptions of the parameters of the

HRSG are considered to be conservative in terms of pressure

losses, approach temperatures, steam turbine efficiency, etc.

There is potential of increasing the HRSG efficiency in order to maximize the net electrical output, however the economical

feasibility of such optimization should not be disregarded.

The IP and HP boiler feedwater (BFW) needed in the

gasification island is taken from the HRSG and all HP steam is

returned back to the HRSG and mixed with the HP steam

produced in the WGS and superheated before expanded in the

steam turbine. The IP level has been set to meet the pressure of

the syngas leaving the wet scrubber 43 bara, since a

considerable amount of IP steam is extracted from the HRSG in

the case with CO2 capture and mixed with the raw syngas in


7

Table 2 – Performance results of the IGCC power plant with and without CO2 capture

order to perform the WGS reaction. The IP steam produced in

the gasifier island has a pressure of 50 bara, thus the BFW

extracted for this purpose is pumped to appropriate pressure and heated by utilizing a small part of the heat generated in the

HT part of the WGS. The assumptions made for the HRSG

calculation are presented in Table A5 (Annex 1). In the case without CO2 capture the HP BFW for the

gasification island is extracted in the same manner as in the

case with CO2 capture, however all the HP steam produced is

returned back to the HRSG and superheated to 500°C. The IP

BFW for is extracted similarly as for the CO2 capture case and

the small amount IP steam not needed in the gasification island

is used for regenerating the solvent in H2S removal unit. Since

the IP steam needed in the H2S removal is higher than the

amount produced in the gasification island the additional required is bled from the HP/IP crossover. The IP SH/RH

temperature has likewise the HP SH temperature for the CO2

venting case been lowered with 30°C to 500 °C to accomplish

the superheating of all steam produced in the gasifier as well as

the steam no needed for the WGS. All other assumptions for the

HRSG are presented in Table A5 in Annex 1.

5 RESULTS AND DISCUSSION The performance of the IGCC power plant with and

without CO2 capture based on the calculation using the models

as previously described are presented in Table 2 and the composition of the syngas for the two cases are given in Table

3. The IGCC without CO2 capture has a somewhat lower

efficiency, even though the syngas in this work is not diluted,

than a similar case presented last year by Kreutz et al [17]. The

main reason for this is that the reference GT used in this work

is less efficient than the General Electric 9 FB even though the

TIT was de-rated to 1327°C in the previous work. Nevertheless,

the syngas considered was highly pre-heated and the HRSG

fully optimized, which are issues within the scope of future

activities within this project. The net efficiency of the case with

CO2 capture and undiluted hydrogen rich syngas is on the

contrary demonstrating a higher efficiency compared to the same publication. This is due to a slightly difference in the

steam-to- CO ratio between the present study and the one

presented in [17]. In addition the higher heating value of

undiluted syngas results in a significantly higher GT power

output. Since the HRSG in this study has still not been

optimized the genuine improvement using undiluted syngas is

to be determined. The initial results have though confirmed that

without considering any any modifications of the GT and

keeping the efficiency constant, the power output from the

engine could increase with as much as 30 MW (compared to the same GT fired with natural gas).

The big differences in fuel composition between

natural gas, hydrogen-rich syngas and cleaned syngas will most

probably result in different designs of the combustion system as

well as compressor and turbine to maintain stable combustion

and to keep the pressure ratio for the different mass flow ratios

in turbine and compressor. The extent of these changes or

requirements will be revealed within the project in a near future

and will be implemented in the GT model, giving the

opportunity to optimise the processes for the various cases.

However, Table 3 summarizing the two different fuel

compositions directly indicates that two different combustor designs might be essential given the huge differences in the

properties, which are difficult to be covered in a single design.

The resulting difference in turbine inlet flow due to the huge

difference in fuel flow will either require a compressor design

with high efficiency over a wider range of IGV positions, or

also two different designs. This topic, which is closely

connected to transients and operation at off-design, will be

addressed during the next steps within the project.

The turbine outlet temperature (562°C and 588°C

respectively) as well as the turbine flow (700 kg/s and 749 kg/s

respectively) is higher for both IGCC cases compared to natural gas (576°C /698 kg/s), which favours the steam bottoming

cycle. However, there is an important difference in terms of

extraction of BFW and steam along with returning condensate

and steam from different parts of the IGCC power plant for the

two cases investigated. This will have a major impact on the

investment costs if the targeted fuel flexibility ranging from

natural gas to cleaned syngas is going to be met. The further

optimization of the two cases (with and without CO2 capture)

should thus be performed taking into consideration to reduce

these distinctions to the greatest extent possible. In addition

some aspects of changed conditions for component lifetime

need to be evaluated since the lifetime due to the above mentioned increases i.e. the gas temperature of the un-cooled

blade rows of the GT under certain operating conditions and

could if not designed for have certain negative impacts on plant

availability and costs.

The current overall CO2 capture rate for the hydrogen

rich case is 88.6 mol%, although the removal rate in the AGR

unit is approximately 96.3 mol%. The reason for this significant

difference is due to CO2 lost in the H2S absorber. The current

outline of the AGR unit has not been optimized; hence a

minimization of absorbed CO2 in the first stage of the AGR will

be further investigated by finding a more convenient combination of number of flashes as well as the extent of

solvent pre-loading. Currently there is also a deviation in

pressure loss in the H2S absorber for the two cases due to

pressure limitations in IPSEpro for pure gaseous streams which

IGCC w. IGCC w.o.

GT power out 324.07 309.39 MW ST shaft power 166.30 211.43 MW HRSG pumping power 3.54 3.13 MW AGR turbine power out 3.42 - MW

AGR pumping/ compr. power req. 11.39 0.2 MW ASU compression power req. 40.88 37.14 MW Gasification power req. 4.96 4.50 MW CO2 compression power req. 18.06 - MW

Net power out 414.96 476.86 MW Net IGCC efficiency (LHV) 37.40 47.20 %


8

limits the pressure, to 35 bara, in the case where the syngas is

sent for further removal in second stage. This has an impact on

the removal of CO2, since physical absorption is favoured at

higher partial pressures.

Table 3 – Composition (wt%) and characteristics after AGR of the hydrogen-rich and cleaned syngas respectively (undiluted)

Hydrogen-rich syngas Cleaned syngas

CO 0.0448 0.7857 CO2 0.1078 0.0716 H2 0.3595 0.0262 N2 0.4879 0.1165 Fuel flow (kg/s) 17.67 70.78 LHV (kJ/kg) 43641 11100 Temperature °C 25.6 25.24

Pressure (bara) 34.5 42.4

6 CONCLUSIONS As part of the EU-funded H2-IGCC project this work

has described the establishment of two fairly conservative

baseline IGCC cycles aimed for further investigations. The first

IGCC power plant has been modelled with pre-combustion

separation of CO2 while the second is without the application of

CO2 removal resulting in two completely different syngas compositions. Both IGCC power plants are based on the GT

Ansaldo Energia 94.3A without any dilution of the syngas. By

performing new gasifier calculations including fly-ash recycle,

optimizing the heat integration and implementing the

characteristic GT data there is a potential to increase the net

efficiencies of both plants beyond current values of 37.4% for

the IGCC power plant with CO2 capture and 47.2% for the case

with CO2 venting. The overall CO2 capture rate presented in

this work, 88.6mol% is somewhat low due to lost of CO2 in the

first AGR stage. A more favourable configuration of the H2S

removal unit will be further investigated to demonstrate higher

capture ratios.

ACKNOWLEDGMENTS The authors wish to acknowledge Nuon and E.ON for their

technical input and truthful discussions in the early phase of

this work. The authors are also grateful to Han Raas at Nuon

for performing the gasification simulations. The authors would

also like to acknowledge the project partners in SP3 for

providing the gas turbine performance data.

NOMENCLATURE AGR Acid gas removal

ASU Air separation unit BFW Boiler feed water

CCS Carbon capture and storage

CO2 Carbon dioxide

DLE Dry low NOx emission

EOS Equation of state

GT Gas turbine

H2 Hydrogen

H2S Hydrogen sulfide

HP High pressure

IGCC Integrated gasification combined cycle

IP Intermediate pressure

LP Low pressure

mol Molar

NOx Nitrogen oxide SOx Sulphor oxide

SOA State-of-the-art

SP Subproject

ST Steam turbine

TIT Turbine inlet temperature

WGS Water-gasshift

wt Weight

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[9] Chiesa, P., Consonni, S., 1999 Shift reactors and physical absorption for low- CO2 emission IGCCs.

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with oxygen-blown combustion. Journal of

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635-641.

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23259, ASME Turbo Expo, Glasgow, UK.

ANNEX A

TECHNICAL ASSUMPTIONS USED IN THE MODELLING

Table A1 – Technical assumptions for the ASU

Delivery pressure/temperature of O2 and N2 by ASU 1.2/10 bara/°C Main air compressor polytropic efficiency 87 %

GOX compressor polytropic efficiency 87 % HP PGAN compressor polytropic efficiency 87 % Inter-cooling temperature 40 °C


10

Table A2 – Technical assumptions for the Shell gasification island including the syngas conditioning downstream to the wet scrubber exit

Table A3 – Technical assumptions used for the AGR unit

CO2 capture No CO2 capture

Syngas pressure/temperature at H2S absorber inlet 39.1/25 43.96/25 bara/°C CO2 co-absorbed in H2S absorber 9.5 8.5 wt% (of inlet)

Syngas pressure/temperature at CO2 absorber inlet 35/25.7 - bara/°C Pressure loss in 1st/2nd absorber 4.1/0.5 0.5 bar H2S stripping duty 13.6 10 MWth H2 co-absorbed (overall) 0.35 0.1 wt% (of inlet) CO co-absorbed (overall) 1.2 0.2 wt% Solvent pumps polytropic efficiency 70 70 % Compressor isentropic efficiency (recycle gas) 85 85 % Hydraulic expander isentropic efficiency 85 85 %

Mechanical and electrical efficiency 99 99 % Solvent temperature at absorber inlet 25 25 °C

Table A4 – Technical assumptions used for the gas turbine

Ambient air pressure 1.013 bara Ambient air temperature 15 °C Moisture in air 60 % TIT 1331 °C

GT outlet pressure 1.08 bara (total) Pressure ratio 18.2 (target natural gas) Electrical/mechanical efficiency 99/99.5 %

Table A5 – Technical assumptions used for the HRSG

Dried coal moisture content 2 wt%

Gasification pressure/temperature 45/1600 bara/°C Shifted syngas for drying 2.2 wt% (of total flow) Steam/coal ratio 0.061 kg / kg coal (ar) O2/coal ratio 0.7839 kg / kg coal (ar) HP PGAN/coal ratio 0.241 kg / kg coal (ar) Power requirement 112 kJel/kg coal (ar) Heat loss to membrane wall 2.5 % coal LHV Carbon conversion (single pass/overall) 99.3 %

Syngas cooler pinch-point HP evaporator 30 °C Syngas cooler pinch-point IP evaporator 64 °C Heat exchanger heat loss 0 % Pressure drop syngas cooler (gas side) 0.33 bar Pressure drop wet scrubber 1 bar Water pump mechanical efficiency 85 % Steam-to-CO ratio at WGS inlet 2.4

HP/IP/LP 140/43/4 bara

SH and RH temperature 530* °C SH LP steam 300 °C HP/IP/LP ST isentropic efficiency 88.5/89/91 % ST and generator mechanical efficiency 99.5 % Gas side HRSG pressure drop 0.04 bara Generator electrical efficiency 98.2 % Pump polytropic efficiency 70 % Pump mechanical efficiency 95 %

Evaporator pinch point IP/LP 10/10 °C Super heater pinch point 32 °C Economizer pinch point 10 °C Approach point temperature 5 °C Condenser pressure 0.04 bara * The superheating/reheat temperature for the case without CO2 capture is 500°C, all other assumptions are the same.

133

Paper II

An EU initiative for future generation of IGCC power plants

using hydrogen-rich syngas: Simulation results for the baseline

configuration

Mohammad Mansouri Majoumerd, Sudipta De, Mohsen Assadi,

Peter Breuhaus

Published in Applied Energy, Vol. 99, p. 280-290, June 2012

Author's personal copy

An EU initiative for future generation of IGCC power plants using hydrogen-richsyngas: Simulation results for the baseline configuration

Mohammad Mansouri Majoumerd a,⇑, Sudipta De b, Mohsen Assadi a, Peter Breuhaus c

a Department of Mechanical and Structural Engineering and Materials Science, University of Stavanger, 4036 Stavanger, Norwayb Department of Mechanical Engineering, Jadavpur University, Kolkata 700032, Indiac International Research Institute of Stavanger (IRIS), Postbox 8046, 4068 Stavanger, Norway

h i g h l i g h t s

" A baseline IGCC power plant with and without CO2 capture is presented." Burning of undiluted hydrogen-rich syngas in the gas turbine is assumed." A significant efficiency penalty is associated with the CO2 capture system.

a r t i c l e i n f o

Article history:Received 13 February 2012Received in revised form 23 May 2012Accepted 25 May 2012Available online 22 June 2012

Keywords:IGCCCO2 captureGas turbineH2-rich fuel

a b s t r a c t

In spite of the rapid development and introduction of renewable and alternative resources, coal still con-tinues to be the most significant fuel to meet the global electricity demand. Emission from existing coalbased power plants is, besides others, identified as one of the major sources of anthropogenic carbondioxide, responsible for climate change. Advanced coal based power plants with acceptable efficiencyand low carbon dioxide emission are therefore in sharp focus for current development. The integratedgasification combined cycle (IGCC) power plant with pre-combustion carbon capture is a prospectivetechnology option for this purpose. However, such plants currently have limitations regarding fuel flex-ibility, performance, etc. In an EU initiative (H2-IGCC project), possible improvements of such plants arebeing explored. These involve using premix combustion of undiluted hydrogen-rich syngas and improvedfuel flexibility without adversely affecting the availability and reliability of the plant and also makingminor modifications to existing gas turbines for this purpose. In this paper, detailed thermodynamicmodels and assumptions of the preliminary configuration of such a plant are reported, with performanceanalysis based on available practical data and information. The overall efficiency of the IGCC power plantwith carbon capture is estimated to 36.3% (LHV). The results confirm the fact that a significant penalty onefficiency is associated with the capture of CO2. This penalty is 21.6% relative to the IGCC without CO2

capture, i.e. 10.0% points. Estimated significant performance indicators as well as comparisons with alter-native schemes have been presented. Some possible future developments based on these results and theoverall objective of the project are also discussed.

� 2012 Elsevier Ltd. All rights reserved.

1. Introduction

Use of energy is closely related to the development of an econ-omy. Often per capita consumption of energy is considered as anindex of the living standard of the people of a country. Thoughthe efficiency of energy usage has a strong impact on energy con-sumption, the demand for energy is always expected to increasewith the growth in population and living standards. The mostuseful form of energy in the modern world is electricity. Thus theefficient conversion of primary energy to electricity is, besides its

efficient use, critical for human civilization [1]. In terms of the eco-nomical aspects of available reliable technology, coal is still themajor source of electric power [2]. It is also available in differentparts of the world, safe to store and easy to transport over a longdistance. Thus coal has emerged as the most widely used fossil fuelfor large-scale power generation, though natural gas (NG) use isalso increasing mostly in localities of availability due to the factthat it is more environmentally friendly [3]. Conventional pulver-ized fuel (PF) fired thermal power plants have been the mostprevalent technology worldwide over a long period. These plantsare mostly used for large-scale electricity supply through the grid.

Climate change due to anthropogenic greenhouse gas (GHG)emissions is identified as the greatest threat to mankind [4]. The

0306-2619/$ - see front matter � 2012 Elsevier Ltd. All rights reserved.http://dx.doi.org/10.1016/j.apenergy.2012.05.023

⇑ Corresponding author. Tel.: +47 45 39 19 26; fax: +47 51 83 10 50.E-mail address: [email protected] (M. Mansouri Majoumerd).

Applied Energy 99 (2012) 280–290

Contents lists available at SciVerse ScienceDirect

Applied Energy

journal homepage: www.elsevier .com/ locate/apenergy


major source of these GHGs is carbon dioxide emission, and thepower sector is identified as the single largest sector contributingto this emission. According to the International Energy Agency,the CO2 emissions from electricity and heat production were about41% of total global emissions from fossil fuels in the year 2009 [5].The present challenge for the power sector is to meet the everincreasing demand for electricity and simultaneously mitigatethe GHG emissions, principally CO2. Besides drastically increasingthe energy efficiency, one possible option is to replace fossil fuelbased power plants by renewable sources (say, solar, hydro, bio-mass, geothermal, etc.). Unfortunately, available technologies forproducing electricity from renewable sources are still not whollymature and/or not installed to the extent to meet the present de-mand fully in an economic and feasible way. Renewable sourcesare undoubtedly the only option for the future, but the estimatedtimescale for the complete transformation from fossil fuels torenewable resources is not definite and is likely to be a significanttime away [3]. Thus the development of suitable technology forlarge-scale power generation using coal during this transition is ur-gently needed.

The major challenge for future generation coal based powerplants is to minimize the emissions of CO2 to the atmosphere whilemaintaining acceptable overall plant efficiency. One way of pas-sively reducing this emission per MW power generation is to con-tinue to further increase the efficiency of conversion. However,incorporating some active measures to reduce CO2 emissions isalso necessary if targets for 2050 are to be met. Several routes havebeen identified for this purpose [6–11]. Capturing CO2 from the ex-haust flue gas mixture before it is vented to the atmosphere isknown as ‘post combustion carbon capture’. Solutions are usuallyused to absorb CO2 from the flue gas mixture [12]. Processes basedon solids to capture CO2 from the flue gas mixture are described in[13,14]. The small fraction of CO2 in the flue gas, which is mixedwith other combustion products and a large fraction of nitrogenfrom atmospheric air, makes capture difficult. An alternative tech-nology is oxy–fuel combustion. This is to use pure oxygen for thecombustion of coal, resulting in mostly CO2 in the exhaust fluegas, which is easier to capture and transport directly for geologicalstorage. Large-scale separation of oxygen from the air, which is anenergy-intensive process, is needed and results in high penalties

on efficiency. Also the gas turbine has to be redesigned for this pro-cess [15]. Significant development of this process at the laboratorylevel is reported in the literature [16,17]. Pre-combustion carboncapture is another good alternative technology [18–21]. Coal isgasified to produce syngas (primarily a mixture of H2 and CO),and the carbon monoxide produced in this process is convertedto carbon dioxide by ‘water-shift reaction’ [22]. CO2 is then sepa-rated from the syngas before combustion. As CO2 partial pressureis higher in the gas mixture in this pre-combustion process, it iscomparatively easier to capture. Also other pollutant gases canbe removed in this gas cleaning process before combustion, result-ing in minimum emission of pollutants. The resulting hydrogen-rich syngas is subsequently used in a combined power plant withhigh thermodynamic efficiency. Such integrated gasification com-bined cycle (IGCC) power plants with pre-combustion carbon cap-ture appear to be promising for using coal and meeting theenvironmental standards [23]. However, the overall plant effi-ciency is reduced, and complex plants for coal gasification andgas treatment/cleaning may lead to frequent shutdown and re-duced reliability. Though high-scale integration may improve theefficiency of the plant during operation [24], it might also reducethe reliability of the power supply, according to the practical expe-rience of operating similar equipment in integrated configurationssuch as the Buggenum plant operated by Vattenfall. Determiningthe optimum degree of integration to obtain acceptable efficiencyand reliable power supply is, therefore, another objective for futureplants.

In the H2-IGCC project (refer to Section 2), the overall objectiveis to enable the stable operating conditions of the gas turbine withcombustion of undiluted H2-rich syngas, and to increase the abilityto operate on a variety of fuels (such as cleaned syngas, and naturalgas), a feature known as ‘fuel flexibility’, without adversely affect-ing the reliability and availability of the plant. Besides, minor mod-ification of existing GTs is one of the project’s goals.

In this paper a detailed thermodynamic model is presented, aswell as the performance analysis of the integrated gasificationcombined cycle power plant based on practical flow-sheet andrealistic performance indicators verified by the operators of simi-lar, relevant plants. Further investigations for an optimum config-uration, based on the results of this study, are also discussed.

Nomenclature

AGR acid gas removalAr argonASU air separation unita.r. as receivedBFW boiler-feed-waterCCS carbon capture and sequestrationCMD coal milling and dryingCO carbon monoxideCOS carbonyl sulfideCO2 carbon dioxideDEPG di-methyl ether of polyethylene glycolDLN dry low NOx emissionEOS equation-of-stateEU European UnionGHG greenhouse gasGOX gaseous oxygenGT gas turbineHHV higher heating valueH2 hydrogenH2S hydrogen sulfideHP high pressure

HRSG heat recovery steam generatorIGCC integrated gasification combined cycleIP intermediate pressureLHV lower heating valueLP low pressureMAC main air compressorNG natural gasNOx nitrogen oxidePF pulverized fuelPGAN pure gaseous nitrogenRH reheatingSCOT Shell Claus off-gas treatingSGC syngas coolingSGS syngas scrubbingSH superheatingST steam turbineSWGS sour water–gas shiftTIT turbine inlet temperatureTEG tri-ethylene glycolTOT turbine outlet temperatureVIGV variable inlet guide vane

M. Mansouri Majoumerd et al. / Applied Energy 99 (2012) 280–290 281


2. H2-IGCC project

Current technologies for coal gasification and the use of the syn-gas as fuel in combined cycle power plants suffer from two mainlimitations. The wide variation of fuel composition (i.e., wide var-iation of the heating value) causes several difficulties during oper-ation using available gas turbines (GTs). Furthermore, the syngas isrich in H2 due to pre-combustion carbon capture resulting in chal-lenges for using the premix burners. These burners are the state-of-the-art technology for dry low NOx (DLN) combustion in naturalgas fuelled GTs. Higher reactivity of H2 compared to that of NGcauses problems for using these burners in IGCC plants. Often thisproblem is overcome by using conventional diffusion burnersresulting in high emissions of NOx, besides diluting the fuel witheither N2 or water/steam to reduce the effect of the higher adia-batic flame temperature when burning H2-rich fuel.

In November 2009 the H2-IGCC project was started with theoverall goal to develop and demonstrate technological solutionsto overcome the above-mentioned drawbacks while burning H2-rich fuels. The developed technology therefore may allow burningundiluted H2-rich syngas with low NOx emissions, comparablewith that of the state-of-the-art technologies with NG as fuel.The goal of the project is also to develop an optimized plant layoutthat will not only maximize efficiency but also allow fuel flexibilityas well as reliability of power supply. Both options are also to beexplored: with CO2 capture or without since access to CO2 trans-port, injection and storage infrastructure is not yet guaranteed.

Twenty-four different partners including academia and manu-facturers as well as plant operators from ten European countriesare working together to achieve the above-mentioned goals. Fourmajor research areas are targeted namely combustion, materials,turbomachinery and system analysis. Results of these activitiesshould support:

� Developing and demonstrating a safe and low emission pre-mixed combustor technology for the undiluted hydrogen-richsyngas from coal gasification with pre-combustion carboncapture.

� Developing and demonstrating improved materials withadvanced coatings for the turbine blades and combustor.The target is to achieve lifetimes similar to those of the latestnatural gas fired gas turbines for identical run time in spite ofthe potentially more aggressive temperature and compositionof the exhaust gas.

� Providing required design for the compressor/expander aero-dynamics as well as the cooling of hot gas path componentsin order to cope with increased mass flow rate, due to thehigher fuel flow and changed gas properties of the exhaustgas, which causes changed heat transfer conditions at all sur-faces exposed to the hot gas.

� Evaluating and optimizing the best IGCC plant configurationas well as to provide guidelines for optimized full-scale inte-gration in order to satisfy the above-mentioned require-ments. Moreover, a detailed systems analysis will beperformed to generate realistic techno-economic results forIGCC plants with pre-combustion carbon capture. The resultsare to be compared with a natural gas fired plant forbenchmarking.

3. System overview

In this section the thermodynamic model of the baseline config-uration of the IGCC power plant consisting of several sub-systems isdescribed. The detailed model includes many sub-systems withreasonable assumptions based on either commercially available

technology or data provided by other subgroups of the project. Sig-nificant sub-systems with relevant assumptions and issues are dis-cussed. The thermodynamic model of the baseline IGCC powerplant was based on commercially available technologies as follows:

� Cryogenic air separation unit (ASU);� Oxygen-blown, entrained flow coal gasifier based on Shell

technology;� Sour water–gas shift (SWGS)� Carbonyl sulfide (COS) hydrolysis unit for the case when no

capture of CO2 took place;� Acid gas removal (AGR) unit using physical absorption by

SELEXOLTM system;� CO2 compression and dehydration unit; and� power generation block consisting of a 300 MW single-shaft

gas turbine based on the Siemens/Ansaldo Energia 94.3Atechnology and a conventional triple-pressure bottomingsteam cycle.

Theoretical description and integration methods of similar sub-systems have been addressed by several studies [21,22,25–31].Therefore, in this study special emphasis is placed on a practicalplant (Fig. 1) to estimate realistic performance indicators, verifiedby project team members with relevant plant operating experi-ences. The specifications of each sub-system as well as assump-tions and boundary conditions are described in the followingsub-sections.

3.1. Coal feed

The assumed coal was a bituminous coal which was a mixtureof various trade coals on the world market. The composition ofthe coal (wt.% a.r.) is summarized in Table 1.

The amount of coal required was determined by the thermalpower demand of the gas turbine which was within the range of1005–1112 MWLHV.

3.2. Air separation unit (ASU)

The cryogenic air separation process, which is currently themost reliable technology for large-scale production of oxygenand nitrogen [25], was considered as a stand-alone unit. The purityof oxygen was set to 95 mol% (2% N2 and 3% Ar) as obtained fromthe techno-economic evaluation of such units utilized in realplants.

Ambient air was initially compressed by the main air compres-sor (MAC). Although integration of the ASU and the GT would leadto a higher efficiency, the most appropriate degree of integrationneeds to be decided. Better operational safety and greater avail-ability of the plant would be the result of low or no integration[26]. Experience from the real IGCC plant in Buggenum promoteda non-integrated approach for improved plant availability [27].The MAC was a three-stage intercooled compressor with a dis-charge pressure of 5.5 bar. The delivery pressures of the pure gas-eous nitrogen (PGAN) and gaseous oxygen (GOX) from the MACwere 5 and 1.2 bar, respectively. The discharge pressure of thePGAN which was used for coal feeding to the gasifier was 80 bar,while the gaseous oxygen (GOX) was compressed further up to55 bar and fed to the gasifier. Both compressors for the GOX andthe PGAN were six-stage intercooled compressors. It is worth not-ing that the lower number of inter-cooled stages used here com-pared to other studies, as well as the lower componentefficiencies, represent ‘‘common practices’’ in the currently exist-ing power plants. Further technical assumptions for the ASU areshown in Table 2 below.

282 M. Mansouri Majoumerd et al. / Applied Energy 99 (2012) 280–290


3.3. Gasification, syngas cooling and scrubbing

Gasification of coal took place in the Shell gasifier [28]. Themilled and dried coal was gasified in the presence of intermediatepressure (IP) steam and oxygen. The gasifier was of single passtype, and the remaining fine particles that were not captured bythe ceramic filters as fly ash left the bottom of the gasifier as vitre-ous slag. One of the major sources of inaccuracies in theoretical

studies presented in open literature is due to the non-realisticmodel of the gasification unit. The gasification plant model usedin this study was based on the existing plant in Buggenum [27],and the gas analysis obtained from the model was validatedagainst real plant data.

The raw syngas was first cooled to 900 �C by recycling thecooled, ash-free syngas stream and then further cooled to 340 �Cin syngas coolers by generating high pressure (HP) and intermedi-ate pressure (IP) steams, as shown in Fig. 1. After passing throughthe dry particulate filters and recycling a part of the syngas streamfor the aforementioned cooling purpose, the rest of the syngas wassent to the wet scrubber. The quenched and cleaned syngas enter-ing the SWGS unit had a temperature and pressure of 165 �C and43 bar, respectively. Further technical assumptions and resultsare presented in Table 3 below. The syngas composition at the inletof SWGS unit is presented in Table 4.

3.4. Sour water–gas shift

The water–gas shift process was a catalytic reaction convertingthe CO of the raw syngas to CO2 (Eq. (1)). This was prior to acid gasremoval and was therefore termed as sour water–gas shift. Thisreaction was carried out in two sequential reactors.

COðgÞ þH2OðgÞ $ð44 kJ

moleÞCO2ðgÞ þH2ðgÞ ð1Þ

The dry-feed characteristics of the Shell gasifier required theinjection of a considerable amount of steam to ensure adequateCO to CO2 conversion rate during the SWGS. In order to protect

Fig. 1. The schematic configuration of the IGCC power plant with carbon capture.

Table 1Composition (% by weight) and heating values of the bituminous coal.

C 64.10 Moisture 10H 3.90 Ash 12.50N 0.70O 7.21S 1.50 kJ/kgCl 0.09 HHV 26,195F 20 ppm LHV 25,100

Table 2General assumptions for the ASU.

Delivery pressure/temperature of O2 by ASU (bar/�C) 1.2/10Delivery pressure/temperature of N2 by ASU (bar/�C) 5.0/10Main air compressor polytropic efficiency (%) 85GOX compressor polytropic efficiency (%) 78HP PGAN compressor polytropic efficiency (%) 78Inter-cooling temperature (�C) 40



the catalytic bed from carbon deposition as well as to increase theequilibrium conversion of CO and steam to H2 and CO2, the steam-to-CO ratio was set to 2.4. The IP steam for this purpose was partlysupplied from the syngas cooler and the rest was provided fromthe HP/IP steam turbine crossover. The inlet temperatures of bothreactors were set to 250 �C. The high temperature syngas leavingthe first reactor was quenched by saturating HP and IP boiler-feed-water (BFW) flows, while the warm syngas leaving the secondreactor was cooled by preheating the raw syngas entering the firstreactor and preheating HP and IP BFWs and generating low-pres-sure (LP) steam.

The resulting overall adiabatic conversion of CO to CO2 in theSWGS process was 98% (molar basis). The total pressure loss ofthe syngas from the exit of the wet scrubber to the exit of the dem-ister was 7.7%. It is worth noting that one of the advantages of thisunit is the simultaneous conversion of carbonyl sulfide (COS) tohydrogen sulfide (Eq. (2)) [29] with shift reaction.

COSðgÞ þH2OðgÞ $ð33:6 kJ

moleÞH2ðgÞ þ CO2ðgÞ ð2Þ

3.5. Carbonyl sulfide hydrolysis unit

In order to remove more than 99.99% of the sulfur content in theproduced syngas, it was necessary to add a COS hydrolysis unit toconvert COS to H2S in the case of CCS unit trip (Fig. 2), according toEq. (2) [30]. In this case, the scrubbed syngas was preheated to220 �C before entering the COS hydrolysis reactor. The syngasleaving this reactor was cooled down by preheating the scrubbed

syngas, LP steam generation, and IP BFW saturation. The conver-sion of COS to H2S in this reaction was 99.8% (molar basis).

3.6. Acid gas removal (AGR) unit

During the gasification process, the sulfur content in the rawcoal was converted to H2S and COS. However, most of the COS(more than 98%) was converted to H2S during the SWGS reaction.The pressure of the system, which was dictated by the gasificationprocess, resulted in high partial pressure of CO2 (around 15.5 bar).Therefore, two-stage physical absorption of acid gases, using di-methyl ether of polyethylene glycol (DEPG) also known as SEL-EXOL, was favorable for the AGR unit. High stability, high absorp-tion capacity as well as low corrosive effect, are the favorablefeatures of SELEXOL.

H2S was removed from the shifted gas in the first stage. The richsolvent exited at the bottom of the absorber column. Since the con-centration of CO2 in the syngas leaving the SWGS unit was high,and the order of magnitude of solubility of H2S and CO2 in SELEXOLwas similar, a considerable amount of CO2 content was co-ab-sorbed with H2S [31]. Having the appropriate content of H2S (morethan 35% molar basis) in the inlet stream of the Claus unit, whichwas used to oxidize H2S to elemental sulfur, a concentrator unitwas considered after the H2S absorber tower. A part of the fuelgas (�2.5%) produced in the AGR unit was recycled back to the con-centrator column as a stripping agent. The rich solution exiting atthe bottom of the concentrator column was then stripped off in aregenerator for which heat was provided by the LP steam gener-ated in the SWGS unit. The regenerated solvent was cooled to5 �C and recycled back to the H2S absorber. The separated H2Swas sent to a sulfur recovery unit including a Claus plant and aShell Claus off-gas treating (SCOT) plant for tail gas clean-up.

In the case of running the gas turbine with cleaned syngas (i.e.CCS unit trip and without the SWGS unit) the H2S concentrator col-umn was bypassed, since the concentration of CO2 was low in thesyngas leaving the COS hydrolysis unit. Fig. 2 illustrates the config-uration of IGCC power plant without carbon capture unit.

Syngas leaving the H2S absorber, after extraction of a small partof it for coal drying purpose, entered the second stage for CO2 re-moval. The removal process was similar to that in the first stage.The rich CO2 solvent was passed through four flash drums con-nected in series, where CO2 was released as a result of loweringthe pressure. The lean solvent leaving the last flash drum wascooled to 5 �C to increase the absorption efficiency. However, thiscooling increased the inherent loss of energy [29]. The cooled sol-vent was then re-circulated back to the absorber tower. The gasleaving the first flash drum was recycled back to the absorbertower. The CO2 released in flash drums two to four was sent forcompression. The CO2 removal rate in the AGR unit was 93.65%(molar basis), while the overall CO2 capture rate as defined in Eq.(3) was 89.80% (molar basis).

Capture rate ¼CO2sent to compression

þ CA þ CS

CF� 100 ð3Þ

where CA, CS, and CF are carbon content in fly ash, slag, and feed coal,respectively. The solidification of fly ash and slag took place in theplant and this was the reason for the relocation of these two termsfrom denominator to numerator in the above equation (Eq. (3)).

For cases when CO2 was not captured, the syngas leaving theCOS hydrolysis unit and the demister entered the H2S absorber.The rich solution leaving the bottom of the tower was regeneratedand the sulfur was stripped off using LP steam produced after theCOS hydrolyser unit. The H2S-free hydrogen-rich syngas exitingat the top of the absorber was passed to the GT combustor. The

Table 3General assumptions for the Shell gasification block including the syngas conditioningdownstream to the wet scrubber.

Dried coal moisture content (wt.%) 2Gasification pressure/temperature (bar/�C) 45/

1600Steam/coal ratio (kg/kg coal a.r.) 0.061O2/coal ratio (kg/kg coal a.r.) 0.7839HP PGAN/coal ratio (kg/kg coal a.r.) 0.241Power requirement (kJel/kg coal a.r.) 112Heat loss to membrane wall (% coal LHV) 2.5Carbon conversion (single pass/overall) (%) 99.3Syngas cooler pinch-point HP evaporator (�C) 30Syngas cooler pinch-point IP evaporator (�C) 64Heat exchanger heat loss (%) 0Pressure drop syngas cooler (gas side) (bar) 0.33Pressure drop wet scrubber (bar) 1Water pump mechanical efficiency (%) 85Shifted-desulfurized syngas for CMD in the case with CCS (% of total

flow)1.7

Shifted-desulfurized syngas for CMD in case of CCS unit trip (% oftotal flow)

1.5

Table 4Syngas composition (mole fraction) at the inlet ofSWGS unit.

Components Raw syngas

CO 0.4895CO2 0.0305H2 0.2268H2O 0.1751N2 0.0739H2S 0.0042COS (ppmv) 341NH3 (ppmv) 87



general assumptions and results of the AGR units for both cases, i.e.with and without CCS, are presented in Table 5 below.

3.7. CO2 compression

The CO2 released from the last three flash drums in the CO2 sep-aration process was compressed in a seven-stage intercooled com-pressor to 60 bar, liquefied and then pumped up to a final pressureof 150 bar. In order to reduce the corrosion risk in the transportpipeline, a dehydration unit using tri-ethylene glycol (TEG) wasconsidered. The upper limit of 20 ppm (mass basis) for water con-

tent in the CO2 stream was specified according to Ref. [32]. Thecompressor isentropic efficiency and pump polytropic efficiencyhave set to 80% and 70%, respectively.

3.8. Gas turbine model

The gas turbine was modeled using internal project informationexchange focusing on turbomachinery. This information includedinitial performance calculation results of a lumped turbomachin-ery model of the GT, Ansaldo Energia 94.3A, the compressor mapand some turbine data. All information used was based on a natu-ral gas fuelled engine. The control algorithm for burning undilutedH2-rich syngas and cleaned syngas was without any major modifi-cations, i.e. the same as for natural gas operation. The turbine inlettemperature (TIT) was fixed and set to 1331 �C, and the model ad-justed the pressure ratio due to the increased fuel flow. The currentGT model was built up accordingly:

Compressor model: The generated compressor characteristicsusing a lumped GT model were implemented with variable inletguide vane (VIGV) opening positions for ISO condition (i.e., 15 �C,1.01325 bar, 60% relative humidity).

Combustor model: The composition of fuel to the combustorwas calculated using the models described above (Sections 3.2–3.6). Furthermore, a pressure loss reflecting current state-of-the-art technology for dry low NOx combustors was used.

Turbine model: A simplified expander model was used, assum-ing a constant flow through the turbine. The influence of cooling airentering the turbine at different rows was considered, using a vir-tual/mixed turbine inlet temperature as well as virtual mixed poly-tropic efficiency according to the following equations:

Table 5General assumptions and results of both AGR units with and without CO2 capture.

CO2

captureWithoutCO2

capture

Syngas pressure/temperature at H2S absorber inlet(bar/�C)

39.7/25

39.7/25

Solvent pumps polytropic efficiency (%) 70 70Compressor isentropic efficiency (recycle gas) (%) 85 85Mechanical and electrical efficiencies (%) 98 98Coefficient of performance for refrigeration pump 2.2 2.2Solvent temperature at absorber inlet (�C) 5 5Pressure loss in 1st/2nd absorber (bar) 0.5/0.5 0.5/–H2S stripping duty (MWth) 44.7 22.0H2S removal efficiency (%) 99.99 99.99CO2 co-absorbed in H2S absorber (mol% of inlet) 1.32 12.62Overall H2 co-absorption (mol% of inlet) 2.19 0.02Overall CO co-absorption (mol% of inlet) 3.26 0.06CO2 removal efficiency(mol% of inlet) 93.65 12.62

Fig. 2. The schematic configuration of the IGCC power plant without carbon capture.



Tt mixed i ¼Pshaft

_mtotalcpþ T to ð4Þ

and

gt polytropic mixed ¼Cp

RD

lnðTtmixed i=TtoÞlnðpti=ptoÞ

ð5Þ

where T is temperature, P is power, _m is mass flow rate, cp is specificheat, g is efficiency, R is gas constant, p is pressure, and subscrip-tions i, o, and t are expander inlet, expander outlet and total condi-tion, respectively. The general assumptions for the GT including NGoperating conditions are listed in Table 6 below.

3.9. Heat recovery steam generator

Downstream of the GT was a three-pressure heat recoverysteam generator (HRSG) with reheat. The superheating (SH) tem-perature was set to 530 �C in order to meet both the GT exhausttemperature and the required amount of HP steam needed to besuperheated. Potential exists for further increasing the HRSG effec-tiveness in order to maximize the net electrical output. However,the economic feasibility of such optimization should not be disre-garded. The IP level was set to meet the pressure of the syngasleaving the wet scrubber, i.e. 43 bar, since a considerable amountof IP steam was extracted from the HRSG and mixed with theraw syngas in order to perform the SWGS reaction.

For the case without CO2 capture, the required amount of IPsteam is considerably lower compared to the cycle with CCS, dueto the bypassing of SWGS unit. The HP superheating temperaturewas lowered to 500 �C to accomplish the superheating of the entiresteam produced in the gasifier as well as the extra IP steam whichis not required in the process. The general assumptions made forthe HRSG calculation are listed in Table 7.

4. Simulation tools

To obtain reliable results and to utilize the possibility of incor-porating detailed component characteristics later, a combination ofthe following simulation tools was used for modeling the IGCCpower plant:

� Enssim: Simulation tool developed by Enssim Software [33];� ASPEN Plus: Commercial process engineering software by

AspenTech [34]; and� IPSEpro: Commercial heat and mass balance programme by

SimTech [35].

Data exchange between software tools was performed manu-ally to find the optimal match. The main reason for utilizing threesoftware tools was the specific capabilities of each tool to model acertain sub-system. To simulate each aforementioned sub-system(Section 3.1), the relevant one of these three software tools wasused as described below.

� Detailed modeling of the Shell gasification process, includingcomponents such as coal milling and drying (CMD), gasifica-tion, raw syngas cooling (SGC) and scrubbing (SGS), was per-formed by Vattenfall (Nuon) using the Enssim modeling tool.It is worth noting that the gasification model was validatedagainst real plant operational data.

� The air separation unit (ASU) was modeled using ASPEN Plus.The Peng-Robinson properties method was selected as theequation-of-state (PR EOS).

� The sour water–gas shift (SWGS) reaction was modeled inASPEN Plus using PR EOS.

� The acid gas removal (AGR) unit was modeled in ASPEN Plus.Two different equations-of-state, i.e., Peng-Robinson and Per-turbed-Chain Statistical Associating Fluid Theory (PC-SAFT),were used for simulation. However, based on a benchmarkingstudy with one of the industrial partners, the simulationusing PC-SAFT equation-of-state was selected.

� For cases without CO2 capture, the carbonyl sulfide (COS)hydrolysis unit and H2S removal (i.e. AGR unit) was modeledin ASPEN Plus using PR EOS and PC-SAFT EOS, respectively.

� The compression of captured CO2 and dehydration of CO2

stream was modeled in ASPEN Plus using PR EOS, and Sch-warzentruber and Renon (SR polar) equation-of-state,respectively.

� The power block including the GT, and the triple-pressuresteam cycle were modeled in IPSEpro.

5. Results and discussion

The overall objective of the H2-IGCC project is to enable the pre-mix combustion of undiluted H2-rich syngas in IGCC power plants.Developing an optimized plant layout that not only maximizes effi-ciency but also increases fuel flexibility by enabling the burning ofcleaned syngas with variable composition is another goal. The sys-tem analysis research group aims to evaluate and optimize theIGCC plant configuration. As an initial step toward optimizing theconfiguration of the plant, this group has established a realisticbaseline process layout. A detailed thermodynamic model using acombination of three simulation tools is presented in this paper.Performance analysis of the IGCC plant based on practical flow-sheet and realistic performance indicators is reported in this paper.

Simulation results of the baseline IGCC plant for two differentcases, i.e. with or without CO2 capture (referred to here as Case Aand Case B, respectively), based on calculations using modelsas described in Sections 3 and 4 are presented. Estimated

Table 7General assumptions used for the HRSG.

HP/IP/LP (bar) 140/43/4SH and RH temperature (�C) 530a

SH LP steam (�C) 300HP/IP/LP ST isentropic efficiency (%) 88.5/89/91ST and generator mechanical efficiency (%) 99.5Gas side HRSG pressure drop (bar) 0.04Condenser pressure (bar) 0.04Generator electrical efficiency (%) 98.2Pump polytropic efficiency (%) 70Pump mechanical efficiency (%) 95Evaporator pinch point IP/LP (�C) 10/10Super heater pinch point (�C) 32Economizer pinch point (�C) 10Approach point temperature (�C) 5

a The superheating/reheating temperature for the case without CO2 capture is500 �C; all other assumptions are the same.

Table 6General assumptions used for the gas turbine.

Ambient air pressure (bar) 1.013Ambient air temperature (�C) 15Moisture in air (%) 60TIT (�C) 1331GT outlet pressure (bar (total)) 1.08Pressure ratio 18.2Electrical/mechanical efficiency (%) 99/99.5NG mass flow (kg/s) 14.88GT power output fuelled with NG (MW) 292Turbine outlet temperature (NG fuelled) (�C) 577



performance indicators as well as specific CO2 emissions in bothcases are also reported. Performance indicators such as gas andsteam turbine power outputs, auxiliary power demands, and effi-ciencies of processes were validated against the results of feasibil-ity studies conducted by industrial partners of the project and theresults of published literature. The syngas compositions for bothcases are also reported. These compositions were validated againstpublished data. Some adverse effects of fuel change and the possi-ble measures for those are also briefly discussed.

The composition and other properties of the corresponding fuelgas in the two cases in this study, i.e. H2-rich syngas (Case A) and

cleaned syngas (Case B) prior to the gas turbine burner, are pre-sented in Table 8.

Estimated performance parameters of this simulation for CasesA and B together with corresponding operating conditions (pointsin Figs. 1 and 2) are shown in Table 9. The gas turbine power out-puts in both cases are higher than the power output of the NGfuelled GT (referred to here as Case C, see Table 6) which is approx-imately 292 MW [36]. This is due to greater hot gas flow in Cases Aand B than the Case C. It is worth noting that the current GT modelin all cases was using the compressor map based on NG as the fuel,and the component efficiencies were kept constant. The steam tur-bine power outputs for Cases A and B show a significant difference.IP steam consumption decreases in the absence of SWGS for Case B.This additional IP steam expands in the steam turbine to increasepower output of the steam turbine by 39 MW. Higher integrationof the HRSG and the SWGS in Case A results in 12.4% increase ofthe HRSG pumping power demand compared to Case B.

Simulation results confirm that the highest auxiliary powerconsumption is in the ASU for both cases (refer to Fig. 3). Solventflow in the AGR unit for Case A is higher due to CO2 capture. Thiscauses approximately 8.5 MW higher power demand for solventcirculation. Moreover, the higher solvent flow needs 6.8 MW morepower for its refrigeration. The total power demands for pumping,compression and refrigeration for H2S removal in both cases arerelatively small. These power demands are 7.65 MW and3.61 MW (about 0.36% and 0.69% of the respective gross thermal

Table 8Syngas composition (mole fraction) and characteristics prior to the GT burner.

Components H2-rich syngas Cleaned syngas

CO 0.0117 0.5984CO2 0.0403 0.0334H2 0.8583 0.2774H2O 0.0004 0.0005N2 0.0893 0.0904Pressure (bar) 38.71 39.21Temperature (�C) 30.0 30.0LHV (kJ/kg) 33255.55 11084.33HHV (kJ/kg) 39211.07 11656.48Mass flow (kg/s) 23.30 70.92Mole flow (kmole/s) 3.67 3.33

Table 9Performance results and operating conditions of the IGCC power plant with and without CO2 capture (Fig. 1 and 2).

Point # IGCC plant with CCS (Case A) IGCC plant without CCS (Case B)

T (�C) P (bar) _m (kg/s) T (�C) P (bar) _m(kg/s)

1 15.0 1.01 150.09 15.0 1.01 136.742 15.0 1.01 44.31 15.0 1.01 40.113 125.8 55.00 36.74 125.8 55.00 33.264 98.4 80.00 10.68 98.4 80.00 9.675 164.7 43.00 95.71 164.7 43.00 86.646 250.0 41.72 177.69 220.0 42.50 86.637 276.7 40.48 177.69 220.4 42.00 86.638 25.0 39.71 120.62 25.0 39.71 73.479 12.4 39.21 119.13 9.2 39.21 72.03

10 12.4 39.21 2.00 9.2 39.21 1.1111 33.8 150.00 93.19 4.4 39.71 121.9212 30.0 38.71 23.30 30.0 39.21 70.9213 15.0 1.01 683.01 15.0 1.01 682.9614 419.8 19.02 614.71 424.7 19.48 607.8415 1331.0 19.02 638.22 1331.0 19.48 678.7616 563.3 1.08 706.52 583.3 1.08 753.8917 530.0 140.00 145.62 500.0 140.00 118.6218 530.0 43.00 95.47 500.0 43.00 153.9819 241.6 4.00 114.67 206.7 4.00 150.5120 29.1 0.04 114.67 29.1 0.04 150.5121 314.0 43.00 78.39 263.2 50.00 3.2522 338.1 143.00 35.52 338.1 143.00 118.4223 337.0 140.00 130.82 337.0 140.00 118.4224 30.1 50.00 21.62 257.4 50.00 19.6125 31.3 141.00 95.30 329.8 43.00 118.6226 104.8 1.04 706.52 66.5 1.04 753.89

Performance indicators Case A Case B

GT power output (MWe) 329.22 311.27ST power output (MWe) 172.91 211.95HRSG pumping power demand (MWe) 3.53 3.14AGR pumping and compression power demand (MWe) 9.12 0.66AGR refrigeration power demand (MWe) 9.78 2.95ASU compression power demand (MWe) 50.02 45.45CO2 compression power demand (MWe) 20.83 0.00Gasification power demand (MWe) 4.96 4.48Net power out (MWe) 403.89 466.53Net IGCC efficiency (% LHV) 36.32 46.34Overall CO2 capture (%) 89.80 0.00Specific CO2 emissions (g CO2/kWh) 78.57 716.01



inputs) for Cases A and B, respectively. The total power demand forCO2 capture and compression for Case A is approximately32.1 MW, which is about 2.88% of the gross thermal input for thatcase. The net IGCC efficiency is 10% (absolute value) or 21.6% (rel-ative value) less for Case A than for Case B. This significant effi-ciency penalty for capturing CO2 is due to the auxiliary powerdemand of the SWGS unit and the CO2 capture and compressionunits. However, this loss in efficiency may be justified in futureIGCC plants by more stringent environmental regulations for CO2

emissions.Simulation results of some configurations of IGCC plants are

reported by other authors [22,32,37,38]. A brief comparison ofthe results of this work with a few others available in literatureis described and discussed in the following. The similarities anddeviations in results are explained for the validation of the presentwork as well as to gain insight for future improvements. Table 10shows a brief comparison of the specifications of sub-systemsand some performance parameters of this study with some othersavailable in literature. Even though the syngas used in this work isnot diluted with N2 as assumed by Kreutz et al. [38], Case B of thisstudy has about 1% lower efficiency. The cleaned syngas fuel wasstrongly (up to 350 �C) pre-heated before the combustor and theHRSG were fully optimized in Kreutz’s study. However, the net effi-ciency for Case A is closer to that reported by them. Some factors

have had increasing effects on the reported efficiency in the pres-ent study compared to Ref. [38]. These factors include: (a) Higherpower output from the GT due to using undiluted syngas; (b) lowersteam-to-CO ratio in the SWGS, which results in lower steamconsumption and higher steam bottoming power; (c) lower CO2

capture rate which implies lower loss; and (d) lower power de-mand in gasification block. On the contrary, the lower optimiza-tion/integration level of the HRSG in the current study is likely tocancel the increasing effects of the aforementioned factors. The dif-ferences in efficiencies are not significant when being comparedwith the overall plant efficiency. In another study, although fullintegration between the GT and ASU was considered (i.e. 100% ofthe air feeding the ASU is extracted from the GT), lower net effi-ciency (LHV basis) in both cases (6.4% for Case A and 2.4% for CaseB) has been reported by Kanniche et al. [32,37]. The steam injectioninto the GT for controlling NOx formation results in an efficiencypenalty in both cases. Having a similar low heating value comparedto that produced in Case B, the dilution with N2 in Case A has beenconsidered, which results in efficiency reduction. Also, the lowerpressure of the gasification block (27 bar) results in lower carboncapture efficiency and a higher energy penalty in the CCS unit.However, lower carbon capture efficiency results in lower steaminjection into the SWGS and a lower penalty for the bottoming cy-cle. Another study conducted by Chiesa and Consonni [22] reported

Fig. 3. The shares of auxiliary power consumptions for both cases (IGCC with and without carbon capture).

Table 10The main specification and performance results of published studies.

Sub-system/performanceindicators

Kreutz et al. [38] Kanniche et al. [32,37] Chiesa and Consonni[22]

Present study

Gasifier Shell technology O2 blown, dry fed based onPRENFLO technology

O2 blown, slurry fedbased on Texaco

Shell technology

38.5 bar 27 bar 60 bar 43 barASU N2 for dilution 100% integration with GT Non-integrated Non-integratedWGS type Sour Sweet Sour SourCO2 capture system SELEXOLTM SELEXOLTM SELEXOLTM SELEXOLTM

150 bar to storage 150 bar to storage 80 bar to storage 150 bar to storage93% Capture 85% Capture 91.7%% Capture 89.8% Capture

GT technology GE 9FB Siemens V 94.3 Generic F technology Siemens/AnsaldoEnergia 94.3A

Diluted with N2 and small amount of steam Diluted with steam for IGCCwithout CCS

Pre-heating (125 �C) Undiluted fuel

Pre-heating (350 �C for IGCC w/o CO2 capture &200 �C for IGCC plus capture)

Diluted with N2 and steam Saturation with steam

HRSG Triple pressure level Triple pressure level Triple pressure level Triple pressurelevel

Overall efficiency of IGCCwithout carbon capture

47.7% 43.9% 45.9% 46.3%

Overall efficiency of IGCC withcarbon capture

36.6% 29.9% 38.8% 36.3%



a net efficiency of about 45.9% for Case B which shows similar val-ues to this study. On the contrary, the net efficiency of Case A inChiesa’s study is approximately 2.5% higher compared to thisstudy. One reason is the utilization of the hydraulic expander forrecovery of solvent pumping power from CO2-rich solvent beforefirst flash drum in the AGR unit. Using a slurry fed gasifier at higherpressure (60 bar), which results in lower injection of IP steam tothe SWGS is also another reason for this efficiency difference.

The scientific literature confirms that the composition of thecleaned syngas based on Shell technology shown in Table 8 is with-in the range of those obtained from commercial gasifiers [30,39].The similar lower heating value of H2-rich syngas in the currentstudy and that of Ref. [22] (33.255 MJ/kg and 34.663 MJ/kg, respec-tively) shows a good agreement for every sub-system upstream ofthe GT. Even though in the study conducted by Zheng and Furinsky[30], the higher O2-to-coal ratio (0.9 instead of 0.78 in this study)and the higher O2 content in the coal result in lower CO in thecleaned syngas, the higher gasification temperature employed inZheng and Furnisky’s study (2000 �C instead of 1600 �C in thisstudy) led to similar CO and CO2 contents in both studies. Due tothe lower H2 content in cleaned syngas (Table 8), this fuel has low-er HHV and LHV compared to H2-rich syngas. The big difference incomposition, especially in H2 content, will certainly demand differ-ent combustor designs to maintain stable combustion. In addition,the large difference in the cleaned syngas flow compared to the H2-rich fuelled GT (70.9 kg/s compared to 23.3 kg/s), leads to the high-er turbine inlet flow and consequently higher back pressure. Clos-ing the variable inlet guide vane (VIGV) of the compressor willsolve this problem to some extent. However, keeping a reasonablesurge margin in the compressor and an acceptable efficiency over awider range of VIGV positions will require compressor modifica-tions. The turbine outlet temperature (TOT) is higher (583 �C) forCase B compared to Cases A (563 �C) and C (577 �C), which favorthe steam bottoming cycle. However, the higher TOT for thecleaned syngas fuelled GT than that of the NG fuelled one raisesone critical design concern, i.e. the lifetime of turbine components.It may lead to a considerable reduction in the lifetime, especially ofthe last and penultimate (un-cooled) stage blades of the turbine.This problem may be solved in several ways, such as by modifica-tion of the compressor and/or expander flow path, by blowing off apart of the compressed air and by modification of the operatingcondition (i.e. different TIT and VIGV position). Some changes inthe design of the combustor and turbomachinery block are inevita-ble in order to accommodate the switching of fuels (say, from H2-rich syngas to cleaned syngas) and the associated problems of thereduced lifetime of turbine blades. These may evolve with the fu-ture progress of the project.

6. Conclusion

The overall objective of the H2-IGCC project is to enable the pre-mix combustion of undiluted H2-rich syngas in IGCC power plantswith carbon capture. The object of the system analysis group of theproject is to evaluate and optimize the IGCC plant configuration. Asan initial step, simulation of a baseline configuration with a de-tailed thermodynamic model, using realistic assumptions andinternal information from other partners of the project, is reportedin this paper. This simulation will set the framework for techno-economic analysis in the next step for the commercial feasibilityassessment of the concept.

The estimated overall efficiency of the IGCC power plant with-out carbon capture is 46.3%. For the plant with carbon capture,the figure is 36.3%. This confirms the fact that a significant penaltyon efficiency is associated with the capture of CO2. This penalty is21.6% relative to the IGCC without CO2 capture. However, stricter

environmental regulations regarding CO2 emissions as well asthe requirement for a secured energy supply and the lack of maturealternatives may justify the IGCC technology with CCS in future.

Through comparison with other published studies, more inte-gration of sub-systems indicated some potential for better effi-ciency but with lesser reliability. Using undiluted syngas in theGT improves GT power significantly. However, some challenges re-lated to the unstable operating condition of the GT combustor andcompressor as well as reduced lifetime of the blades of the existinggas turbines when using undiluted H2-rich syngas have to be ad-dressed. Thus optimization of the plant needs more investigation.This study identifies these areas for future investigation and setsthe framework for techno-economic analysis in the next step ofoptimization involving commercial feasibility.

Acknowledgments

The authors wish to acknowledge Vattenfall and E.ON for theirtechnical inputs. The authors are also grateful to Han Raas at Vat-tenfall for performing the gasification simulations.

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147

Paper III

Estimation of performance variation of future generation IGCC

with coal quality and gasification process – Simulation results

of EU H2-IGCC project

Mohammad Mansouri Majoumerd, Han Raas, Sudipta De,

Mohsen Assadi

Published in Applied Energy, Vol. 113, p. 452-462, August

2013


Estimation of performance variation of future generation IGCC with coalquality and gasification process – Simulation results of EU H2-IGCCproject

Mohammad Mansouri Majoumerd a,⇑, Han Raas b, Sudipta De c, Mohsen Assadi a

a Faculty of Science and Technology, University of Stavanger, 4036 Stavanger, Norwayb Asset Development Division, Vattenfall, Westervoortsedijk 73, 6827 AV Arnhem, The Netherlandsc Department of Mechanical Engineering, Jadavpur University, Kolkata 700 032, India

h i g h l i g h t s

� Coal quality effects on the performance of four commercial gasifiers are reported.� The overall IGCC performance indicators using various coals are presented.� Dry-fed gasifiers are relatively insensitive to the coal quality.� Slurry-fed gasifiers are not suitable for the gasification of low-rank coals.


Article history:Received 14 January 2013Received in revised form 17 June 2013Accepted 21 July 2013Available online 23 August 2013

Keywords:IGCCGasificationDry-fedSlurry-fedCoal qualityPerformance

a b s t r a c t

The integrated gasification combined cycle (IGCC) power plant delivers environmentally benign powerfrom coal. The overall objective of the European Union (EU)’s H2-IGCC project is to develop and demon-strate technological solutions for future generation IGCC plants with carbon capture. As a part of the gen-eral goal, this study evaluates the effects of coal quality and the selection of gasifiers on the overallperformance of the baseline configuration of the IGCC plant. Four commercially available gasifiers i.e.,Shell, GE, Siemens, and ConocoPhillips gasifiers are considered for this comparative study. The effectsof three different types of coals on the gasification processes have been investigated, as well as the overallperformance of the plant. Simulation results show that slurry-fed gasifiers are not suitable for lignite coal,while dry-fed gasifiers are less sensitive to coal quality. Coal quality has the greatest effect on the GE gas-ifier. The ConocoPhillips gasifier demonstrates the highest cold gas efficiency using bituminous coal. Thecoal rank and the gasification process have relatively less effect on gas turbine power output, while steamturbine power output varies significantly with these. Although steam turbine power output increaseswith a reduction in coal quality, especially for slurry-fed gasifiers, the air separation unit power demandoffsets this increase. The highest overall plant efficiency is 37.6% (LHV basis) for the GE gasifier and coal B.The lowest overall efficiency penalty with coal quality is 5% (LHV basis) for the Shell gasifier with inputchanged from bituminous to lignite. Moreover, simulation results show that GE’s gasification technologyhas the highest CO2 emissions for lignite coal, i.e. 158 g/kWh.

� 2013 Elsevier Ltd. All rights reserved.

1. Introduction

The rapid growth of industry and population coupled with im-proved living standards has led to an ever-increasing demand onworld energy, more specifically for electric power. Fossil fuels,mostly coal, have been catering to most of this demand for somedecades. However, the ‘climate change’ problem [1] has forcedthe development of new technologies for fossil fuel based powerand utility heat supply. According to the International Energy

Agency (IEA), CO2 emissions from the electricity and heat supplysector amounted to about 41% of total global CO2 emissions fromfossil fuels in the year 2010 [2]. However, the IEA’s New PoliciesScenario suggests a 25% increase in coal consumption in the year2035 compared to the 2009 level. This increase will be 65% basedon the current policies scenario [3]. One of the key players withinthese policies is ‘Carbon Capture and Sequestration’ (CCS) accord-

ing to the European Energy Roadmap 2050 [4]. The deployment ofCCS in coal-fired power generation will ensure the growing shareof the coal consumption among other fossil fuels in the comingyears with more restricted emissions regulations.

0306-2619/$ - see front matter � 2013 Elsevier Ltd. All rights reserved.http://dx.doi.org/10.1016/j.apenergy.2013.07.051

⇑ Corresponding author. Tel.: +47 45391926; fax: +47 51 83 10 50.E-mail address: [email protected] (M. Mansouri Majoumerd).

Applied Energy 113 (2014) 452–462

Contents lists available at ScienceDirect

Applied Energy

journal homepage: www.elsevier .com/ locate/apenergy


Integrated gasification combined cycle (IGCC) has been identi-fied as an attractive coal technology which offers less expensivepre-combustion carbon capture than conventional plants withpost-combustion capture. Moreover, the IGCC technology providesopportunities for the production of steam, H2, and synthetic chem-icals such as Fischer–Tropsch fuels [5]. Effort is devoted to developIGCC technology as a possible good alternative power using coalbut lower CO2 emissions. Thermodynamic estimation of possibleimprovements of the performance of an IGCC plant with an en-trained-flow, dry-fed, oxygen-blown gasifier with hot gas desulfur-ization in comparison with conventional process has beendiscussed by Giuffrida et.al. [6]. They also reported thermodynamicperformance estimation vis-à-vis comparison through simulationbetween air-blown and oxygen-blown gasifiers for IGCC applica-tions [7]. Cost effectiveness of power from IGCC plants with respectto conventional coal fired plants and nuclear power plants againstthe backdrop of penalty of CO2 emission has been exhaustively ex-plored [8]. Results show relative advantages and disadvantagesdepending on several conditions of operation as well as regula-tions. With rapid growth of renewable energy, future coal basedpower plants may have to accommodate wide range of ratio ofrenewable and non-renewable power mix with efficient use of ex-cess power for some other utility using IGCC power plants. Simula-tion results of an IGCC plant integrated with CaO based CO2

absorption using Shell and Texaco gasifiers are analyzed to esti-mate the expected performance [9]. It was noted that though plantefficiency may be low (30–33%), CO2 capture may improve (�97%).Two innovative options for reducing the penalty in efficiency ofshell coal IGCC plants during CO2 capture are simulated and opti-mized by Martelli et al. [10].

With a distinct view towards the development of IGCC technol-ogy, the European Union has sponsored a well-integrated and coor-dinated research endeavor under its FP7 Framework ResearchProgram. Fifteen academic and nine industrial partners of the EUare involved in this H2-IGCC project to develop and demonstratea future generation IGCC plant with pre-combustion CO2 capture[11]. Four different sub-groups are working in well-defined andcoherent work packages towards this common goal. The simula-tion sub-group is working not only to achieve optimizationthrough detailed system analysis at different stages of develop-ment but also to ensure a realistic techno-economic evaluation.

Gasification plays the key role in an IGCC plant [12,13]. It notonly makes it possible to use coal or other solid fuels in an efficient

combined power cycle but also provides opportunities to capturemost of the pollutants, including CO2, efficiently. Employing propergasification technology is essential for optimizing the operation ofa future generation IGCC plant. Moreover, gasification performanceis significantly affected by coal quality. This quality varies widelydepending on the geographical location of coal source [14]. Highash, sulfur, chlorine, alkali metals etc. in addition to low heat valueand ash melting point are some typical characteristics of low qual-ity coals [15]. Unfortunately, about 53% of global coal reserves areof low rank, i.e. sub-bituminous and lignite [16]. Thus to explore auseful real-life future generation IGCC plant, the effects of the gas-ification process, as well as that of coal quality, on the performanceof the plant must be investigated. Several previous studies [17–21]have reported on IGCC plants using bituminous coals without anyreference to low rank coals.

In an effort to evolve the optimum IGCC plant configurationbased on data provided by other sub-groups of the H2-IGCC pro-ject, the simulation sub-group previously reported detailed simu-lation results for a baseline configuration of the IGCC plant asdeveloped in this project [22]. In this paper, subsequent simulationstudies on the effects of the gasification process as well as of coalquality on the performance of that baseline configuration are re-ported. Comparative performance evaluations of the gasificationprocess of three different types of coal, viz. bituminous, sub-bitu-minous and lignite in four different commercially available gasifi-ers are reported in this paper. Two coals typically represent lowrank coal and the results for these are compared with that for bitu-minous coal as reference. Subsequently, the performance evalua-tion is extended to the whole plant using the same coals andgasification technologies. The results of this work show some dis-tinct implications for the optimum configuration of the future IGCCplant that may evolve through subsequent studies of different sub-groups of the project.

2. Gasification and gasifiers for power generation

Conventional gasification is the process of conversion of a solidor liquid through sub-stoichiometric reaction with oxidants, eitherair or O2 at a temperature exceeding 700 �C to produce a syntheticgaseous product [23]. Compared to conventional pulverized coalfiring, gasification offers great opportunities for both higher effi-ciency and improved capture of pollutants. According to the flowgeometry, the commercial gasification technologies can be classi-

Nomenclature

AGR acid gas removalAr argonASU air separation unitC carbonCCS carbon capture and sequestrationCCU combined cycle unitCH4 methaneCMD coal milling and dryingCO carbon monoxideCOS carbonyl sulfideCO2 carbon dioxideEU European UnionGE General ElectricGT gas turbineHHV higher heating valueHP high pressureHRSG heat recovery steam generator

H2 hydrogenH2O waterH2S hydrogen sulfideIEA international energy agencyIGCC integrated gasification combined cycleIP intermediate pressureLHV lower heating valueNOx nitrogen oxidesN2 nitrogenO2 oxygenPFD process flow diagramSCGP Shell Coal Gasification ProcessSFG Siemens Fuel GasificationSOx sulfur oxidesST steam turbineSWGS sour water–gas shift



fied into three categories, viz. entrained-flow, fluidized bed, andmoving bed gasification technologies [24]. However, the need ofmodern power plants for large capacity gasifiers demands theshortest residence time and hence entrained-flow gasifiers arethe most favored for this purpose. Entrained-flow gasifiers allowhigh operating pressures (20–80 bar) and temperatures (1200–1600 �C). High operating temperatures enable a favorable slaggingprocess to remove ash and render gasification almost tar-free.These conditions are very desirable for large-scale power genera-tion. Hence, almost all the commercially useful coal gasifiers de-ployed for large-scale power generation are of the entrained-flowtype.

Although entrained-flow gasifier can process many varieties offeedstock e.g., high/intermediate/low quality coals, and heavy li-quid fuels [12,25], the feedstock characteristics significantly influ-ence the gasification performance and consequently theperformance of the whole IGCC plant [12,24,26]. The existing gas-ifiers show a substantial increase in cost combined with a drasticreduction in performance when operating on low-rank feedstocke.g., lignite coals [19]. Nevertheless, the utilization of such typesof coals can improve flexibility of supply and consequently im-prove the security of the energy supply [15]. The main parametersfor the selection of coal type for IGCC plant are ash content, slagviscosity, and coal reactivity.

The feedstock can be fed either wet (using slurry water) or dry(using N2 as a conveying gas) into the entrained-flow gasifier. Thehigh pressure and temperature environment of the gasifier facili-tates the gasification of the fed coal [27]. The released heat resultsin the melting of the ash content and the production of molten, in-ert slag. Meanwhile, the carbon content in the coal is convertedmainly to CO and H2 rather than to the normal products of com-bustion, CO2 and H2O, due to the reducing environment of the gas-ifier. The content of these products in the syngas depends heavilyon the gasifier lambda value (the fraction of stoichiometric O2 de-mand of the reactor when conceived as a partial oxidation burner).

Due to the high operating pressure and other advantages of theentrained-flow regime, this type of gasifier provides a high H2/COratio syngas and an inert slag. In the case of high rank coal, steamis added to the gasifier to moderate the temperature of the processwhile maintaining good carbon conversion. Under the extremelyhot condition, coal devolatilizes (pyrolysis) almost instantaneouslyinto gaseous elements like CH4, aromatics, CO2, CO, and solid charresidue (C).The volatiles formed are immediately combusted withthe supplied oxygen leading to an enormous rise in temperature.

Volatilesþ xþ 12

y� �

O2 ! xCO2 þ yH2O ð1Þ

Depending on the oxidant factor of the gasification process,either the volatiles consume all O2 in the equation or some excessO2 is left. In the case of there being no oxygen left after combustionof the volatiles, the following endothermic gasification reactions(Eqs. (2)–(4)) of residual char with the oxidants CO2 and H2O (socalled moderating agents) take place.

CþH2O$ COþH2 ð2Þ

Cþ 2H2O$ CO2 þ 2H2 ð3Þ

Cþ CO2 $ 2CO ð4Þ

These moderation reactions are relatively slow compared to thedevolatilization reaction (Eq. (1)) and cause a temperature drop. Inthe case where there is excess O2 after combustion of the volatiles,some of the residual char will be completely (Eq. (5)) or partiallycombusted (Eq. (6)) and release heat prior to moderation. Thesereactions (i.e. Eqs. (5) and (6)) are exothermic irreversiblereactions.

Cþ O2 ! CO2 ð5Þ

Cþ 12

O2 ! CO ð6Þ

Another important reaction is the gasification’s CO-shift reac-tion (Eq. (7)), which is an exothermic reaction to convert CO to CO2.

COþH2O$ CO2 þH2 ð7Þ

The methane content of the produced syngas is increasedthrough reactions (8) and (9) [23]. These are exothermic methana-tion reactions (below); however, they are more prevalent in gasifi-ers operating at lower temperatures. A higher gasifier pressure alsoincreases the methane content. In addition to the mentioned reac-tions, most of the sulfur content in the coal is converted to H2S,with a small fraction being converted to COS. Moreover, nitrogenis converted to ammonia in the reducing environment of the gas-ifier. This ammonia also breaks down into N2 and H2 in the hightemperature environment. A small amount of hydrogen cyanideis also produced.

COþ 3H2 $ CH4 þH2O ð8Þ

Cþ 2H2 $ CH4 ð9Þ

2.1. Gasifiers assumed for this simulation

The gasification of coal has gained special significance in thecontext of future generation IGCC plants. Several industrial re-search groups are developing coal gasifiers, specifically those ofthe entrained-flow type, on a commercial scale. Some of the lead-ing companies in the power sector have patented their technolo-gies in this field. To assess the significance of the process ofgasification on the performance of future generation IGCC plants,four common commercially-matured gasifiers with known specifi-cations have been used for this simulation. These are Shell CoalGasification Process (SCGP), General Electric (GE) gasifier (formerlyTexaco), Siemens Fuel Gasification (SFG), and ConocoPhillips (E-Gas™) gasifier. The main characteristics of these gasification tech-nologies are shown in Table 1. All of these gasifiers are oxygen-blown and entrained-flow type, each having some specific featuresas discussed below.

2.1.1. Shell Coal Gasification Process (SGCP technology)The SCGP gasifier typically operates at around 45 bar, with a

temperature range of 1400–1600 �C, well above the ash meltingpoint to ensure that molten ash has a low viscosity to flow easilyout of the gasifier [28,29]. Since it has a dry-fed system, no watermust be evaporated in the gasifier leading to high cold gas efficien-cies compared to (single stage) slurry-fed entrained flow gasifiers[29]. Coal is pulverized and dried to 2% residual moisture in a rollermill system featuring a hot drying gas recycle loop. Drying heat issupplied by an in-line burner in a hot drying gas recirculation loop,burning a small fraction of the cleaned syngas flow downstreamthe syngas desulphurization unit (1–2%). The dry, pulverized coalis subsequently pressurized using a lock-hopper system. The pres-surized coal is pneumatically fed to the gasifier in dense phasemode using pure nitrogen as a conveying gas. Gasifier lambda va-lue is low (0.30–0.33) which, at least for hard coal gasification,would lead to both unacceptably high gasifier working tempera-tures and low carbon conversion. To solve this problem, intermedi-ate pressure (IP) moderation steam is admixed to the gasifieroxygen feed in a ratio of typically 0.1 (kg steam/kg coal dust feed).When gasifying lignite, lambda values are high such that externalmoderation steam supply is not required. The raw syngas leavingthe gasifier is first rapidly cooled to around 900 �C by recycling



cooled, ash-free syngas. This cooling process is called dry quench-ing. The purpose of this type of quenching is to solidify the slagparticles and it is essential to reduce the fouling risk in the down-stream syngas cooler. The syngas is then further cooled to 340 �Cwhile generating high pressure (HP) and IP steam. Downstreamthe syngas cooler, the syngas is thoroughly dedusted in a filter sys-tem consisting of a cyclone and a ceramic candle filter in series.Part of the dedusted syngas (<10 mg/N m3 residual dust) is recy-cled to the dry quench section. The rest of the syngas is sent to awet scrubber upstream of the acid gas removal (AGR) unit for re-moval of halogens (Cl and F compounds), trace elements, and fineparticulate matter. The produced, fully dedusted and dehaloge-nized syngas is then sent to downstream sub-systems in the IGCCplant. There is currently one IGCC plant in operation using SCGPtechnology: the Vattenfall Buggenum IGCC plant in theNetherlands.

2.1.2. General Electric gasifierSimilar to the SCGP, the GE gasifier uses pulverized coal. How-

ever, in this case pulverized coal is mixed with water to produce aslurry feed. The typical range of slurry (ratio of solid to whole mix-ture) varies from 35 to 70 wt% depending on the coal’s characteris-tics [25,28,30]. The slurry type of gasifiers utilize a slurry pump tofeed the slurry into the gasifier enabling the process to have a high-er operating pressure compared to dry-fed systems (up to 70 bar).Lambda value is relatively high (0.40) caused by the fact that someCO and H2 burning is required to vaporize the slurry water. Thesyngas therefore shows relatively high contents of the productsof combustion (i.e. CO2 and H2O). The main disadvantage of thistechnology is the limited lifetime of the refractory and the associ-ated cost due to refractory replacement. Therefore, such plants aredesigned with a spare gasifier to enable them to achieve 90% targetavailability [19]. Contrary to shell process, slag and syngas leavethe gasifier co-currently at 1260–1480 �C.

Application of a dry quench system is not possible due to thelarge amount of slag that should be solidified. Instead, a radiantsyngas cooler is applied followed by a convective syngas cooler.

Both syngas coolers raise saturated HP steam. In between bothtypes of syngas coolers, the solidified slag is separated using awater quench bath for further quenching. Finally, the solidified slagis sluiced out of the gasification system. Syngas leaving the convec-tive syngas cooler then enters the scrubber before being sent to theAGR unit. In the current study, this type of cooling is used insimulations.

The type of syngas cooling described above is just one way ofcooling for GE gasifier produced syngas. Often GE type gasificationsystems are designed based on a so-called wet quench systemwhere syngas and slag leaving the gasifier are directly quenchedin a wet quenching system. The wet quench design consists of alarge water pool that cools the syngas and removes slag and ashparticles. The quenched raw syngas then enters a wet scrubber.The dry syngas cooling type of heat recovery results in a higheroverall plant efficiency and steam turbine (ST) power output com-pared to the wet quench design. However, a gasification systembased on a radiant/convective cooler is considerably more expen-sive than a wet quench design (by a factor of two).

The higher operating pressure compared to dry-fed gasificationsystem results in a smaller sized CO2 removal system and reducesthe corresponding cost. The water content of the syngas leaving thewet scrubber is relatively high compared to dry-fed gasifiers. Theproduced syngas needs a certain level of water content to carryout the CO-shift conversion at the sour water–gas shift (SWGS)unit and this level is controlled by the steam extraction from theheat recovery steam generator (HRSG) of the combined cycle unit(CCU). This extraction is, therefore, lower compared to dry-fed gas-ifiers [19].

There is presently one IGCC plant using the GE gasifier: theTampa Electric Polk IGCC power station in the USA.

2.1.3. Siemens gasifier (SFG technology)Similar to the SCGP, the SFG technology features a dry-fed sys-

tem which results in high cold gas efficiency [15]. Coal milling anddrying and pulverized coal dry-fed systems are similar to the onedescribed for the SGCP process. This technology is commercially

Table 1The main characteristics of investigated gasifiers.

Specification Shell Coal GasificationProcess (SCGP)

GE (formerly Texaco) Siemens fuel gasification (SFG) Conoco-Philips (E-Gas™)

Flow regime Entrained-flow Entrained-flow Entrained-flow Entrained-flowType of ash Slag Slag Slag SlagOxidant O2-blown O2-blown O2-blown O2-blownDry/slurry Dry-fed Slurry-fed Dry-fed Slurry-fedFeed type Pulverized coal Pulverized coal Pulverized coal Pulverized coalPressurization Lock hopper (pneumatic

feeding)Slurry pump Pneumatic feeding Slurry pump

Number of stages Single Single Single DoubleSlag removal

system(position)

Lock-hopper (bottom) Lock-hopper (bottom) Lock-hopper (bottom) Continuous pressure let-downsystem (bottom) [23]

Flow direction Upward flow Downward flow Downward flow Upward flowBoiler position Side-fired Top-fired Top-fired Side-firedQuenching type Quenching with recycle gas

and radiant coolerFull water quench, radiant cooler, andradiant/convective coolers

Built-in full water quench Two-stage gasification

Reactor type Membrane-wall typereactor [29]

Refractory-lined reactor Both membrane-wall type reactor andrefractory-lined reactor [31]

Refractory-lined reactor

Cold gasefficiencya

78–83% [29] 70–75% 75–80% [15] 78–83%

Carbonconversion

Above 99% [29] Above 96% Above 98% [31] Above 99% [35]

Tar formation Tar free Tar free Tar free Tar freeAvailability/

Reliabilitytargets

92%/96% [36] 88–90% (availability) [19] 90%/94%[32] 92% (availability)

a The definition of cold gas efficiency is presented in Section 5.



available with both reactor types, refractory-lined for lower ashcontent (<2%) and membrane-wall for higher ash content (>2%)[31]. The gasification temperature range is 1450–1750 �C [32]and the operating pressure is approximately 40 bar [33]. The SFGutilizes full wet quenching which results in a simple process com-pared to radiant or convective coolers and ensures optimal condi-tions for CO-shift conversion in the subsequent process unit (i.e.SWGS). In the current study, the quenching process is based onthe direct wet quench type.

The cooled and saturated raw syngas leaves the gasification is-land for the SWGS unit at a temperature of 220–230 �C [15].Though there is currently no full-scale SFG for IGCC application,the power market is increasingly showing interest in this type ofgasifier [31].

2.1.4. ConocoPhillips (E-Gas™) gasifierSimilar to the GE gasifier, this E-Gas™ gasifier is a slurry-fed

type [19]. However, this type of gasification has two stages of gas-ification and incorporates a proprietary slag removal system, charrecycle and syngas cooling schemes. Both gasification stages arefed with coal slurry and are provided with refractory inner walls.The operating pressure is around 40 bar [34]. Operating conditionsof the first stage gasifier resemble the one for the GE gasifier. How-ever, instead of co-current flow of slag and raw syngas in GE gas-ifier, the major part of the slag is kept separated from the rawsyngas flow by letting the slag flow to be quenched in a water bathlocated beneath the gasifier. In the second stage of gasifier, only avery little amount of oxygen is applied. Most of the gasification ofthe entering slurry is accomplished by the moderating agents, CO2

and H2O, present in relatively high concentration in the enteringsyngas from the first stage of the gasifier. Since gasification usingCO2 and H2O as the main gasifying agents is endothermic, the gas-ification of the slurry feed results in a large syngas temperaturedrop (from >1300 to 900 �C). This temperature drop also causesfly ash particles still present in syngas flow from the first stage gas-ifier to solidify, alike in the dry quench section of the SGCP. There-fore, this second stage gasifier is sometimes denoted as chemicalquench. The chemical quench results in a lower overall lambda va-lue and an improvement of cold gas efficiency. On the other hand,it reduces the available sensible heat transfer in the downstreamsyngas cooler [23]. Therefore, a radiant cooler is no longer needed.The second stage gasifier is less effective in carbon conversion thanthe first one. Therefore, a lower carbon conversion is assumed forthe second stage. A filter downstream the convective syngas coolerremoves the ash particles and unconverted carbon. Because of itshigh carbon content, the separated ash flow is recycled to the firstgasification stage in order to be gasified.

There is currently one IGCC plant using the E-Gas™ gasifier: theWabash River IGCC plant in the USA.

3. IGCC plant for this simulation

The impact of coal quality on the gasification process has beeninvestigated for the four assumed gasifiers. However, the principalobjective of the simulation sub-group of the H2-IGCC project is toexplore optimized configuration of the plant through simulationand using data available in open literature or from other grouppartners. Hence, the effects of coal quality and the gasification pro-cess on the performance of the baseline configuration of the plant,as reported in [22], are also investigated subsequently. The sche-matic of the IGCC configuration using the GE gasifier is shown inFig. 1. Details of this scheme (except the gasification unit) maybe obtained from [22]. However, a brief outline of the scheme isalso presented here. The plant consists of seven major sub-systemsas discussed below:

(1) Air separation unit (ASU): the cryogenic ASU is a stand-aloneunit generating O2 (95% purity) from air supplied by anintercooled main air compressor for the gasification of coal.This compressor is not integrated with the gas turbine of theCCU.

(2) Gasification island and syngas cooling and scrubbing: thegasification of the coal takes place in various O2-blown,entrained-flow gasifiers using technologies described in Sec-tion 2.

(3) Sour water–gas shift (SWGS) reaction unit: the SWGS pro-cess is the reaction used to convert the CO in the raw syngasto CO2 by shifting the CO with water over a catalytic bed(usually alumina supported cobalt molybdate) according tothe following equation:

COðgÞ þH2OðgÞ $44 MJ

kmol CO2ðgÞ þH2ðgÞ ð10Þ

(4) Acid gas removal (AGR) unit: a two-stage SELEXOL systemfor H2S removal and CO2 capture is used. Due to the highpartial pressure of acid gases, physical absorption of H2Sand CO2 is preferred to chemical, amine-based absorptionprocesses.

(5) CO2 compression and dehydration unit: the CO2 capturedfrom the process (90% capture rate) is compressed by anintercooled compressor, aftercoooled, liquefied and finallypumped up to a final pressure (150 bar). In order to reducethe corrosion risk in the transport pipeline, a dehydrationunit using tri-ethylene glycol is considered (H2O water con-tent in the captured CO2 line is less than 20 mg/kg).

(6) Gas turbine (GT): the GT block including compression, com-bustion, and expansion generates electric power using agenerator. Simulation has been performed using characteris-tics and boundary conditions of a gas turbine which isdesigned for combustion of the H2-rich fuel produced fromsub-systems 1–4.

(7) Heat recovery steam generator (HRSG) and steam cycle:downstream of the GT is a triple pressure HRSG (140 bar/530/530 �C) and steam turbine to generate steam and power.

4. Simulation tools and methods

In this study the performance of various gasification technolo-gies (refer to Section 2) using three different types of coal havebeen investigated. To obtain reliable results, the following softwaretools based on their specific capabilities were utilized for simula-tion of the entire IGCC plant:

� Enssim: simulation tool developed by Enssim Software [37];� ASPEN Plus: commercial process engineering software devel-

oped by AspenTech [38]; and� IPSEpro: commercial heat and mass balance program developed

by SimTech [39].

Data exchange between software tools was performed manu-ally to find the optimal match. The simulation of all sub-systems(refer to Section 3) except gasification block was performed usingcommercial tools, i.e. ASPEN Plus and IPSEpro. The relevant oneof these two software tools was used as described below:

� The ASU and SWGS reaction were modeled using ASPEN Plus.The Peng-Robinson properties method was selected as theequation-of-state (PR EOS).� The AGR unit was modeled in ASPEN Plus with Perturbed-Chain

Statistical Associating Fluid Theory (PC-SAFT) as the equation-of-state.



� The compression of captured CO2 and dehydration of CO2

stream were modeled in ASPEN Plus using PR EOS, andSchwarzentruber and Renon (SR polar) equation-of-state,respectively.� The power block including the GT, and the triple-pressure

steam cycle were modeled in IPSEpro.

The simulation of the gasification block was carried out usingthe Enssim tool. All simulations were static design calculationsfor all equipment. Gasification modeling started from a purelythermodynamic analysis of the process. Gasification kinetics wasnot included in the calculations. Nevertheless, chemical equilib-rium is attained for the most important equilibrium reactionsdue to the high operating temperatures at entrained flow gasifiers.Non-equilibrium conditions are taken into account by temperaturedifferences between actual and equilibrium temperatures for thevarious simultaneous gasification reactions. Realistic design dataand data for chemical equilibrium deviations for the Shell gasifierhave been deducted from the design and operational data of thewell-known Nuon (Buggenum) IGCC plant. It is worth noting thatthe dry-fed gasification model (based on the Shell technology)using this in-house tool was validated against real plant opera-tional data and design data for the Magnum plant gasifier (referto Table 3). In Tables 2 and 3 below, common input variable datafor validation of the model and a comparison of results providedby the gasification technology licensor and the Enssim tool aregiven.

As seen in Table 3, calculated syngas compositions are quiteclose. There is a relatively small difference in calculated GOX todry coal dust ratio. The relative difference in calculated gasifiercold gas efficiency is even smaller. Therefore, Enssim tool is

regarded as a reliable tool for fitting gasification data providedby the licensor.

The simulation of SCGP using this tool is given here as an exam-ple. For the SGCP process the Enssim tool was used to analyze thesubset of conceptual process flow diagram (PFD) consisting of coalmilling and drying section (CMD), the dry pulverized coal feedingsection and the gasification section. The latter section consistedof gasifier, dry quench section, syngas cooler section, dedustingsection, and wet scrubber section.

Coal

Stack

GE

Slag

Convective cooler

Particulate removal

SWGS

CO+H2O→ CO2+H2

SELEXOL

IP S

team

Sulfur by-product

CO2 to storage

AGR, CO2capture,

compression &

dehydration

Mak

e-up

w

ater

Particulates

O2

HRSG

Air

Generator

H2-

rich

syng

as

ASU

Air

Feed water

Generator

Syngas

(CO, H2)

Water

Slurry pump

Slurry tank

HP steam

HP

stea

m

Feed

wat

er

Fig. 1. The schematic configuration of the IGCC power plant with carbon capture (using GE gasifier).

Table 2Common input variable data for validation of the Shell gasification model.

Input data Value Remarks

Coal designation Drayton Bituminous Australian coalMoisture content dried

coal (kg/kg)0.02

Dry coal dust feedtemperature (�C)

80

Coal dust conveying N2

ratio (kg/kg)0.07 0.07 kg N2 needed to transport 1 kg of

dry coal dust (in pneumatic densephase mode)

O2 purity (mole%) 99.5O2 temperature (�C) 200Moderator steam/

burner feed ratio(kg/kg)

0.0769

Gasificationtemperature (�C)

1650

Relative heat transfer tomembrane wall (%)

2.0 As a percentage of gasifier coal feedthermal flow (LHV based)

Carbon conversion (%) 99.3



Calculations of the PFD for CMD included secant iteration blocksfor:

� Drying gas purge temperature, O2 content and relativehumidity.� Blending coal with fluxing agent in the CMD such that the

approach to the flow point of the resulting slag in the gasifier(100 K) was maintained.

Calculations of the gasifier were carried out using the followinginput design parameters:

� gasifier working temperature and pressure,� carbon conversion,� relative (to pulverized coal thermal input) heat transfer of the

membrane wall or refractory wall.

The chemical gasifier calculations first start with a calculationof slag, ash composition, and a first estimate of syngas composi-tion. It also takes into account the amount of CO2 resulting fromcalcination of limestone or dolomite if these minerals were addedas fluxing agents in the coal milling and drying unit. Subsequently,

sixteen simultaneous homogeneous equilibrium reactions alsoincluding sulfurous and nitrogenous compounds are used to equil-ibrate the initial syngas composition. These equilibrium calcula-tions are carried out in a secant iteration block which determinesthe gasifier lambda value to arrive at the design gasifier heat trans-fer for the given gasifier design operating temperature. For a num-ber of reactions, non-equilibrium situations were simulated usingapproaches to the equivalent equilibrium temperature. Followingthe gasifier computations all equipment downstream the gasifieris analyzed. In the end, the code outputs the syngas compositionat the outlet of the wet scrubber and outputs a list of ratios ofthe quantities demand mass flow rates, required and producedheat rates, power demands, production mass flow rates, and pro-duced power and the quantity fuel flow rate (as received) to theCMD.

To investigate the effect of coal characteristics on the perfor-mance of gasifiers as well as the power plant, three coals with var-ious characteristics including bituminous, sub-bituminous andlignite coals are considered in this work. It is evident from Table 4that these coals differ significantly in moisture, ash content, andheating value.

As previously mentioned, four different gasification technolo-gies such as SCGP, GE, SFG, and E-Gas™ were selected to assess

Table 4Composition and thermal properties of investigated coals.

Coal samplecode

Coal A(Bituminous)

Coal B (Sub-bituminous)

Coal C(Lignite)

Proximate analysis (wt%, dry basis)Moisture 10 27.40 31.24Ash 12.50 4.50 17.92Volatile matter 27.00 31.40 28.08Fixed carbon 50.50 36.70 22.76LHV (kJ/kg) 25,100 19,691 14,127HHV (kJ/kg) 26,195 20,469 14,682

Ultimate analysis (wt%, a.r.)C 64.10 50.25 36.27H 5.02 3.41 2.42N 0.70 0.65 0.71O 16.09 13.55 10.76S 1.50 0.22 0.64Cl 0.09 0.02 0.04

Main ash composition (wt%)SiO2 55.00 33.40 56.96Al2O3 24.00 16.30 19.01Fe2O3 5.50 5.20 3.49CaO 4.50 21.50 8.39

Table 5Technical variables for various gasification technologies.

Coal sample code Coal A Coal B Coal C

Shell Coal Gasification Process (SCGP)Operating temperature (�C) 1550 1550 1550Operating pressure (bar) 45.0 45.0 45.0Specific O2 demand (kg/kg coal a.r.) 0.773 0.549 0.419Specific moderator steam demand (kg/kg coal a.r.) 0.060 0.000 0.000Specific N2 demand (kg/kg coal a.r.) 0.232 0.186 0.170Carbon conversion (%) 99.3 99.3 99.3

GE gasifierOperating temperature (�C) 1450 1450 1450Operating pressure (bar) 60.0 60.0 60.0Slurry solid contents (wt%) 64.5 56.0 45.0Specific O2 demand (kg/kg coal a.r.) 0.881 0.708 0.721Carbon conversion (%) 99.0 99.0 99.0

Siemens fuel gasifier (SFG)Operating temperature (�C) 1550 1550 1550Operating pressure (bar) 45.0 45.0 45.0Specific O2 demand (kg/kg coal a.r.) 0.770 0.554 0.418Specific moderator steam demand (kg/kg coal a.r.) 0.060 0.039 0.000Specific N2 demand (kg/kg coal a.r.) 0.160 0.132 0.126Carbon conversion (%) 99.0 99.0 99.0

ConocoPhillips (E-Gas™) gasifierOperating temperature (�C) � 1st stage 1450 1450 1450Operating temperature (�C) � 2nd stage 991 991 991Operating pressure (bar) 43.0 43.0 43.0Slurry solid contents (wt%) 64.5 56.0 45.0Specific O2 demand (kg/kg coal a.r.) 0.712 0.548 0.586Carbon conversion � 1st stage (%) 99.0 99.0 99.0Carbon conversion � 2nd stage (%) 95.0 95.0 95.0

Table 3Comparison between gasification technology licensor and Enssim results for gasifiercalculation.

Quantity Licensor result Enssim result

Gasifier syngas composition (mole fraction)H2O 0.0205 0.0201H2 0.2851 0.2802CO 0.6327 0.6350CO2 0.0107 0.0112CH4 118a 101a

H2S 0.00313 0.00317N2 0.0462 0.0488Ar 885a 834a

HCl 99.5a 99a

NH3 120a 102a

COS 343a 244a

CS2 – 2a

S2 – 5a

HCN 120a 110a

C2H4 – 9a

GOX to dry coal dust ratio (kg/kg) 0.798 0.754Gasifier cold gas efficiency (%) 79.8 80.4

a The reported values are based on ppmv.

30.0

40.0

50.0

60.0

70.0

80.0

90.0

Coal A Coal B Coal C

Col

d ga

s ef

ficie

ncy

(%)

Coal type

SCGP

GE

SFG

E-GAS

Fig. 2. Effects of coal rank on cold gas efficiencies.



the gasification performance for different coals for the IGCC plantwith CO2 capture. The operating conditions and technical assump-tions used for simulation of investigated gasification technologiesare given in Table 5.

It is worth noting that the GT has been recently optimized for ahydrogen-rich fuel produced by the Shell Coal Gasification Processunder the H2-IGCC project’s framework. Hence, GT characteristics(e.g. turbine inlet temperature, compressor and expander’s isentro-pic efficiencies, combustion efficiency, compressor map, etc.) for allaforementioned gasification technologies are the same as the opti-mized GT for the Shell system. Thus, the fuel mass flow rates (forthe GT) and consequently pressure ratios vary depending on thefuel composition produced by each gasification technology.

As seen in Table 5, the operating pressure of the GE gasifier issignificantly higher than the one of the other gasifiers. To maintainthe GT fuel at a pressure level similar to that of the other IGCCplants using different gasifiers, an expander downstream of theAGR unit has been assumed for the IGCC plant using the GEgasifier.


Based on the objective of this work, results obtained from sim-ulation as described above are presented in this section in differentsubsections to describe the effects of coal quality and type of gas-ifiers on the process of gasification as well as possible overall per-formance of the baseline configuration of the plant [22].

5.1. Effects of coal quality on gasification

Coal properties that have significant effects on the gasificationprocess are mostly ash content, slag viscosity, and coal reactivity.A coal with low ash content is favorable for the IGCC power plantsince it produces smaller amounts of fly ash and bottom slag. It re-duces the risk of the plugging of exit pipes and the fouling of down-stream heat transfer surfaces [12]. Moreover, it also reduces coalfeed for the same amount of produced gas. The slag viscosity di-rectly determines the operating conditions of a gasifier. Althoughthe calculation of slag viscosity for the three coals assumed in thissimulation is a part of the gasification model, the detailed investi-gation of this topic is outside the scope of the present work. In thisregard, the slag viscosity is set to 25 Pa.s for the calculation of theamount of fluxing agent which, depending on the ash compositionof the coal to be gasified, is either basic limestone or refractory,acidic fly ash. The amount of oxidant agent is directly influencedby the gasification temperature which is determined by coal reac-tivity. To evaluate the effects of coal quality on the gasification pro-cess, two principal characteristics viz., cold gas efficiency and theproperties of produced syngas including its composition have beeninvestigated.

5.1.1. Coal quality and cold gas efficiency of gasifiersOne of the main parameters used to describe gasifier perfor-

mance is cold gas efficiency. This parameter indicates how muchof the energy input has been recovered as chemical energy in syn-gas [12]. The gasification efficiency (cold gas efficiency) is definedas:

ggasifier ¼LHVsgQ sg

LHVf Rfð11Þ

where ggasifier is the cold gas efficiency of gasification (%), LHVsg isthe lower heating value of the syngas (kJ/m3), Qsg is the volumetricflowrate of the syngas (m3/s), LHVf is the lower heating value of thecoal input (kJ/kg), and Rf is the gasifier coal consumption rate (kg/s).

The comparison between cold gas efficiencies for the investi-gated gasification technologies using three different coals is shownin Fig. 2.

According to Fig. 2, the coal quality significantly influences thegasification efficiencies of slurry-fed gasifiers i.e. GE and E-Gas™gasifiers. Amongst slurry-fed gasifiers, the coal quality has thegreatest impact on the GE gasifier. The cold gas efficiency of theGE gasifier with lignite coal is 29% lower than that of the same gas-ifier with bituminous coal. However, it is noted from Fig. 2 that uti-lization of the second-stage gasification in the E-Gas™ gasifierresulted in higher cold gas efficiency compared to the other slur-ry-fed gasifier, i.e. GE gasifier. Although the ash content of coal af-fects the cold gas efficiency of slurry-fed gasifiers, the lower ashcontent of coal B could not offset the lower dry solid content ofthe slurry compared to coal A. Therefore, the cold gas efficiencyis lower for coal B than for coal A. As observed from Fig. 2, coldgas efficiencies of dry-fed gasifiers are relatively insensitive tothe coal quality which is a significant advantage compared to slur-ry-fed gasifiers. The higher cold gas efficiency for coal B than thatfor coal A in SCGP and SFG gasifiers may be due to the lower ashcontent of coal B.

5.1.2. Coal quality and properties of raw syngas from gasifiersThe composition and characteristics of raw syngas produced by

different gasification technologies are presented in Tables 6 and 7.The presented data correspond to upstream of the sour water–gasshift unit.

Results of the simulation show that raw syngas from dry-fedgasifiers has higher CO and lower CO2 content compared to slur-ry-fed gasifiers. The higher water content in the slurry-fed gasifierresults in conversion of CO to CO2 and H2 through CO-shift reaction(refer to Eq. (7)). In addition, the higher rate of oxygen consump-tion in the GE gasifier (refer to Table 5, Section 4) compared toSFG and SCGP, caused by the need to evaporate the slurry waterin the gasifier, yields higher carbon dioxide in the raw syngas. Eventhough the O2 consumption for bituminous and sub-bituminouscoals is lower in the E-Gas™ than that in the SFG and SCGP, theCO2 content is higher in the raw syngas produced by the formergasifier. This is caused by more intense CO-shifting (refer to Eq.(7)) during gasification at a lower employed temperature in thecase of the E-Gas™ technology.

Results in Tables 6 and 7 show another important difference be-tween slurry-fed and dry-fed gasifiers for low-rank coals. The pro-duced syngas from gasification of lignite coal in slurry-fed gasifiersshows a very low heat value. Therefore, it demands higher feed-stock consumption to produce the same energy input for thedownstream GT block compared to other coals. Thus, slurry-fedgasifiers are unsuitable for lignite coal. On the other hand, thecapability of the dry-fed gasifiers to produce syngas from lignitecoal with relatively closer energy density to that from bituminouscoal obviously establishes them as better options for low-rankcoals.

The CH4 content from Shell, GE, and Siemens gasifiers is verysmall (ppm level). On the contrary, methane formation withinthe E-Gas™ gasifier is prominent. This is a result of the lower tem-perature employed in the second stage of this gasifier that favorsexothermic methanation reactions (refer to Eqs. (8) and (9)). Unlikethe other gasification technologies, the E-Gas™ gasifier also pro-duces some ethylene caused by the lower temperature of the sec-ond stage of gasification.

5.2. Effects of coal quality and gasifier on overall performance of theplant

Estimated performance parameters of the simulation for vari-ous gasification technologies using different coal quality are shown



in Tables 8 and 9. It is observed from these tables that the GTpower output does not vary much either with coal type or gasifica-tion technology. This is due to using the same GT technology withfixed characteristics in simulations. The major difference in thegenerator power output between different plants (i.e. using differ-ent gasification technology and coal quality) comes from the powerproduced by the steam turbine. The higher ST power outputs in GEand E-Gas™ technologies are due to the type of gasification pro-cess, i.e. slurry-fed. The higher water content of the produced syn-gas from these gasifiers not only reduces the steam extraction fromthe steam cycle required to achieve the desired CO conversionwithin the SWGS unit but also produces more steam in the syngascooler. Although the water content in the produced syngas fromthe Siemens gasifier is high due to the direct water quench, theST power output is not as high as slurry-fed gasifiers. The reasonis the production of HP steam within slurry-fed gasifiers which isabsent in the SFG technology.

It can also be seen from Tables 8 and 9 that the ST power out-puts for both dry- and slurry-fed gasifiers are increased by thereduction in coal quality. The combination of higher gasifier rawsyngas flow rates and the higher moisture content of slurry (byreduction in coal quality) results in a higher steam production insyngas coolers downstream of the gasifiers. However, an exception

is the SCGP for coal A and coal B. According to Table 6 (previoussection), due to the lower water content of the produced syngasfrom coal B, the steam extraction from the steam cycle should bemore compared to coal A to fulfill the SWGS reaction. This extrac-tion results in a lower ST power output in the case of coal Butilization.

The increase of ST power output for lower quality coal, how-ever, could not compensate for the increase of auxiliary power de-mand, more specifically for slurry-fed gasifiers. The highermoisture content combined with the increased ash content of coalC compared to coal A in slurry-fed gasifiers results in higher oxy-gen demand to maintain the gasifier temperature. Therefore, ASUpower demand is drastically increased for coal C compared to coalA. Results in Tables 8 and 9 confirm that the auxiliary power is in-

Table 7Composition and properties of produced syngas by SFG and E-Gas™ gasifiers (prior tothe SWGS unit).

Component (mol%) SFG E-Gas™

Coal A Coal B Coal C Coal A Coal B Coal C

Ar 0.45 0.41 0.42 0.53 0.51 0.51H2 14.23 14.97 12.85 20.83 20.73 14.85CO 32.27 30.87 30.14 26.99 25.86 12.80H2O 49.07 49.29 50.59 35.28 36.91 55.00CO2 0.53 1.69 2.40 11.81 12.33 15.51H2S 0.21 0.04 0.15 0.37 669a 0.18COS 779a 135a 587a 93a 16a 31a

NH3 134a 147a 134a 984a 936a 631a

N2 2.56 2.64 3.33 0.75 0.69 0.87CH4 339a 205a 106a 2.30 2.01 0.20C2H4 0.00 0.00 0.00 1.01 0.79 150a

Pressure 43.3 43.3 43.3 41.7 41.7 41.7Temperature 210.7 211 212.1 192.7 194.8 213.7HHV (MJ/kg) 6.90 6.70 6.15 8.34 7.83 3.87LHV (MJ/kg) 6.57 6.36 5.86 7.75 7.27 3.55


Table 6Composition and properties of produced syngas by SCGP and GE gasifiers (prior to theSWGS unit).

Component (mol%) SCGP GE

Coal A Coal B Coal C Coal A Coal B Coal C

Ar 0.71 0.66 0.67 0.70 0.62 0.62H2 23.29 23.80 20.35 22.97 20.67 10.61CO 50.04 50.92 48.61 34.16 25.43 9.82H2O 16.38 15.46 18.29 30.23 39.25 59.94CO2 2.45 2.05 3.62 10.78 13.31 18.18H2S 0.42 794a 0.31 0.04 608a 0.17COS 436a 84a 353a 250a 28a 73a

NH3 203a 213a 193a 152a 34a 47N2 6.56 6.78 8.07 0.66 0.62 0.64CH4 237a 781a 781a 651a 239a 7a

Pressure (bar) 43.0 43.0 43.0 58.1 58.1 58.1Temperature (�C) 161.4 159.1 165.7 199.7 212.2 232.7HHV (MJ/kg) 10.14 10.34 9.19 7.93 6.29 2.66LHV (MJ/kg) 9.64 9.83 8.77 7.43 5.85 2.44


Table 8Performance results of IGCC plants using SCGP and GE gasifiers.

Parameter SCGP GE

CoalA

Coal B CoalC

CoalA

Coal B CoalC

GT power (MW) 324.0 323.61 326.3 317.6 318.60 334.2ST power (MW) 176.6 163.79 177.8 221.7 273.49 330.2Expander powera (MW) 0.0 0.0 0.0 1.0 1.0 1.2Generator power output

(MW)500.6 487.4 504.1 540.3 593.1 665.5

Gasification powerdemand (MW)

4.9 6.1 8.5 4.0 5.6 12.9

ASU compression powerdemand (MW)

48.9 46.4 54.7 54.5 61.0 142.3

Syngas compression andpumping powerdemand (MW)

10.8 10.7 11.3 9.0 9.2 16.0

AGR refrigeration powerdemand (MW)

8.5 11.3 11.3 11.1 11.2 25.8

CO2 compression powerdemand (MW)

20.4 20.2 21.6 20.6 21.8 36.3

HRSG pumping powerdemand (MW)

3.4 3.43 3.7 3.9 4.33 4.2

Auxiliary power demand(MW)

97.0 98.1 111.1 103.2 113.1 237.4

Net power output (MW) 403.6 389.4 393.0 437.1 480.1 428.1

a This value is related to the output power of the gas expander upstream of theGT for the GE IGCC.

Table 9Performance results of IGCC plants using SFG and E-Gas™ gasifiers.

Parameter SFG E-Gas™

CoalA

CoalB

CoalC

CoalA

Coal B CoalC

GT power (MW) 320.3 320.5 321.1 318.6 318.46 330.5ST power (MW) 170.0 174.5 183.5 186.3 201.22 287.9Generator power output

(MW)490.3 495.0 504.6 504.9 519.7 618.3

Gasification powerdemand (MW)

7.6 9.8 14.5 3.8 5.0 9.1

ASU compression powerdemand (MW)

47.0 45.5 52.0 43.6 43.6 84.0

Syngas compression andpumping powerdemand (MW)

10.6 10.8 11.3 11.5 11.7 15.1

AGR refrigeration powerdemand (MW)

19.4 20.4 49.8 10.5 10.7 22.8

CO2 compression powerdemand (MW)

20.0 20.0 21.5 20.1 20.5 27.3

HRSG pumping powerdemand (MW)

2.4 2.4 2.4 3.0 2.94 3.6

Auxiliary power demand(MW)

107.0 108.9 151.6 92.4 94.5 162.0

Net power output (MW) 383.3 386.2 353.0 412.6 425.2 456.3



creases with low coal quality. This is primarily due to the increas-ing oxygen demand but also because of the increasing CO2 contentwhich should be captured and compressed. The oxygen consump-tion, which is an important factor to give an indication of the cap-ital cost of the ASU, is shown in Fig. 3.

The effect of coal rank and gasification technology on the ther-mal efficiency and the net heat rate (the reciprocal of netefficiency) of the IGCC plant with CO2 capture is shown in Fig. 4.It is obvious that the coal quality significantly influences the over-all plant efficiency. It is noted from Fig. 4 that the slurry-fed GEgasifier is more affected by the low-rank coal C compared todry-fed systems (i.e. SCGP and SFG). The other slurry-fed gasifier,the E-Gas™, is less sensitive to the coal quality. This is due to betterutilization of the input feedstock with the second gasificationstage. As mentioned previously, the lower overall plant efficiencyfor various gasification technologies using coal C is primarily dueto decreased gasification efficiencies.

It can be seen from Fig. 4 that the overall plant efficiency for coal Bis higher than that for coal A in both GE and E-Gas™ gasifiers. Multi-ple reasons contribute to the mitigation of the impact of the rela-tively lower cold gas efficiency for coal B compared to coal A (referto Fig. 2) on power plant net efficiency. These are as follows:

(a) The ash content of coal B is lower compared to coal A, whichresults in a low difference between the dry and ash-free solid con-tent of both coals. It should be noted that this fraction of coal, i.e.the dry and ash-free solid content, provides the required energyto vaporize the slurry water; (b) coal B raises more HP steam inthe syngas cooler than coal A; and (c) the produced syngas fromthe gasification of coal B is more pre-CO-shifted than syngas fromcoal A due to the higher water content. This leads to less exergyloss in the SWGS section. The higher CO conversion (refer to Eq.(7)) also results in higher plant efficiencies for coal B in slurry-fed gasifiers compared to dry-fed gasifiers.

Fig. 5 shows CO2 emissions from the IGCC plant using differentgasification technologies and for various coal qualities. Althoughthe carbon content of the coal principally determines CO2 emis-sions from the IGCC plant, the use of dry-fed gasifiers and the E-Gas™ shows a relatively constant trend for different coal qualities.In terms of CO2 emissions of the plant, the GE technology, amongstvarious gasification technologies, does not appear to be the correctoption for gasification of lignite coal (i.e. coal C).

6. Conclusions

The EU’s H2-IGCC project is aiming to develop and demonstratetechnological solutions for future generation IGCC plants with car-bon capture. In the current study, under the framework of the pro-ject which aims for the evaluation and optimization of the bestplant configuration, the effects of coal quality and the selectionof gasifiers on the overall performance of the baseline configura-tion of the IGCC plant have been reported. Four commercially avail-able gasifiers from Shell, GE, Siemens, and ConocoPhillips havebeen considered for this comparative study. The effects of threedifferent types of coals on these gasifiers, as well as on the overallperformance of the IGCC plant, have been investigated. Given thefact currently there is not any operating IGCC power plant withcarbon capture, the validation of the overall system performanceis not feasible. However, utilization of validated tools and modelsagainst existing plant data for simulation of different IGCC sub-sys-tems in this study has resulted in more reliable results. Severalconclusions can be inferred from the results as follows:

(1) The coal quality considerably influences the cold gas effi-ciency for slurry-fed gasifiers i.e. GE and ConocoPhillips gas-ifiers. Amongst slurry-fed gasifiers, the coal quality has thegreatest impact on the GE gasifier. The cold gas efficiencyof the GE gasifier gasifying lignite coal is 29% lower than gas-ifying bituminous coal. On the contrary, dry-fed gasifiers arerelatively insensitive to the quality of the input coal.

(2) Results confirm that one of the main advantages of dry-fedgasifiers compared to slurry-fed types is a relatively con-stant quality of produced syngas even when low-rank coalis gasified.

(3) The higher water content of the produced syngas fromslurry-fed gasifiers increases the ST power output due toreduction of the steam extraction from the steam cycle forthe SWGS reaction. However, this power increase cannotcompensate for the increase of ASU power demand andresults in lower system efficiency for low-rank coal.

(4) The overall performance of the whole IGCC is slightlyaffected by the GT performance using different syngas com-positions from various gasification technologies. However,

Fig. 3. Oxygen consumption of different gasification technologies with various coalqualities.

Fig. 4. Effects of coal rank and gasification technology on the IGCC plant efficiencyand heat rate.

Fig. 5. Effects of coal rank and gasification technology on the CO2 emissions of theIGCC plant.



paper findings including characteristics of the inlet syngas tothe gas turbine are very important in terms of the GT design.

(5) Summarizing, slurry-fed gasifiers in this study, i.e. GE andConocoPhillips, are suitable for bituminous and sub-bitumi-nous coals, while dry-fed gasifiers, i.e. Shell and Siemens,show a relatively constant behavior for a wider range of coalquality.

Acknowledgments

The authors are grateful to the European Commission’s Direc-torate-General for Energy for financial support of the Low EmissionGas Turbine Technology for Hydrogen-rich Syngas (H2-IGCC)project.

References

[1] IPCC. IPCC fourth assessment report: climate change 2007 (AR4); 2007.<http://www.ipcc.ch>.

[2] IEA. IEA Statistics 2012 Edition: CO2 emissions from fuel combustionhighlights. Paris: International Energy Agency; 2012.

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high temperature and high pressure coal gasification. Appl Energy2012;92:279–85.

[6] Giuffrida A, Romano MC, Lozza GG. Thermodynamic assessment of IGCC powerplants with hot fuel gas desulfurization. Appl Energy 2010;87(11):3374–83.

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carbon capture for the co-production of hydrogen and electricity. Int J HydrogEnergy 2010;35:556–67.

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electricity and CO2 from coal with commercially ready technology. Part A:performance and emissions. Int J Hydrogen Energy 2005;30:747–67.

[19] Holt N, Booras G, Todd D. A summary of recent IGCC studies of CO2 capture forsequestration. In: Gasification technologies conference2003: San Francisco,CA, USA.

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[22] Mansouri Majoumerd M, De S, Assadi M, Breuhaus P. An EU initiative for futuregeneration of IGCC power plants using hydrogen-rich syngas: Simulationresults for the baseline configuration. Appl Energy 2012;99:280–90.

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[27] Parulekar PS. Comparison between oxygen-blown and air-blown igcc powerplants: a gas turbine perspective. In: ASME paper GT2011-45154. ASME TurboExpo, Vancouver, Canada; 2011.

[28] Maurstad O, Herzog H, Bolland O, Beér J. Impact of coal quality and gasifiertechnology on IGCC performance. In: 8th international conference ongreenhouse gas control technologies (GHGT8), Trondheim, Norway; 2006.

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2003.


161

Paper IV

Fuel change effects on the gas turbine performance in IGCC

application

Mohammad Mansouri Majoumerd, Mohsen Assadi

Presented at 13th International Conference on Clean Energy

(ICCE 2014), Istanbul, Turkey, June 2014

1

FUEL CHANGE EFFECTS ON THE GAS TURBINE PERFORMANCE IN IGCC APPLICATION

Mohammad Mansouri Majoumerd1, Mohsen Assadi1,2

1Faculty of Science and Technology, University of Stavanger, 4036 Stavanger, Norway 2International Research Institute of Stavanger (IRIS), P.O. Box 8046, 4068 Stavanger, Norway

E-mail: [email protected]; [email protected]

ABSTRACT Improved security of energy supply by utilizing clean coal technology with and without CO2 capture results in changed fuel composition at integrated gasification combined cycle (IGCC) plants. Gas turbine modifications might be therefore necessary to cope with such changes. As part of the H2-IGCC project, a European Union co-funded project, this study presents a detailed analysis of the effect of using various fuel(s) compositions on the performance of the selected gas turbine in IGCC plants considering different operating conditions. For realistic analysis of the gas turbine behavior, component characteristic maps were generated and implemented into a detailed thermodynamic model in a commercial heat and mass balance program, IPSEpro. The fuels studied in this paper are undiluted hydrogen-rich syngas (i.e. 87 mol% H2 content), clean syngas (without CO2 capture), and natural gas. The impact of the fuel change on the gas turbine performance has been investigated and the results are presented and discussed in this paper. Moreover, technical solutions for realization of the targeted fuel flexibility under certain limitations and boundary conditions are presented. Calculation results show that for the given boundary conditions, the surge margin of the compressor was slightly reduced when natural gas was replaced by H2-rich syngas. The use of clean syngas instead of H2-rich syngas resulted in a considerable reduction of the surge margin and elevation of the turbine outlet temperature at design point conditions, when keeping the turbine inlet temperature and compressor inlet mass flow unchanged. In order to maintain the exhaust temperature and improve the surge margin, when operating the engine with clean syngas, a combination of adjustment of variable inlet guide vanes and reduced turbine inlet temperature was finally considered. Results of this study confirm that using clean syngas requires major gas turbine modifications such as air bleed from compressor outlet and multiple fuel feed systems. Key words: IGCC, gas turbine, performance analysis, fuel flexibility, hydrogen-rich syngas, clean syngas 1. INTRODUCTION The world’s demand for electricity is ever increasing mainly due to the population growth and improved living standards. Currently, the share of electricity generation is 37% of the global primary energy consumption. In 2012, the global electricity production was 22,126 TWh [1] with an annual average growth rate of 2.95 % from 1990 [2]. Fossil-based electricity production accounted for 68 % of the total generation and coal, the most carbon-intensive fossil fuel, was the largest contributor (41%) to the electricity supply in 2012 [1]. For future, electricity demand is projected to grow more rapidly than the total energy consumption [3, 4]. This demand will be almost 70 % higher in 2035 than the current demand [5]. On the other hand, needs to reduce greenhouse gas (GHG) emissions require considerable efforts to be directed towards the utilization of clean power generation technologies. The emissions of CO2 from the electricity and heat supply sector using fossil fuels were about 42% of the total global CO2 emissions in the year 2011 [6]. Several options should be considered in a comprehensive package to reduce the global GHG emissions per unit of energy consumption. Amongst those options are energy conservation and efficiency improvement, transformation/replacement of carbon-intensive fossil fuels by cleaner technologies (such as switch from coal to natural gas (NG), enhanced use of renewable energy sources and utilization of nuclear energy) and reduction of CO2 emissions using carbon capture and storage (CCS) for fossil-based energy. The integrated gasification combined cycle (IGCC) has been one of the most promising coal-derived technologies in terms of higher efficiency and lower environmental impact, compared to conventional pulverized coal plants [7]. In addition, the well-established high temperature coal gasification technology may facilitate the control and reduction of gaseous pollutants ( e.g. NOx and SOx) to the level of NG-fuelled plants [8]. Furthermore, using IGCC provides one of the least costly approaches for CO2 abatement through pre-combustion carbon capture [8, 9]. However, one of the largest barriers towards widespread utilization of the IGCC technology is its higher capital costs compared to a conventional pulverized coal plant [10, 11]. In addition, the high H2 content in the syngas derived from coal gasification (more specifically when a pre-combustion CO2 capture unit is considered in the cycle) complicates the application of pre-mixed burners, which is the current state-of-the-art (SOA) technology in NG-fired gas turbines (GTs) [12]. The restriction of using such burners is the flammability limits of H2-rich fuels, which are much larger than that for natural gas [13]. Moreover, high hydrogen content syngas has higher adiabatic flame temperature, higher flame speed, and higher flashback potential compared to NG, which complicate its pre-mixed combustion [14, 15]. For this reason, high NOx emitting diffusion burners have been employed for the existing IGCC power plants, which require the hydrogen-rich syngas to be diluted with nitrogen or water/steam to control the higher adiabatic flame temperature. The other persistent challenge in the IGCC plants is the variation in composition and heating value of the produced syngas, which needs to be combusted in the downstream GT. This variation is mainly due to the varying feedstock quality [16], and the process and operational causes (e.g. switch from a plant with CO2 capture to a non-capture mode).

2

Several studies highlighted the effect of varying composition of a specific type of fuel. Nag et al. investigated the effects of using different compositions of liquefied natural gas (LNG) on gas turbine operation. They found that change of lower heating value (LHV) and composition of the concerned fuel (i.e. LNG) may lead to increased emissions and different component lifetime [17]. Chishty mainly studied the combustion and corresponding design challenges in the combustor when using different fuels [18]. Experiences concerning the continuous use of different fuel composition, rather than switching fuels during operation, have been also investigated in various papers from original equipment manufacturers (OEMs) [19-21]. In addition to the areas covered in the publications mentioned above, the operation of an IGCC plant with pre-combustion CO2 capture, burning undiluted hydrogen-rich syngas, raises other matters of increased importance, such as the requirement for secure electricity production, which could be threatened by various disturbances. Compared to standard combined cycles, a H2-rich fuelled IGCC power plant has a complex plant layout with an increased number of components. Consequently, a higher probability of disturbances, such as failure or planned maintenance of the components/sub-systems of the cycle could be expected in such a plant. A changed operational window might also be caused by economic reasons, e.g. when CO2 capture is not beneficial due to low prices on the CO2 trading markets resulting in the bypassing of the CO2 capture unit. Furthermore, bypassing the CO2 capture unit will result in an overall higher power output, which requires efficient operation of the plant under these operating conditions. As a consequence, the GT should cover a wide range of fuel types from undiluted H2-rich fuel (as the design fuel) to low-LHV gaseous fuels (in the case of burning clean syngas) and also natural gas (as the back-up fuel) [21]. These fuels have different composition and LHV, which result in a different volume flow and consequently the mass flow into the combustor to reach the same order of turbine inlet temperature (TIT) and thereby similar efficiency level for a given compressed air flow [22]. Change of fuel flow rate affects the compressor/expander matching [13], induces higher back pressure to the compressor [12], and reduces available surge margin [22] if no adjustments are implemented to compensate for the mass flow change. Therefore, it is necessary to adjust the operational parameters of the gas turbine in such a way that a safe operation with reasonable performance can be offered. Given all these technological challenges, a secure provision of electricity using a fuel-flexible gas turbine with high operational flexibility is an essential need in IGCC power plants [23]. In 2009, the H2-IGCC project was co-funded by European Union to develop knowledge that would allow the use of SOA gas turbines in the next generation of IGCC power plants with deployment of CO2 capture. The overall objective of the project was to enable the stable operating conditions of the GT with pre-mixed combustion of undiluted H2-rich syngas. The secondary objective was to increase the fuel flexibility without adversely affecting the reliability and availability of the entire system by minor modifications to existing GTs [24]. As part of the H2-IGCC project, this work presents the consequences of fuel change on the performance of the gas turbine at various operating conditions. The main objective is to see whether the targeted fuel flexibility or ability to operate on a variety of fuels (i.e. H2-rich syngas, non-captured clean syngas and natural gas) is achievable under presumed boundary conditions and limitations or not. In this paper, the baseline configuration of the selected IGCC plant with and without CO2 capture unit is briefly presented to provide an overview of the entire cycle’s layout. This will assist the readers for better understanding of how the fuel properties are affected by different operational/process changes (or disturbances). The effects of fuel change on the performance of the selected gas turbine, as an isolated sub-system, are then assessed. Accordingly, different operating conditions and adjustments to mitigate the negative effects of fuel change are thoroughly investigated and discussed followed by necessary modifications/strategies to minimize the negative effects of fuel change during the lifetime of a gas turbine in IGCC application. 2. THE SELECTED IGCC CONFIGURATION In order to investigate the impact of fuel change on the gas turbine performance, it is essential to have the expected fuel properties and composition prior to the GT. For this purpose, a baseline IGCC plant with and without CO2 capture unit has been established and thermodynamically analyzed. For better understanding of the process change from the IGCC plant with CO2 capture to a plant without capture, the plant description is briefly presented in this section. However, detailed technical assumptions and specification for modeling of the entire IGCC plant may be obtained from authors previous publication [25]. It should be noted that the fuel compositions in both cases, i.e. the plant with capture (H2-rich syngas) and the plant without capture have been adopted from a previous study [25]. 2.1. The selected IGCC plant with CO2 capture The block flow diagram of the IGCC plant with capture unit is shown in Fig. 1. The feedstock considered for the selected IGCC plant is bituminous coal. The plant consists of seven major sub-systems as explained below: (1) Air separation unit (ASU): the cryogenic ASU is a stand-alone unit generating O2 with 95% purity from air supplied by an intercooled main air compressor (MAC) for the gasification of coal. The main advantage of non-integrated ASU is higher plant availability, operability, and flexibility. However, notably is that the overall plant efficiency increases with the degree of integration between ASU and the gas turbine compressor due to the higher isentropic efficiency of the GT compressor [26]. Nevertheless, lower efficiency of the non-integrated GT-ASU case could be balanced with selection of an intercooled MAC. Often for IGCC plants either syngas dilution with N2 or steam or syngas saturation with water is considered to control the NOx emissions from diffusion flame burners. However, here this strategy has been

3

eliminated due to the use of undiluted pre-mixed combustion of the H2-rich syngas. As there is no need for injection of diluent gaseous nitrogen into the GT for dry-low NOx combustion, heat integration between the GT compressor bleed air and diluent nitrogen from the ASU is not an option in order to enhance the overall plant efficiency.

To Sulfur recovery

Coal

O2

Air

Slag

Shift

reactionGasification

Air

separation

unit

Stack

To atmosphere

AirGas turbine

HP IP/LP

Heat recovery steam

generator

Acid gas

removal

CO2

capture

CO2

compression &

dehydration

H2-rich syngas

CO2

Fig.1. The block flow diagram of an IGCC power plant with CO2 capture

(2) Gasification island and syngas cooling and scrubbing: the gasification of coal takes place in an entrained-flow, oxygen-blown, dry-fed gasifier based on the Shell Coal Gasification Process (SCGP). Such a technology was selected due to its high cold gas efficiency and its operating pressure level. A key parameter governing the overall plant pressure is the operating pressure of the GT combustor. The pressure prior to the combustion chamber was fixed at about 30 bar to overcome the pressure loss over the fuel valves and required turbulent conditions for pre-mixed combustion. The pressure of the gasification block was then calculated to be at 45 bar considering all pressure losses from the gasifier to the combustion chamber for eliminating any supplementary syngas compression. The selection of the SCGP technology was also justified by availability of a validated gasification model provided by the operator of the Buggennum IGCC plant within the H2-IGCC project consortium. The validation results are available in [27]. (3) Sour water-gas shift (SWGS) reaction unit: the SWGS process converts the CO in the raw syngas to CO2 by shifting the CO with water over a catalytic bed according to the following reaction:

𝐶𝑂(𝑔) + 𝐻2𝑂(𝑔)(44

𝑀𝐽

𝑘𝑚𝑜𝑙𝑒)

↔ 𝐶𝑂2(𝑔) + 𝐻2(𝑔) (1)

(4) Acid gas removal (AGR) unit and CO2 capture unit: a two-stage SELEXOL system for H2S removal and CO2 capture was used. Due to the high partial pressure of acid gases, physical absorption of H2S and CO2 is preferred to chemical, amine-based absorption processes. The H2S is removed by a counter-current flow of solvent in the first stage. The syngas leaving the H2S absorber enters the second stage where the CO2 is captured. The overall CO2 capture rate is approximately 90% (molar basis). (5) CO2 compression and dehydration unit: the CO2 captured from the process is compressed by an intercooled compressor, aftercooled, liquefied and finally pumped up to a final pressure of 110 bar. In order to reduce the corrosion risk in the transport pipeline, a dehydration unit using tri-ethylene glycol is considered resulting in water content in the captured CO2 line less than 20 mg/kg. (6) Gas turbine: the GT block including compression, combustion, and expansion generates electric power using a generator. The GT model is further discussed in Section 3. (7) Heat recovery steam generator (HRSG) and steam cycle: downstream of the GT is a triple pressure level HRSG with reheat (140bar/530/530°C) and a steam turbine to generate steam and power. 2.2. The selected non-capture IGCC plant In the plant without CO2 capture, the water-gas shift reaction is bypassed and the raw syngas leaving the wet scrubber is passed through a COS hydrolysis unit before entering the H2S absorber. Fig.2 illustrates the block flow

4

diagram of the non-capture IGCC plant. In order to remove more than 99.9% of the sulfur content in produced syngas, it is necessary to add the COS hydrolysis unit to convert the COS to H2S [8]. In addition to this change, few other sub-systems of the plant with capture should be out of operation such as CO2 capture unit (i.e. the 2nd absorption stage), CO2 compression and dehydration unit. The H2S-free syngas exiting the top of the H2S absorber is then sent to the GT combustor.

Coal

O2

Air

Slag

COS

hydrolysisGasification

Air

separation

unit

Stack

To atmosphere

AirGas turbine

HP IP/LP

Heat recovery steam

generator

Acid gas

removal

To sulfur recovery

Non-captured, clean syngas

Fig.2. The block flow diagram of an IGCC power plant without CO2 capture

3. METHODOLOGY This work aims to investigate the effects of fuel change on the performance of a selected gas turbine under various operating conditions in IGCC application. It should be noted that the consequences of fuel change and necessary adjustments to the IGCC plant are not covered in this study. However, it was necessary to simulate the entire IGCC system with and without capture unit to reach the composition of different fuels upstream of the gas turbine. For this purpose, simulation results of the selected IGCC plant available in the recent publications by the authors have been used [25, 27]. Detailed modeling of the gasification process, based on the Shell Coal Gasification Process (SCGP) including coal milling and drying, gasification, raw syngas cooling and scrubbing, has been performed by Vattenfall (Nuon) using an in-house model in the Enssim software, which validated against operational data from Buggenum power plant [28]. The modeling of upstream and downstream units of the gasification block, such as the air separation unit, the sour water-gas shift reaction unit, the acid gas removal unit, the CO2 compression and dehydration unit, and the COS hydrolysis unit has been performed using ASPEN Plus [29]. Details of the thermodynamic models of the aforementioned units are also available in [25, 27]; hence, are not repeated here. A special emphasis is dedicated to the gas turbine in this study. The thermodynamic model of the GT has been established using IPSEpro, a heat and mass balance software [30]. This model is briefly discussed in the following sub-section. 3.1. Gas turbine model In order to investigate the effects of fuel change from NG, which is the design fuel for the GT, to undiluted H2-rich syngas for the IGCC plant with CO2 capture and clean syngas for the non-capture IGCC plant, a reference GT design should be selected. Accordingly, a Siemens SGT5-4000F/Ansaldo Energia V94.3A type of gas turbine was selected as the manufacturers being partners of the H2-IGCC consortium. Using a one-dimensional lumped model, detailed engine specifications including the main GT components characteristics maps were generated for NG as fuel and made available for the system modeling and simulation. An advanced thermodynamic GT model in IPSEpro software was then modified followed by model validation against performance data published by the manufacturer [31]. The main components of the gas turbine model are described below: (1) Compressor model: The compressor map generated by aforementioned lumped model, provided by Roma Tre University (refer to Fig.3), has been implemented into the thermodynamic compressor model in IPSEpro software tool as look-up tables. The axes’ labels in Fig.3 are not shown for reasons of confidentiality. The look-up table contains the changes of pressure ratio, corrected inlet mass flow, and isentropic efficiency based on corrected rotational speed. The effect of the variable inlet guide vane (VIGV) on aforementioned parameters (i.e. look-up table’s parameters) was also considered. However, the limited dimensions (i.e. number of rows and columns) of such a table, implemented in IPSEpro, are among limiting factors affecting the accuracy of the information retrieval from the look-up table.

5

(a)

(b)

Fig.3. The compressor characteristics maps, (a) pressure ratio versus corrected mass flow and (b) isentropic efficiency versus pressure ratio

In terms of compressor stability, surge margin calculation has been incorporated into the compressor model. Surge is defined as a transient condition involving reverse flow through the compressor path and can occur when the pressure ratio increases beyond a safety margin. The surge margin is defined as:

𝑆𝑢𝑟𝑔𝑒 𝑚𝑎𝑟𝑔𝑖𝑛 (%) =𝑃𝑅𝑠𝑢𝑟𝑔𝑒−𝑃𝑅𝑜𝑝𝑒𝑟𝑎𝑡𝑖𝑜𝑛

𝑃𝑅𝑜𝑝𝑒𝑟𝑎𝑡𝑖𝑜𝑛× 100 (2)

(2) Combustor model: The fuel composition entering the combustor was obtained from system simulation reported in previous publication [25] based on the IGCC plant described in Section 2. To achieve realistic results, pressure losses reflecting the current SOA combustor technology were used. (3) Expander model: Once H2-rich syngas or non-captured syngas is used as the GT fuel in the existing GT (i.e. SGT5-4000F/Ansaldo Energia V94.3A) designed for NG operation, the operating conditions and performance of the GT deviates from the original design. Therefore, an off-design analysis was required in order to provide information about necessary changes. A simplified off-design model has been considered for modeling the expander. The turbine off-design operation was modeled assuming a constant swallowing capacity at choking condition, which is a reasonable assumption for heavy duty gas turbines:

Swallowing capacity = Constant = ��𝑖√𝑇𝑖

𝜅 𝐴𝑖 𝑝𝑖 (3)

𝜅 = √𝛾𝑖

𝑅𝑖(2

𝛾𝑖+1)

𝛾𝑖+1

𝛾𝑖−1 (4)

As shown in Eq.3, the syngas flow rate at the expander inlet is proportional to the square root of the temperature. In a GT designed for NG, once the fuel flow rate is increased due to the change of fuel composition and LHV different components and operating conditions might be affected such as expander lifetime and the compressor stability. The influence of the cooling air entering the turbine at different rows was considered using a virtual/mixed turbine inlet temperature and a virtual/mixed polytropic efficiency according to the following equations:

𝑇𝑡𝑚𝑖𝑥𝑒𝑑 𝑖 =𝑃𝑠ℎ𝑎𝑓𝑡

��𝑡𝑜𝑡𝑎𝑙 𝑐𝑝+ 𝑇𝑡𝑜 (5)

𝜂𝑡 𝑝𝑜𝑙𝑦𝑡𝑟𝑜𝑝𝑖𝑐 𝑚𝑖𝑥𝑒𝑑 =𝑐𝑝

𝑅𝑜 𝑙𝑛 (𝑇𝑡𝑚𝑖𝑥𝑒𝑑 𝑖

𝑇𝑡 𝑜⁄ )

𝑙𝑛(𝑝𝑡𝑖

𝑝𝑡0⁄ ) (6)

In order to simplify the GT model, the effects of fuel change on the amount of cooling flows required to maintain the blade wall temperature at certain level was not considered at this stage. Therefore, it was assumed that the cooling flows were unchanged when the fuel composition was altered.

Pre

ssure

ratio [

-]

Corrected mass flow [-]

IGV 100% IGV 90% IGV 80%

IGV 70% IGV 60% IGV 50%

IGV 47%

Isentr

opic

effic

iency

(%)

Pressure ratio

IGV 100% IGV 90% IGV 80%

IGV 70% IGV 60% IGV 50%

IGV 47%

6

Table 1. Technical assumptions for GT modeling at design condition


Air flow at the compressor inlet kg/s 685 Pressure ratio - 18.2 Cooling flow 1st expander stage kg/s 83.7 Cooling flow 2nd expander stage kg/s 52.7 Cooling flow 3rd expander stage kg/s 26.9 Shaft cooling kg/s 13.7 Compressor isentropic efficiency % 88.2 Combustor outlet temperature ᵒC 1500 Turbine inlet temperature ᵒC 1266 Expander isentropic efficiency % 92.1 Expander total inlet pressure bar 17.9 Expander static outlet pressure bar 1.1 Mechanical efficiency % 88.7 Generator electrical/mechanical efficiency % 99/99.5

Sizing of the entire IGCC plant is governed by the gas turbine as it requires a specific amount of fuel depending on the fuel properties and composition. The operating condition of the GT is determined by matching the operating characteristics of the compressor and the expander. Thus, if the gas flow rate varies at the expander inlet, e.g. due to the change of syngas composition, the operating condition of the GT adapts to this change. This could result in change of pressure ratio even at similar firing temperature. The technical assumptions for GT modeling at its design condition (NG-fired) are presented in Table 1. 3.2. Boundary conditions For modeling of the gas turbine, ISO standard conditions have been considered. The ambient air conditions and composition are shown in Table 2.

Table 2. Ambient air composition and conditions

Components Unit Value

H2O wt% 0.63 N2 wt% 75.10 O2 wt% 23.01 Ar wt% 1.21 CO2 wt% 0.05

Ambient air pressure bar 1.013 Ambient air temperature °C 15 Relative humidity % 60

The investigated fuels in this study included (A) natural gas, (B) H2-rich syngas, and (C) clean (non-captured) syngas. The corresponding composition and characteristics of each fuel based on the previously described plants’ layouts and thermodynamic models in sections 2 and 3 are given in Table 3.

Table 3. Composition a and characteristics of investigated fuels

Components Fuel A (NG)

Fuel B (H2-rich syngas)

Fuel C (clean syngas)

wt% mol% wt% mol% wt% mol%

CO 0.0 0.0 5.4 1.2 79.7 60.4 CO2 0.4 0.1 24.1 3.3 5.6 2.7 H2 2.6 17.9 28.9 86.8 2.7 28.1 H2O 0.0 0.0 0.1 0.0 0.0 0.0 N2 0.0 0.0 41.5 8.7 12.0 8.8 CH4 93.0 80.6 0.0 0.0 0.0 0.0 C3H8 4.0 1.3 0.0 0.0 0.0 0.0

Pressure (bar) 30 30 30 Temperature (°C) 30 30 30 LHV (MJ/kg) 49.7 35.3 11.3

To evaluate the impact of the fuel change on the selected gas turbine technology in IGCC application, various simulation setups with different boundary conditions such as TIT, turbine outlet temperature (TOT), etc. have been considered, as shown in Table 4. As mentioned earlier, the reference GT was chosen as being NG fuelled. However, it should be mentioned that the target of the H2-IGCC project is a plant operated with H2-rich fuel (without major changes to the original gas turbine design) and NG operation is only considered as backup. The clean syngas (non-captured) operation is considered as an off-design alternative when the carbon capture unit is bypassed.

7

Table 4. Different setups for investigation of the fuel change effects on the gas turbine performance

Parameter Case I Case II Case III Case IV Case V

TIT (°C) 1266 Calculated 1266 Calculated Calculated VIGV Fully open Fully open Calculated Fully open Calculated PR Calculated a 18.2 18.2 Calculated 18.2 TOT (°C) Calculated Calculated Calculated 577 577

In addition to those parameters marked as ‘Calculated’ in Table 4, other variable parameters including GT gross power, GT efficiency, and the surge margin were also studied. The simulation results are presented and discussed in the next section. 4. RESULTS AND DISCUSSION The main focus of this study was evaluation of the impact of fuel change on the GT performance. In this section, A, B, and C represent different fuels, namely NG, H2-rich syngas, and clean (non-captured) syngas, respectively. The effects of different parameter setups listed in Table 4 are the same for the NG-fired gas turbine, as these parameters are the design parameters of the reference engine. Therefore, the effect of varying operating conditions on NG-fired GT is only reported as Case A.

Fig.4. Effect of fuel change on relevant performance parameters

at fully open VIGV and constant TIT

Fig.4 shows the effect of fuel change on relevant performance parameters, such as pressure ratio, gross GT power, TOT, fuel flow, and surge margin when the TIT is kept constant and the VIGV is fully open. Change of fuel from NG to H2-rich syngas, when keeping the VIGV fully open and TIT constant (A to BI), increases the pressure ratio by 0.6 over the compressor. The pressure ratio of Case CI increases by 1.3 compared to the reference Case A. The reasons for pressure increase in both cases are the higher fuel mass flow in combination with unchanged compressor air flow, which leads to an increased total mass flow through the turbine, to maintain the TIT unchanged. When using H2-rich syngas, the power output increases compared to the NG operation due to the higher hot gas flow rate through the expander at a constant TIT (i.e. 1266 °C). This is because of the higher enthalpy drop through the expander due to the higher H2O content in the H2-rich syngas and also in the flue gas according to [13]. Comparison of the gross power output for all cases, presented in Fig.4, shows that operating with H2-rich fuel (Case BI) results in the highest power output, 311.6 MW, which is 7% higher than the NG-fired case, i.e. 291.2 MW. Operating with the clean syngas at a similar setup (Case CI) shows 5% higher gross power output than for the reference case. Nevertheless, Case CI delivers 6 MW less power compared to Case BI due to changing hot gas composition and properties, such as lower H2O content. One of the major design concerns for the engine lifetime is the TOT. This indicator is not affected very much by the fuel change from NG to H2-rich syngas. However, the marginally lower TOT for Case BI compared to that for Case A will result in an insignificant drop of power output from the steam cycle downstream of the GT. Despite the increased pressure ratio for Case CI compared to the NG-fired GT (A), 10 °C higher TOT (587 °C) is observed for Case CI. Higher TOT would lead to considerable reduction of the lifetime of the last expander stage. The fuel flow increases with fuel change from NG to H2-rich syngas from 14.9 kg/s to 21.9 kg/s due to the lower calorific value of the H2-rich fuel compared to NG. The fuel mass flow difference becomes significantly higher for the case with clean syngas fuel reaching 69.3 kg/s. Referring to the IGCC cycle, where the CO2 capture unit

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has been bypassed, the syngas production rate increases even though the amount of coal remains unchanged. This is mainly related to changed details inside the overall fuel gas treatment/preparation process. Concerning the surge margin, which is mandatory to ensure stable operation of the compressor, a relative reduction of 22% is observed when using H2-rich fuel instead of NG. However, the remaining surge margin would still be sufficient. Operation of the engine with clean syngas at the same operating setup (i.e. CI) results in a relative reduction of the surge margin by 50%, which brings the compressor close to the surge limit.

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Fig.5. Different gas turbine modifications to reduce fuel change effects

In remedy of the main problems caused by switching from NG to clean syngas (and to some extent to H2-rich syngas), such as unstable operation and reduced lifetime of the turbine blades, various options might be considered. These options are illustrated in Fig. 5 and described below. Modification of the control rules Running the GT safely under different combinations of VIGV, pressure ratio, TIT and TOT is usually an appropriate option. In order to solve the problem of increased pressure ratio and reduced surge margin when the GT is operated on H2-rich and clean syngas, the second and third parameter setups, i.e. Case II and III (refer to Table 4) are considered. The corresponding results to the fuel change effect on various performance indicators using aforementioned simulation setups are shown in Fig.6. Keeping the pressure ratio at its design value (i.e. 18.2) and VIGV fully open results in significant reduction of TIT and thereby GT efficiency drop, which is more pronounced for Case CII compared to that for Case BII. As shown in Fig.6, the gross power output for both H2-rich syngas and clean syngas operations decreases for parameter setup II. The gross power outputs of Case BII and Case CII are reduced by 8.6 and 57.1 MW, respectively compared to that of NG-fired GT (Case A). The negative effect of this parameter setup is not limited to the GT block alone. The TOT also significantly drops for Case BII (533 °C) and Case CII (522 °C) compared to Case A (577 °C) leading to lower overall plant efficiency due to the reduced steam cycle efficiency and power output.

9

Fig.6. Effect of fuel change on relevant performance parameters (at fixed PR)

Parameter setup III (fixed TIT and PR), which is considered to see the effect of VIGV position on the performance of the GT, shows no improvement. It is also evident that such a setup is not useful to keep the necessary margin to the surge condition (refer to Case BIII and Case CIII in Fig.6). Compared to Case A, the surge margin is reduced by 30% and more than 50% even though the VIGV is closed by 9% and 20% for cases BIII and CIII, respectively. In addition, TOT increases considerably at setup III for both H2-rich syngas and clean syngas by 4 and 20 °C, respectively. To avoid unstable operational conditions, to reduce power output, and to eliminate the risk of reduced lifetime of the expander last stage blades in Case C (clean syngas), the parameter setups IV and V (refer to Table 4) are also considered. The TOT of the GT is fixed at its design value for NG-fired case (i.e., 577 °C). It should be noted that simulation results for Case BIV and Case BV are not shown in Fig.7 since none of them offer better performance compared to BI. However, the results relevant to clean syngas operation are shown in Fig.7. Obviously, parameter setup IV would be a better solution due to the increased surge margin and power output compared to setup V. Although, the gross power output of the GT increases for Case CIV compared to Case A, the surge margin is still very low and shows 42% reduction compared to the NG-fired GT.

Fig.7. Effect of fuel change on relevant performance parameters (at fixed PR and TOT)

Modification of the compressor flow path In order to reduce the air mass flow, while keeping the pressure ratio close to the design value, the following alternatives (shown as Mc in Fig.5) could be considered:

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Mc1: Modification of the first compressor stator vanes to reduce the air mass flow. This modification would also

change the last stage height rather extensively. Moreover, a ballast flow (N2 or steam) has to be injected when H2-rich syngas is used as fuel (which has a higher LHV compared to non-captured syngas) into the combustor. The flow of the ballast needs to be reduced, when the LHV of the fuel gas decreases and the syngas flow increases (e.g. at clean syngas operation). Mc2: The addition of one or more rear stages to the compressor with adapted clearances to allow the reduction of the compressed air mass flow rate when the pressure rises. An intrinsic internal flow control would be required to maintain the high pressure while the mass flow reduces. However, it would result in reduced compression efficiency and consequently in reduced GT efficiency. In general, this option would result in a lower penalty to the GT efficiency and stable operating conditions. However, this requires major modifications to the compressor and expander as well as adjustment of the vanes’ and blades’ cooling paths. Mc3: In order to compensate for the increased fuel mass flow when a syngas with low calorific value is used, a fraction of the compressed air could be discharged at the compressor outlet. A loss of efficiency is foreseeable if an internal use of compressed air is not considered. The most efficient use of the bleed stream is in the ASU. The integration of the GT compressor and ASU would reduce the power demand of the main air compressor and slightly increase the overall plant efficiency. However, as mentioned previously, this integration has not been considered within the H2-IGCC project as it results in reduced plant availability. Modification of the expander flow path The other option to reduce the effect of fuel change is to modify the expander. The expander nozzle guide vanes (NGVs) could be re-staggered (shown as Me in Fig.5) to increase the swallowing capacity of the expander. The vane and blade cooling paths should be modified accordingly. However, this might also result in a reduction of the peak efficiency. Adoption of such an option reflects the fact that industry prefers modifications to the expander side. Nevertheless, extensive modifications to the expander should be also avoided as it will be costly. Other secondary alternatives In order to compensate for the increased clean syngas flow, supplementary firing of a portion of the fuel could be considered to increase the total power output of the entire plant. It means in the case of trip of CCS unit, excess cleaned syngas not needed in the GT could be used for supplementary firing leading to increased overall power output of the combined cycle. Another option to combust the extra fuel together with some air blown off at the compressor exit is the utilization of a second expander. Nevertheless, techno-economic evaluations are required to predict the penalties imposed by the use of a second combustor or expander. The results will mainly depend on the expected operating hours of this additional unit, as well as fuel costs. 5. CONCLUSIONS The effect of fuel change (i.e. from NG to H2-rich syngas and clean syngas) on the selected GT was reported in this paper. Based on the results, focusing only on the gas turbine as a stand-alone unit, operation with H2-rich fuel is feasible if a reduced surge margin would be acceptable. The clean syngas operation (in non-capture IGCC plant) results in significantly lower surge margin and higher turbine outlet temperature compared to the reference case especially at off-design conditions, which requires engine modification. Results confirm that running the engine with H2-rich fuel without significant changes compared to the NG-fired engine can be carried out from a turbomachinery point of view. However, it should be noted that the challenges concerning pre-mixed combustion of the H2-rich fuel and different heat transfer rate to the expander materials when operated with H2-rich fuel are not covered in this paper. When operating with a fuel with low calorific value, such as clean syngas, expected operational hours are very important for the selection of appropriate operating conditions or modification options. Although several modification options as well as operating strategies have been suggested in case of clean syngas operation, reduced efficiency and compressor stability range could be tolerated for limited operational hours with clean syngas. Nevertheless, the best combination of the GT power output and efficiency has to be searched for, taking into account the whole IGCC performance as well as investment and maintenance costs, when clean syngas operation is one of the requirements of the plant. Moreover, it was demonstrated that altered VIGV angle doesn’t provide acceptable surge margin for the selected GT. In order to have only minor modifications to the GT for clean syngas operation compared to the design case, decreasing the TIT and maintaining similar TOT as for the reference case (NG-fired GT) with fully open VIGV could be a plausible option. However, results showed significant reduction of efficiency and power output for this specific option. It should be highlighted that using clean syngas requires major modifications to the GT including additional compressor stages, air bleed from compressor outlet, and re-staggering of the expander nozzle wanes. Therefore this option was omitted from the list of possible alternatives for the H2-IGCC project. ACKNOWLEDGMENT The authors are grateful to the European Commission’s Directorate-General for Energy for financial support of the Low Emission Gas Turbine Technology for Hydrogen-rich Syngas (H2-IGCC) project. The authors also wish to acknowledge Han Raas at Vattenfall for performing the gasification simulations. Constructive discussions and data exchange with Professor G. Cerri and his group at Roma Tre University are also acknowledged.

11

NOMENCLATURE

A cross-sectional area AGR acid gas removal ASU air separation unit CCS carbon capture and sequestration CO carbon monoxide COS carbonyl sulfide CO2 carbon dioxide cp specific heat GHG greenhouse gas GT gas turbine HRSG heat recovery steam generator H2 hydrogen H2S hydrogen sulfide IGCC integrated gasification combined cycle LHV lower heating value LNG liquefied natural gas LP low pressure MAC main air compressor m mass flow rate NG natural gas NOx nitrogen oxide N2 nitrogen OEM original equipment manufacturer O2 oxygen P power p pressure PGAN pure gaseous nitrogen PR pressure ratio R gas constant SCGP Shell Coal Gasification Process SOA state-of-the-art SOx sulfur oxide SWGS sour water-gas shift T temperature TIT turbine inlet temperature TOT turbine outlet temperature VIGV variable inlet guide vane Greek Letters γ specific heat ratio κ choked flow coefficient η efficiency Subscripts i expander inlet o expander outlet t total condition REFERENCES

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3. BP, Energy outlook 2030, 2012, British Petroleum Company.

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5. IEA, World energy outlook. International Energy Agency, 2013: Paris, France.

6. IEA, IEA statistics 2013 edition: CO2 emissions from fuel combustion highlights. International

Energy Agency, 2013: Paris, France.

7. Kanniche, M., Bouallou, C, CO2 capture study in advanced integrated gasification combined cycle.

Applied Thermal Engineering, 2007. 27: p. 2693-2702.

8. Zheng, L., Furinsky, E, Comparison of Shell, Texaco, BGL and KRW gasifiers as part of IGCC plant

computer simulations. Energy Conversion & Management, 2005. 46: p. 1767-1779.

9. Sipöcz, N., Mansouri, M, Breuhaus, P, Assadi, M. Development of H2-rich syngas fuelled GT for

future IGCC power plants – establishment of a baseline. in ASME paper GT2011-45701. 2011.

ASME Turbo Expo, Vancouver, Canada.

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10. Carbo, M.C., Jansen, D, Boon, J, Dijkstra, JW, Van Den Brink, RW, Verkooijen, AHM, Staged

water-gas shift configuration: Key to efficiency penalty reduction during pre-combustion

decorbonisation in IGCC. Energy Procedia, 2009. 1: p. 661-668.

11. Kanniche, M., Gros-Bonnivard, R, Jaud, P, Valle-Marcos, J, Amann, JM, Bouallou, C, Pre-

combustion, post-combustion and oxy-combustion in thermal power plant for CO2 capture. Applied

Thermal Engineering, 2010. 30: p. 53-62.

12. Chiesa, P., Lozza, G, Mazzocchi, L, Using hydrogen as gas turbine fuel. Journal of Engineering for

Gas Turbines and Power, 2005. 127: p. 73-80.

13. Romano, M.C., Chiesa, P, Lozza, G, Pre-combustion CO2 capture from natural gas power plants,

with ATR and MDEA processes. International Journal of Greenhouse Gas Control, 2010. 4: p. 785-

797.

14. IEA, Improved oxygen production technologies. IEA Greenhouse Gas R&D Programme.

International Energy Agency, 2007: United Kingdom.

15. Bancalari, E., Chan, P, Diakunchak, I.S. Advanced hydrogen gas turbine development program. in

ASME paper GT2007-27869. 2007. ASME Turbo Expo, Montreal, Canada: Siemens Power

Generation, Inc.

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Annual International Pittsburgh Coal Conference2002.

17. Nag, P., LaGrow, M, Wu, J, Abou-Jaoude, K,Engel, J, LNG fuel flexibility in Siemens’ land-based

gas turbine operations, in Electric Power Conference2007, Siemens Power Generation, Inc.:

Chicago, Illinois, USA.

18. Chishty, W.A., Fuel flexibility effects on gas turbine operation, in Industrial Application of Gas

Turbines (IAGT)2010: Hamilton, Ontario, Canada.

19. McMillan, R., Marriott, D, Su, R.H, Fuel flexible gas turbine cogeneration, in Power-Gen Asia2008,

Siemens AG: Kuala Lumpur, Malaysia.

20. Rahm, S., Goldmeer, J, Moliere, M, Eranki, A, Addressing gas turbine fuel flexibility- GE white

paper GER4601 (06/09), in POWER-GEN Middle East conference2009: Manama, Bahrain.

21. Jones, R., Goldmeer, J., Monetti, B., Addressing gas turbine fuel flexibility- GE white paper

GER4601 (05/11) revB. 2011.

22. Kim, Y.S., Lee, J.J, Cha, K.S, Kim, T.S, Sohn, J.L, Joo, Y.J. Analysis of gas turbine performance in

IGCC plants considering compressor operating condition and turbine metal temperature. in ASME

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Applied Energy, 2012. 99: p. 280-290.

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27. Mansouri Majoumerd, M., Raas, H, De, S, Assadi, M, Estimation of performance variation of future

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project. Applied Energy, 2014. 113: p. 452-462.


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http://www.h2-igcc.eu/

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Paper V

Techno-economic evaluation of an IGCC power plant with

carbon capture

Mohammad Mansouri Majoumerd, Mohsen Assadi, Peter

Breuhaus

Presented at ASME Turbo Expo 2013, San Antonio, Texas,

USA, June 2013

1

Mohammad Mansouri Majoumerd1, Mohsen Assadi1,2, Peter Breuhaus2

1Faculty of Science and Technology



2International Research Institute of Stavanger (IRIS)

Postbox 8046


Abstract

Most of the scenarios presented by different actors and organizations in the energy sector predict an increasing power demand in the coming years mainly due to the world’s population growth. Meanwhile, global warming is still one of the planet’s main concerns and carbon capture and sequestration is considered one of the key alternatives to mitigate greenhouse gas emissions. The integrated gasification combined cycle (IGCC) power plant is a coal-derived power production technology which facilitates the pre-combustion capture of CO2 emissions.

After the establishment of the baseline configuration of the IGCC plant with CO2 capture (reported in GT2011-45701), a techno-economic evaluation of the whole IGCC system is presented in this paper. Based on publicly available literature, a database was established to evaluate the cost of electricity (COE) for the plant using relevant cost scaling factors for the existing sub-systems, cost index, and financial parameters (such as discount rate and inflation rate). Moreover, an economic comparison has been carried out between the baseline IGCC plant, a natural gas combined cycle (NGCC), and a supercritical pulverized coal (SCPC) plant.

The calculation results confirm that an IGCC plant is 180% more expensive than the NGCC. The overall efficiency of the IGCC plant with CO2 capture is 35.7% (LHV basis), the total plant cost (TPC) is 3,786 US$/kW, and the COE is 160 US$/MWh.

Nomenclature

AGR Acid gas removal ASU Air separation unit BEC Bare erected cost BOP Balance of plant CCF Capital charge factor CCS Carbon capture and sequestration CEPCI Chemical Engineering Plant Cost Index CF Capacity factor COE Cost of electricity CO Carbon monoxide CO2 Carbon dioxide EPCC Engineering, procurement, and construction

cost GHG Greenhouse gas GT Gas turbine HHV Higher heating value HRSG Heat recovery steam generator H2 Hydrogen H2O Water IGCC Integrated gasification combined cycle LHV Lower heating value NG Natural gas NGCC Natural gas combined cycle NOAK nth-of-a-kind OECD Organization for Economic Co-operation

and Development O2 Oxygen O&M Operation and maintenance costs SCGP Shell coal gasification process SCPC Super critical pulverized coal ST Steam turbine SWGS Sour water-gas shift


Proceedings of ASME Turbo Expo 2013: Turbine Technical Conference and Exposition

GT2013

June 3-7, 2013, San Antonio, Texas, USA

GT2013-95486

TECHNO-ECONOMIC EVALUATION OF AN IGCC POWER PLANT WITH CARBON CAPTURE

2

TASC Total as-spent cost TOC Total overnight cost TPC Total plant cost TS&M Transport, storage, and monitoring

1. Introduction

The global financial situation during the past few years has resulted in falling investments in the power sector, especially in OECD (Organization for Economic Co-operation and Development) countries [1]. However, global energy demand is steadily increasing, mainly due to the world’s population growth. A greater part of this increasing demand comes from non-OECD countries. It is assumed that electricity generation will be the largest source of primary energy consumption in the coming decades [2]. Among various fossil fuels, coal had the fastest consumption growth rates in 2011 compared to 2010 [3]. According to the International Energy Agency’s “new policies” scenario, coal consumption in the year 2035 will have a 25% increase compared to 2009. However, based on the “current policies” scenario, this increase will be 65% compared to the level of 2009 [4]. The main reasons for this are the abundant resources of coal (more than 100 years with current proved reserves) and its widespread availability compared to the other fossil fuels [3, 5-7].

The necessity to abate greenhouse gas (GHG) emissions will result in the deployment of carbon capture and sequestration (CCS) in the power production sector. CCS will play a key role in curbing CO2 emissions, according to the European Energy Roadmap 2050 [8]. Moreover, the deployment of CCS in coal-fired power production will ensure that coal will have its share in fossil fuel consumption in future years with more restricted emissions’ regulations, even though the CO2 emissions from coal combustion are significantly higher than those for natural gas (NG).

During the last two decades, the integrated gasification combined cycle (IGCC) has been assumed to be one of the most attractive coal-based technologies for generating electricity from coal in terms of low environmental impact [9-11]. Although each of the major sub-systems of the IGCC system has been widely used in industrial applications, their integration in the IGCC plant is not well-matured yet, and such a plant is considered to be complex from the plant owner’s perspective. This complexity may prevent investments in IGCC plants due to higher risk for low availability and consequently higher cost of electricity compared to other fossil fuel-based power technologies.

Incorporating a water-gas shift reaction unit into the IGCC plant facilitates the pre-combustion capture of CO2 [11, 12]. However, due to the associated efficiency penalty imposed by CO2 capture and the high investment cost of

water-gas shift and the capture system, there is currently no full-scale IGCC power plant built with CCS.

Therefore, further investigation of the various methods to increase the availability of the system, to evaluate the associated operational risks, and to reduce the efficiency penalty and the cost of CO2 avoidance in IGCC plants is necessary.

Besides technical issues, economic figures play a major role in the commercialization of a technology. The commercial investment in an IGCC plant requires competitive cost of electricity (COE) compared to other competing power generation technologies [13]. To find out the COE for the IGCC plant, a techno-economic investigation is vital. However, the economic analysis of this plant is more complicated than for other power generation technologies e.g. natural gas combined cycle (NGCC), because of the large number of components used in an IGCC plant. Moreover, there are several alternative sub-systems to select, e.g. for the gasification block (e.g. Shell, GE, Siemens, etc.) with their own specific costs and characteristics. Therefore, an IGCC plant is not considered as a standardized commercial technology with well-established costs [14]. Moreover, other factors such as market situation, fuel price, CO2 allowances cost and currency fluctuations increase the level of uncertainty in cost estimation.

Though the prediction of the investment costs for the IGCC plant is a difficult task, this study attempts to provide a rough estimate in order to illustrate the plant’s economic status. The objectives of this study are to analyze the economic indicators of the IGCC plant with CO2 capture and to compare them with other fossil fuel power generation technologies, i.e. NGCC and supercritical pulverized coal plant (SCPC) with CCS. Since the emphasis in this work has been dedicated to the economic evaluation of the selected IGCC plant, the detailed description of thermodynamic modeling is not repeated here. The description of simulations using Enssim software [15], ASPEN Plus [16], and IPSEpro [17] could be found in references [12, 18].

2. IGCC configuration

The integrated gasification combined cycle plant with CO2 capture (refer to Fig. 1) comprises the following sub-systems:

Cryogenic air separation unit (ASU) to provide O2 for the gasification process and N2 as the conveying gas.

Shell coal gasification process (SCGP) to produce syngas from coal using O2 and intermediate pressure steam [19].

Sour water-gas shift (SWGS) reaction unit to convert CO and steam to CO2 and H2 using exothermic catalytic reaction [20].


3

Acid gas removal (AGR) unit to remove the H2S content of the syngas using physical solvent (SELEXOL) [18].

CO2 capture unit to remove the CO2 content of the syngas.

CO2 compression and dehydration unit to ensure the final CO2 conditions for transport and storage.

Gas turbine (GT) to produce electricity by combustion of H2-rich syngas [18].

Heat recovery steam generator (HRSG) to utilize the energy in the hot exhaust gas from the GT for steam and electricity production.

Steam turbine (ST) to produce electricity from steam produced in the HRSG.

The main technical specifications for simulation of the whole IGCC system are shown in Table A.1 (Appendix I). Reference [18] contains further technical assumptions.

Fig. 1: The schematic figure of the IGCC power plant with CO2 capture

3. Plant economics

The methodology used for cost estimation for the IGCC plant is based on the “Quality Guidelines for Energy System Studies” by the United States’ National Energy Technology Laboratory (NETL) [21]. An estimation of the COE for an IGCC plant with CCS comprises the following items:

1) Capital costs 2) Fuel cost

3) Operation and maintenance (O&M) costs 3.1) Fixed costs e.g. labor cost 3.2) Variable costs e.g. chemicals, solid waste

handling, CO2 emissions cost, etc. 4) CO2 transport, storage and monitoring costs

The following sub-sections describe the aforementioned cost components.


4

3.1. Capital costs

The capital costs have been defined based on the following five different cost levels:

1) Bare erected cost (BEC): This cost comprises process equipment items, supporting facilities (e.g. labs, roads, etc.), and the direct and indirect labor required for the construction and installation of equipment items.

2) Engineering, procurement and construction cost (EPCC): This cost comprises the BEC plus the cost of the engineering, procurement and construction services.

3) Total plant cost (TPC): This cost comprises the EPCC plus project and process contingencies.

4) Total overnight costs (TOC): This cost comprises the TPC plus owner’s costs.

5) Total as-spent cost (TASC): This cost is the sum of all capital expenditures as they are incurred during the capital expenditure period including their escalation. TASC also includes interest during construction.

BEC

The estimation of the BEC for the major components of the IGCC plant (except the gas turbine) is derived from the detailed study of NETL [22].

The cost of the gas turbine is derived from the 2009 Gas Turbine World Handbook [23]. Since the GT in this study has some add-on options such as a new burner design to combust H2-rich fuel (instead of natural gas), new cooling air flow design, and sophisticated materials for the expander section, a 15% cost increase is assumed here. Although a GT with these characteristics is not available on the market, the cost for a mature nth-of-a-kind (NOAK) GT was considered.

The overnight cost of a component ( ) with specific size ( ) based on a reference component ( ) with reference size ( ) is shown by the following Eq. 1:

(Eq. 1)

where is the number of equally sized equipment trains operating at 100%/n, is the cost scaling exponent for multiple trains of the component, and is the cost scaling factor. Adjustments of costs (except for the GT) have been carried out using the Chemical Engineering Plant Cost Index (CEPCI) of April 2012 [24]. The graph of the simple cycle price change available in reference [25] has been used for the fluctuation of the gas turbine price.

EPCC

The EPCC for all major components of the IGCC plant are about 8% of the BECs of the corresponding components [22].

TPC

The project and process contingencies to calculate TPC are assumed to be 18% and 5% of the BECs, respectively [22].

TOC

The sum of the TPC and the owner’s costs is the total overnight cost of a plant. The assumptions for owner’s costs are shown in Table 1 below.

Table 1: Assumptions for owner’s costs

Parameter Comment Pre-production costs 6 months’ operating labor costs

1 month’s maintenance materials cost at 100% CFa 1 month non-fuel consumables at 100% CF 1 month waste disposal 25% of 1 month fuel cost at 100% CF 2% of TPC

Inventory capital 60-day supply of fuel and non-fuel consumables at 100% CF 0.5% of TPC (spare parts)

Initial cost for catalyst and chemicals

Plant site area US$7413/hectare for a land (greenfield without seismic consideration) with area of 121 hectares

Other owner’s costs 15% of TPC Financing costs 2.7% of TPC

a Capacity factor

TASC

This cost vary based on the capital expenditure period and the financing scenario (for further information refer to [22]). The interests during the construction period are included in the TASC. The ratio of TASC/TOC for the IGCC plant with CO2 capture for five years of construction is set to 1.140.

3.2. Other assumptions

It should be noted that all costs are limited to “within the fence line”, except the costs of CO2 transport, storage and monitoring (TS&M). Other economic assumptions employed for the cost estimation are shown in Table 2.


5

Calculation of the cost of electricity is based on the following Eq. 2:

(Eq. 2)

where is the capital charge factor, is the sum of all fixed annual operating costs, is the sum of all variable annual operating costs, and is annual net megawatt-hours of power generated at 100% capacity factor (CF).

Table 2: Economic assumptions

Parameter Value Unit Coal price1,2 110 US$/tonne NG price3 32.79 US$/MWh IGCC capacity factor 80 % NGCC capacity factor 85 % SCPC capacity factor 85 % NGCC net power output 473.6 MW SCPC net power output 550.0 MW NGCC overall efficiency 47.5 % LHV SCPC overall efficiency 29.5 % LHV NGCC CO2 capture rate 90.7 % SCPC CO2 capture rate 90.2 % NGCC plant site area 1/3 of IGCC land SCPC plant site area 1 similar to IGCC TASC/TOC for NGCC 1.078 - TASC/TOC for SCPC 1.140 - CCF4 for IGCC and SCPC 0.124 - CCF for NGCC 0.111 - CO2 allowances cost5 7.36 €/tonne of CO2 CO2 TS&M for IGCC6 4.3 US$/MWh CO2 TS&M for NGCC 3.2 US$/MWh CO2 TS&M for SCPC 5.6 US$/MWh Labor work 50 h/work.week Operating labor cost7 31.18 US$/h.capita Discount rate 12 % Inflation rate 3 % Real escalation rate 0 %

1 Coal price is based on API N2, 6000 kCal NAR (CIF) [26]. 2 The USD to Euro exchange rate is 0.7527 [27]. 3 NG price is based on Zeebrugge price [26]. 4 Capital charge factor 5 The cost of CO2 emissions is based on European Union emission

trading scheme [26]. 6 This cost is derived from reference [22], adjusted using CO2

captured and assumed to be constant and free of fluctuations (from 2007 to 2012) due to the technology improvement. The captured CO2 is transported 80 km.

7 Labor cost have been updated based on EU Labor Cost for EU-27 countries from European Commission reports [28, 29].


In this section, results of thermodynamic simulation are presented followed by results of the plant’s economic and

sensitivity analysis, illuminating the impact of cost/price variations. Finally, results of economic evaluation for various power plants i.e. IGCC, NGCC, and SCPC plants are presented and discussed.

4.1. Thermodynamic results

The performance indicators of the IGCC plant with CO2 capture are given in Table 3.

Table 3: Performance indicators of the IGCC power plant with carbon capture

Performance indicators MW GT shaft power output 324.0 ST shaft power output 177.4 Generator power output 501.4 ASU compression power demand 49.8 Gasification power demand 5.0 Syngas cleaning compression and pumping demand 10.9 Syngas cleaning refrigeration power demand 9.2 CO2 compression power demand 20.8 HRSG pumping power demand 3.4 Total auxiliary power demand 99.1 Net power output 402.2 Overall IGCC efficiency (%LHV) 35.7

Fig. 2 shows the share of auxiliary power demands for the IGCC plant. Simulation results confirm that the ASU has the largest auxiliary power demand with 50.3% of the total auxiliary power demand.

Fig. 2: The share of auxiliary power consumptions

4.2. Cost estimations

The results of the estimation of overnight costs for major components of the IGCC plant with CO2 capture using (Eq.1) and reference [22] are shown in Table 4. It should be mentioned that the uncertainty of this type of cost estimation is about ±30%. It is worth noting that the information given in Table 4 is based on June 2007 US$, without incorporating

5 %

50 %

11 %

9 %

21 %

4 %Gasification power demand

ASU compression powerdemand

AGR pumping andcompression power demand

AGR refrigeration powerdemand

CO2 compression powerdemand

HRSG pumping power demand


6

the installation labor cost. Given the same labor cost for the installation of a component with two different sizes, this cost has been considered to be the same as in reference [22]. However, using the US Bureau of Labor Statistics (BLS), data for chemical manufacturing, the installation labor cost

has been adjusted to April 2012. Moreover, the GT price which is given in Table 4 is the price for 2009. As it was mentioned in Section 3.1, all of these costs have been adjusted using relevant cost indexes.

Table 4: Capital costs for major components of the IGCC power plant

# Plant component Scaling parameter 3 3 1 Coal handling, preparation and feed Coal input (tonne/h) 211040 0.67 16461 161436 13756 2 Gasifier and accessories Coal input (tonne/h) 211040 0.67 180256 161436 150635 3 ASU O2 production (kmol/h) 4642 0.67 173504 4004 154999 4 Gas clean-up Syngas flow rate (tonne/h) 575 0.67 95090 439 79346 5 CO2 compression and drying Compression power (MWe) 30.2 0.67 17811 20.8 13852 6 GT1 - - 73373.6 7 HRSG, ducting and stack GT net power (MWe) 464 0.67 39499 324 31052 8 ST generator, condenser, aux. ST gross power (MWe) 209.4 0.67 33914 177.4 30344 9 Cooling water, aux. ST gross power (MWe) 209.4 0.67 19404 177.4 17362

10 Feed water and miscellaneous BOP ST gross power (MWe) 209.4 0.67 16678 177.4 14922 11 Ash and slag handling Ash content of the coal (tonne/h) 21.1 0.67 20018 20.2 19410 12 Instrumentation and control2 - - 1 13026 - 13026 13 Building and structures Plant net power (MWe) 496.9 0.67 6461 402.2 5608 14 Other (improvements to site,

accessory electric plant) Plant net power (MWe) 496.9 0.67 47953 402.2 41622

1 The price for the GT was derived from Gas Turbine World handbook [23] and the reference GT for this study is Siemens/Ansaldo Energia V94.3A.

2 A similar cost has been used for instrumentation and control cost.

3 All costs (i.e. C and C) in US$×1000.

Table 5 shows results of the economic analysis for the IGCC plant with CCS, based on the information given in Table 4 and assumptions described in Section 3.

Table 5: Various cost indicators for the IGCC plant

Parameter Unit

US$*1000 US$/kW Total plant cost (TPC) 1,523,051 3,786 Total overnight cost 1,881,257 4,677 Total as-spent cost (TASC) 2,144,633 5,332 US$/MWh COE (base year-2012) 160 COE (1st year of operation-2017) 186

The TPC for the IGCC plant with CO2 capture has been reported to be in the range of 1,414-2,513 in references [30-32]. The range of COE has been reported to be 54-95.8 US$/MWh [30-32]. The above-mentioned reported figures are far below the range of COE and TPC calculated in the current study. This difference may be due to the different coal price, power plant size, capacity factor and financial

assumptions used. However, the Electric Power Research Institute (EPRI) report [33] on IGCC shows a TPC of 3,683 US$/kW, which is very close to the number reported in Table 5. Moreover, personal communications with power

plant owners, confirm the range of TPC reported in this study.

4.2.1. Economic sensitivity

In order to evaluate the sensitivity of the economic results to variations in the inputs, a sensitivity analysis has been performed to identify the parameters which have the strongest impact on the results. Results highlight possible drivers which may influence market attention on this technology.

Table 6: Economic parameters and their variation range for sensitivity analysis

Parameter Absolute range Relative range Coal price 60 ‒ 160 US$/tonne -45.5 ‒ 45.5% Capacity factor 40 ‒ 90% -50 ‒ 12.5% CO2 allowances cost 3.7 ‒ 11.0 €/tonne -50 ‒ 50%

Three parameters which are usually considered as the most uncertain parameters for calculation of the COE were selected. These parameters and their variation for sensitivity analysis are shown in Table 6. The results of the sensitivity analysis are presented in Fig. 3.


7

Fig. 3: Sensitivity response on COE for the IGCC plant under variation of fuel cost, capacity factor, and CO2

allowances cost

It is evident from Fig .3 that the capacity factor has the largest influence on the COE. The second ranked parameter

is the coal price, while the impact of CO2 allowances cost is negligible. The minimal effect of the CO2 price is due to the low absolute value of CO2 allowances cost. However, its influence will change depending on the CO2 market development and change in global mitigation policies.

4.2.2. Results of the comparative plant economics

Using assumptions presented in Table 2, Fig. 4 shows results of the comparative study of various plants’ capital cost items.

The TOCs of IGCC, SCPC, and NGCC plants are 4677, 4065, and 1669 US$/kW, respectively. According to Fig. 4, the highest capital cost is required for the IGCC plant. The TOC and TASC for the IGCC plant are 15% higher than the corresponding values for the SCPC plant (the basis for comparison is the SCPC).

Fig. 4: Plant capital costs for IGCC, SCPC, NGCC plants with CO2 capture

Despite the higher cost for the IGCC plant compared to the SCPC plant, investment in such a plant may be beneficial in the coming years with more stringent environmental regulations due to: a) advantages of gasification such as easier control of gaseous pollutants, and b) advantages of the pre-combustion capture, such as high CO2 concentration and smaller equipment size because of high fuel gas pressure.

The TOC and TASC for the IGCC plant are 180% and 196% higher than corresponding values for the NGCC plant (the basis for comparison is the NGCC). Even though there is a large gap between the IGCC and the NGCC, the future investment in the IGCC plant is very plausible due to the security of energy supply.

‐20.0

‐10.0

0.0

10.0

20.0

30.0

40.0

50.0

60.0

70.0

80.0

‐60.0 ‐40.0 ‐20.0 0.0 20.0 40.0 60.0

COE Change (%)

Parameter Variation (%)

Capacity Factor Fuel Cost CO2 Allowances cost

0.0

1000.0

2000.0

3000.0

4000.0

5000.0

6000.0

Total overnightcost (TOC)

TASC TOC TASC TOC TASC

IGCC SCPC NGCC

5331.7

4633.6

1799.7

TOC and TASC, U

S$/kW (2012$)

Total as‐spent cost (TASC) Owner's cost

Process contingency Project contingency

Engineering, procurement, and construction cost (EPCC) Bare erected cost (BEC)


8

Results of the COE for the IGCC, SCPC, and NGCC plants are shown in Fig. 5. The total COEs for IGCC, SCPC, and NGCC plants are 160, 148, and 114 US$/MWh, respectively. The COE for the IGCC plant is 8% and 41% higher than COEs for SCPC and NGCC plants (bases for comparisons are COEs of the SCPC and NGCC, respectively).

Fig. 5: COE for IGCC, NGCC, and SCPC plants with CO2 capture

As mentioned before (refer to Fig. 3), one of the most effective solutions for reducing the difference in COEs for IGCC and SCPC plants is to increase the capacity factor of both IGCC and SCPC plants so that they have a similar value.

The combination of this increase and the increased CO2 allowances cost may improve investment in an IGCC plant where coal is the most available fuel for power production. The COE for both plants is equal when the capacity factors of both plants and the CO2 allowances cost are set to 90% and 74 €/tonne of CO2, respectively.

5. Conclusion

The aim of this paper was to carry out a techno-economic analysis for a specific IGCC plant configuration with CO2 capture, and to compare the COE for this plant with competing technologies which are NGCC and SCPC plants. The main objective was to generate a database using publicly available literature to calculate the COE for this plant.

The initial part of the paper describes the configuration of the IGCC plant. The second part of the paper describes the methodology used for the economic evaluation of the

plant, as well as relevant assumptions, calculation methods, and economic figures.

The COE for the IGCC plant with CCS is 160 US$/MWh. It should be noted that all economic results are strongly dependent on presented assumptions. A sensitivity analysis was also carried out showing that the most influential parameter on the COE was the capacity factor. The fuel price was the second ranked parameter, while the effect of CO2 allowances cost was negligible due to the low cost of CO2 emissions. Finally, a comparative study was carried out to highlight the cost difference between various power generation technologies i.e. IGCC, SCPC, and NGCC plants with CCS. The total overnight costs for IGCC, SCPC, and NGCC are 4677, 4065, and 1669 US$/kW, respectively. The results of the COE for the IGCC, SCPC, and NGCC are 160, 148, and 114 US$/MWh, respectively. Even though the investment cost in the IGCC plant is more than double that for the NGCC plant, the security of the energy supply may encourage investors to select IGCC plants.

Moreover, it was shown that with the higher capacity factor and CO2 allowances cost, which is plausible in the coming years, the IGCC plant could attract more investments compared to the SCPC plant. Furthermore, income from poly-generation applications might also improve the economic status of future IGCC plants.

Acknowledgment

The authors are grateful to the European Commission’s Directorate-General for Energy for financial support of the Low Emission Gas Turbine Technology for Hydrogen-rich Syngas (H2-IGCC) project.

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6. Robinson, P.J., Luyben, WL, Integrated gasification combined cycle dynamic model: H2S absorption/stripping, water-gas shift reactors, and CO2

0.0

20.0

40.0

60.0

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100.0

120.0

140.0

160.0

180.0

IGCC SCPC NGCC

4.3 5.6 3.2

44.151.3

76.6

11.010.4

3.2

18.013.4

5.8

82.8 67.7

24.9

COE, US$/M

Wh (2012$)

Capital costs Fixed costs Variable costs

Fuel costs CO2 TS&M


9

absorption/stripping. Industrial & Engineering Chemistry research, 2010. 49: p. 4766-4781.

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9. Kanniche, M., Bouallou, C, CO2 capture study in advanced integrated gasification combined cycle. Applied Thermal Engineering, 2007. 27: p. 2693-2702.

10. Holt, N., Booras, G, Todd, D, A Summary of Recent IGCC Studies of CO2 Capture for Sequestration, in Gasification Technologies Conference2003: San Francisco, CA, USA.

11. Zheng, L., Furinsky, E, Comparison of Shell, Texaco, BGL and KRW gasifiers as part of IGCC plant computer simulations. Energy Conversion & Management, 2005. 46: p. 1767-1779.

12. Sipöcz, N., Mansouri, M, Breuhaus, P, Assadi, M. Development of H2-rich syngas fuelled GT for future IGCC power plants – establishment of a baseline. in ASME paper GT2011-45701. 2011. ASME Turbo Expo, Vancouver, Canada.

13. Rosenberg, W.G., Alpern, D.C., Walker, M.R., Deploying IGCC in this decade with 3 party covenant financing, 2004: John F. Kennedy School of Government, Harvard University.

14. Rosenberg, W.G., Alpern, D.C., Walker, M.R., Financing IGCC – 3party covenant, 2004: John F. Kennedy School of Government, Harvard University.


16. ASPEN Plus version 7.1, 2009, Aspen Technology Inc.: Cambridge, MA, USA.

17. IPSEpro version 4.0, 2003, Simtech Simulation Technology (Simtech): Graz, Austria.

18. Mansouri Majoumerd, M., De, S, Assadi, M, Breuhaus, P, An EU initiative for future generation of IGCC power plants using hydrogen-rich syngas: Simulation results for the baseline configuration. Applied Energy, 2012. 99: p. 280-290.

19. The Shell coal gasification process for sustainable utilisation of coal, 2006, Shell Global Solutions.

20. Chiesa, P., Consonni, S, Shift reactors and physical absorption for low-CO2 emission IGCCs. Journal of

Engineering for Gas Turbines and Power, 1999. 121(2): p. 295-305.

21. NETL, Quality guidelines for energy system studies- Cost estimation methodology for NETL assessments of power plant performance, 2011, DOE/NETL-2011/1455.

22. NETL, Cost and performance baseline for fossil energy plants, Volume 1: Bituminous coal and natural gas to electricity, 2010, 2nd Revision, DOE/NETL-2010/1397.

23. Gas Turbine World Handbook. Vol. 27. 2009: Pequot Publishing.

24. Chemical Engineering Plant Cost Index (CEPCI). Chemical Engineering, August 2012. 126.

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26. Energy statistics-week 17. 2012; Available from: http://www.energymarketprice.com.

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29. Eurostat newsrelease- Euro indicators, 2012, Eurostat press office, 134/2012.

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32. Huang, Y., Rezvani, S, McIlveen-Wright, D, Minchener, A, Hewitt, N, Techno-economic study of CO2 capture and storage in coal fired oxygen fed entrained flow IGCC power plants. Fuel Processing Technology, 2008. 89: p. 916–925.

33. Schoff, R., Marasigan, J, Coal fleet integrated gasification combined cycle research and development roadmap, 2011, Electric Power Research Institute (EPRI).


10

Appendix I:

Table A.1: The main technical specifications of the IGCC plant

Air separation unit O2 purity: 95%

Main air compressor: Three-stage inter-cooled to 5.5 bar Gaseous O2 compressor: Six-stage intercooled to 55 bar

Pure gaseous N2 compressor: Six-stage intercooled to 80 bar

Acid gas removal unit and CO2 capture Solvent type: physical Solvent: SELEXOL

Number of absorption stages: 2 Solvent inlet temperature to the absorber: 5 °C

CO2 capture rate: 90% (molar basis)

Feedstock properties Type: Bituminous coal

HHV: 26195 kJ/kg LHV: 25100 kJ/kg

CO2 compression and dehydration Final pressure: 150 bar

Drying agent: Tri-ethylene glycol Final water content in the CO2 stream: 20 ppm (mass)

Gasifier Type: SCGP (O2-blown, entrained flow, dry-fed)

Pressure: 45 bar Temperature: 1600 °C

Gas turbine Compressor pressure ratio: 18.2

Firing temperature: 1440 °C Compressor isentropic efficiency: 92.3%

Expander isentropic efficiency: 89.2% GT outlet pressure (bar (total)): 1.08 bar

Electrical/mechanical efficiency: 99/99.5%

Sour water-gas shift reaction unit

Reaction: CO H O CO H

Inlet syngas temperature to the reactor: 250 °C steam-to-CO ratio: 2.4

Heat recovery steam generator Pressure level: 140/43/4 bar

Superheating/reheat temperature: 530/530 °C


187

Paper VI

Techno-economic assessment of fossil fuel power plants with

CO2 capture ‒ Results of EU H2-IGCC project

Mohammad Mansouri Majoumerd and Mohsen Assadi

Published in International Journal of Hydrogen Energy, Vol. 39,

p. 16771-16784, September 2014

ww.sciencedirect.com

i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n en e r g y 3 9 ( 2 0 1 4 ) 1 6 7 7 1e1 6 7 8 4

Available online at w

ScienceDirect

journal homepage: www.elsevier .com/locate/he

Techno-economic assessment of fossil fuel powerplants with CO2 capture e Results of EU H2-IGCCproject

Mohammad Mansouri Majoumerd a,*, Mohsen Assadi a,b

a Faculty of Science and Technology, University of Stavanger, 4036 Stavanger, Norwayb International Research Institute of Stavanger, Postbox 8046, 4068 Stavanger, Norway


Article history:

Received 25 June 2014

Received in revised form

6 August 2014

Accepted 10 August 2014

Available online 8 September 2014

Keywords:

Techno-economy

IGCC

Pulverized coal

NGCC

CO2 capture

Cost of electricity

* Corresponding author. Tel.: þ47 453 91 926E-mail addresses: m_mansouri_m@yahoo

1 Integrated gasification combined cycle.2 Advanced supercritical pulverized coal.3 Natural gas combined cycle.

http://dx.doi.org/10.1016/j.ijhydene.2014.08.00360-3199/Copyright © 2014, Hydrogen Ener

a b s t r a c t

In order to address the ever-increasing demand for electricity, need for security of energy

supply, and to stabilize global warming, the European Union co-funded the H2-IGCC

project, which aimed to develop and demonstrate technological solutions for future gen-

eration integrated gasification combined cycle (IGCC1) plants with carbon capture. As a part

of the main goal, this study evaluates the performance of the selected IGCC plant with CO2

capture from a techno-economic perspective. In addition, a comparison of techno-

economic performance between the IGCC plant and other dominant fossil-based power

generation technologies, i.e. an advanced supercritical pulverized coal (SCPC2) and a nat-

ural gas combined cycle (NGCC3), have been performed and the results are presented and

discussed here. Different plants are economically compared with each other using the cost

of electricity and the cost of CO2 avoided. Moreover, an economic sensitivity analysis of

every plant considering the realistic variation of the most uncertain parameters is given.

Copyright © 2014, Hydrogen Energy Publications, LLC. Published by Elsevier Ltd. All rights

reserved.

Introduction

World total primary energy consumption was 12,470 Mtoe in

2012 [1]. Global population, global economy, energy-intensity

of the global economy, and living standard are the main

drivers of theworld's energy demand [2]. Except for decreasing

energy-intensity (energy consumption per capita) [3], other

fundamental drivers of energy demand will grow continu-

ously in the coming decades [4e6]. Nevertheless, improved

; fax: þ47 51 83 10 50..com, mohammad.mans

20gy Publications, LLC. Publ

energy efficiency cannot outpace the effects of other drivers,

resulting in a growing energy demand over the coming de-

cades [5e7].

Currently, about 37% of global primary energy is

consumed by electricity generation. In 2012 global electricity

generation stood at 22,126 TWh [8], with an annual average

growth rate of 3.0% from 1990 to 2012 [1]. Fossil fuel-based

electricity generation accounted for 68% of the total genera-

tion and coal, the most carbon-intensive fossil fuel, was the

largest contributor to the supply of electricity in 2012. Ever-

[email protected] (M. Mansouri Majoumerd).

ished by Elsevier Ltd. All rights reserved.

mailto:[email protected]

mailto:[email protected]

http://crossmark.crossref.org/dialog/?doi=10.1016/j.ijhydene.2014.08.020&domain=pdf

www.sciencedirect.com/science/journal/03603199

www.elsevier.com/locate/he

http://dx.doi.org/10.1016/j.ijhydene.2014.08.020



Nomenclature

AGR acid gas removal

ASU air separation unit

BFD block flow diagram

BUA bottom-up approach

CCS carbon capture and storage

CEPCI Chemical Engineering Plant Cost Index

COE cost of electricity

DCF discounted cash flow

EBTF European Benchmarking Task Force

EPCC engineering, procurement, and construction

costs

EU European Union

FP7 Seventh Framework Programme

GHG greenhouse gas

GT gas turbine

HHV higher heating value

HRSG heat recovery steam generator

IGCC integrated gasification combined cycle

LHV lower heating value

MEA monoethanolamine

NGCC natural gas combined cycle

NPV net present value

O&M operation and maintenance

SCGP Shell Coal Gasification Process

SCPC supercritical pulverized coal

SCR selective catalytic reduction

SOTA state-of-the-art

ST steam turbine

SWGS sour wateregas shift

TDA top-down approach

TDPC total direct plant costs

TPC total plant costs

5 Natural gas.6 Carbon capture and storage.

i n t e rn a t i o n a l j o u r n a l o f h y d r o g e n en e r g y 3 9 ( 2 0 1 4 ) 1 6 7 7 1e1 6 7 8 416772

increasing world demand for electricity represents the largest

driver of demand for primary energy consumption. Electricity

demand is projected to grow more rapidly than total energy

consumption over the next few decades [5,6]. In 2035, the

demand for electricity will be almost 70% higher than the

current demand [9].

The growing use of fossil-fuel power plants has resulted in

many environmental concerns over the past decade. The

power sector is identified as the single largest sector contrib-

uting to the emission of CO2, the most important greenhouse

gas (GHG4). Carbon dioxide emissions from the electricity and

heat supply sector were about 42% of total global CO2 emis-

sions from fossil fuels in the year 2011 [10]. Minimizing the

negative effects of growing GHG emissions resulted in the

development of environmentally-friendly technologies for

electricity production. The share of renewable energies,

therefore, has been growing significantly, thanks to govern-

mental supports and subsidies around the globe. However, the

estimated timescale for the complete transformation to

renewable resources is likely to be a substantial time away [11]

and fossil fuels are forecasted to steadily cover a major part of

the energy mix. Thus the development of suitable

4 Greenhouse gas.

technologies such as clean fossil fuel-based power technolo-

gies is urgently needed during this transition phase.

Natural gas (NG5) powergenerationoffers lessCO2emissions

compared to coal-based systems. Increasing shale gas explo-

ration and production in the United States has meant a shift in

the U.S. energy market towards higher natural gas and lower

coal consumption for the electricity generation sector [12]. This

shift resulted in more coal export from U.S., cheaper price of

coal in other continents, e.g. Europe, and consequently higher

coal consumption. In addition, wide geographical distribution,

abundant reserves, convenient transportation and storage of

coal are still maintaining the level of coal consumption in this

sector [13]. Nevertheless, in both coal- and NG-based power

plants, CO2 emissions need to bemitigated bymeans of carbon

capture and storage (CCS6) in order to achieve targeted global

GHG emissions [14]. The deployment of CCS in fossil-fired

power plants can prevent the sharp reduction of the fossil-

fuel consumption in the coming years with more restrictive

emissions regulations and higher renewable energy share.

The integrated gasification combined cycle is currently one

of the most promising technologies for the efficient use of

coal. IGCC technology benefits from its widely known envi-

ronmental credentials such as low emissions of SO2 and NOx

[15]. Although this technology suffers from high capital costs

and is perceived to be more complex than other technologies

e.g. pulverized coal plants, its significantly better emissions

performance is interesting for future large-scale deployment

[16,17]. In addition, the IGCC technology offers the opportunity

for co-gasification of biomass, good performance with lower

grade coals and other feedstock [18], and the co-production of

H2 and electricity [19]. Moreover, IGCC technology is techni-

cally well suited to CO2 capture. If CCS becomes necessary for

the next generation of fossil-based power plants, pre-

combustion carbon capture methods can be easily incorpo-

rated into the IGCC system. The additional cost due to the

capture unit will be significant, but probably lower than for

pulverized coal combustion systems [20].

With a distinct view towards the development of IGCC

technology, the European Union has sponsored the H2-IGCC

project under its Seventh Framework Programme (FP77). This

project aims todevelop anddemonstrate a complete designof a

burner for the combustion of hydrogen-rich syngas for future

generation IGCCplantwithpre-combustionCO2 capture in2014

[21]. In an effort to evolve the new generation of IGCC plant

configuration, the simulation sub-group of the H2-IGCC project

previously reported detailed simulation results for a baseline

configuration of the IGCCplant as developed in this project [22].

In another paper, subsequent simulation studies on the effects

ofvariousgasificationprocesses, aswell asof coalquality on the

performance of the selected configuration, were reported [23].

In addition to favorable technical performance, the viability

of the IGCC technology strongly depends on the overall eco-

nomic figures compared to other competing technologies. The

commercial investment in an IGCC plant requires a competi-

tive cost of electricity (COE8) [24]. An IGCC plant is not

7 Seventh Framework Programme.8 Cost of electricity.



i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n en e r g y 3 9 ( 2 0 1 4 ) 1 6 7 7 1e1 6 7 8 4 16773

considered as a standardized commercial technology with

well-established costs compared to e.g. natural gas combined

cycle [25]. However, several researchers and energy organiza-

tions assessed the COE for power generation by IGCC tech-

nology [26e32]. In spite of massive economic assessments, the

breakdown of the costs and assumptions is clear and well

documented in only a few of them [27,28]. In addition, the

majority of open literature did not touch upon a consistent

comparison with other fossil fuel-based technologies. More-

over, the sensitivity of the calculated COE to the variations of

most important input parameters is missing in most of the

recently published studies. Such plausible changes may result

in improved competitiveness of the IGCC technology compared

to other fossil-based power generation technologies and

should be clearly addressed in economic evaluations.

The main purpose of this study is to present the results of a

techno-economic assessment of the selected IGCC technology

with carbon capture performed using a tool developed by the

simulation sub-group of the H2-IGCC project. Such a tool has

provided the opportunity to modify or change the input pa-

rameters during economic assessment. The assessment is

basedonapracticalflow-sheet and realistic technical/economic

performance indicators verified by the plant's operators. The

other objective is to make a consistent and reliable comparison

between the selected IGCC plant and other fossil fuel-based

competing technologies, i.e. an NGCC and an SCPC plant based

on the same sort of economic assumptions. The natural gas

plant was selected for its wide utilization during past years and

for its bright future in a low gas price regime due to the wide-

spreadunconventional gas production incoming years [11]. The

pulverized coal plant was selected since it has been the most

prevalent coal technology worldwide over a long period [17].

Moreover, an analysis based on a literature review has been

performed to collect realistic economic data of the aforemen-

tioned state-of-the-art (SOTA9) technologies asnew-built plants

on a commercial scale. Calculations of the COEwere performed

using a set of parameters to ensure that the comparison ismade

in a consistent and fair way. All assumptions and sources of

data, more specifically those for economic assessment, have

been carefully gathered and listed in this work.

Note that the results for the IGCC plant are generally based

on the realistic performance of a series of SOTA components/

sub-systems. However, to achieve more realistic results, these

performance indicators have been justified and verified by the

operators of similar plants. The degree of confidence in the

presented results for the NGCC and SCPC is significantly higher

due to the larger number of plants in operation. Nevertheless,

the lack of full-scale capture plants in operation and the lack of

data validation should be assumed as sources of uncertainties

when considering the presented results for all plants.

10 Block flow diagram.11 Air separation unit.12 Shell Coal Gasification Process.13 Sour wateregas shift.14 Acid gas removal.15 Gas turbine.

Power plant configurations

The principal objective of this study is to present the results of

a techno-economic assessment of the selected IGCC plant

with CO2 capture. The final goal is to provide a fair and

consistent comparison with other competing technologies,

9 State-of-the-art.

i.e. an advanced SCPC power plant and an NGCC plant both

with and without CO2 capture. This section concisely presents

the selected IGCC plant configuration. Further details con-

cerning the selected IGCC plant can be obtained from a pre-

vious study [22]. The configurations of the SCPC and NGCC

plants are also briefly described here.

IGCC configuration

The block flow diagram (BFD10) of the selected IGCC configu-

ration with capture unit is shown in Fig. 1. The thermody-

namic model of the selected IGCC power plant was based on

commercially available technologies representing various

sub-systems. A cryogenic air separation unit (ASU11) is

considered as a stand-alone unit generating O2 (95% purity)

from air supplied by an intercooled main air compressor for

the coal gasification. The gasification of the coal takes place in

an O2-blown, dry-fed, entrained-flow gasifier based on the

Shell Coal Gasification Process (SCGP12). A sour water-gas shift

(SWGS13) reaction unit is used to convert the CO content in the

raw syngas to CO2 by shifting the CO with steam over a cat-

alytic bed. The acid gas removal (AGR14) unit is based on a

double-stage SELEXOL system for H2S removal in the first

absorption-regeneration stage and for CO2 capture with a rate

of 90% in the second absorption stage. The physical absorp-

tion was selected over the chemical, amine-based process due

to the high partial pressure of CO2 in the syngas downstream

of the SWGS unit. In the case of a non-capture IGCC plant, a

COS hydrolyzer is considered to convert the COS content of

the raw syngas to H2S which will be removed in the down-

stream AGR unit without CO2 capture stage.

The CO2 captured from the process (90% capture rate) is

pressurized by an intercooled compressor, aftercoooled, liq-

uefied and finally pumped up to a final pressure (110 bar). A

dehydration unit using tri-ethylene glycol is considered (H2O

content in the captured CO2 line is less than 20 mg/kg) to

prevent the corrosive effects on the transport pipeline. The

gas turbine (GT15) block including compression, combustion,

and expansion generates electric power using a generator. Gas

turbine modeling has been performed using the characteris-

tics and boundary conditions of a gas turbine which is

designed for the combustion of the H2-rich fuel produced from

upstream sub-systems. The heat recovery steam generator

(HRSG16) is based on a triple pressure level with reheat

(140 bar/530 �C/530 �C) and a steam turbine (ST17) is considered

to generate power from the steam produced at the HRSG.

Advanced SCPC configuration

As mentioned previously, the thermodynamic characteristics

of the advanced SCPC plant has been adopted from Ref. [28].

The BFD of the supercritical pulverized coal power plant is

16 Heat recovery steam generator.17 Steam turbine.



Fuel Raw

syngas

O2

Air

Slag

GascleaningGasification

ASU

Stack

To atmosphere

AirGas turbine

HP IP/LP


Compressed CO2

H2Sremoval

CO2captureSWGS

Condenser

Fig. 1 e The block flow diagram of the selected IGCC plant with CO2 capture.

CO2 product

Stack

Coal and ashhandling

Coal Pulverized coal boiler

HPturbine

IPturbine

LPturbine

Electrostaticprecipitator

FGD

Condenser

Feedwaterheatersystem

Oxidation air

Effluent Gypsum

Water

LimestoneDeNOx plant

Fluegas

Fluegas

Air

Ammonia

CO2 Capture

Fly ash

Bottom ash

Pre-heated air

Steam/water to and from capture plant

Flue gas

Compressed CO2

Fig. 2 e The block flow diagram of the advanced SCPC plant with CO2 capture.


shown in Fig. 2. The plant consists of a steam turbine, steam

generator with coal bunker bay and central switch gear. The

steam cycle consists of a triple pressure level with reheat

(300 bar/600 �C/620 �C) with extraction points for regenerative

heating of feed water and condensate. The steam boiler is

based on the SOTA Doosan Babcock two-pass single reheat

BENSON boiler. The boiler is equipped with an SOTA com-

bustion system comprising 30 Doosan Babcock low NOx axial

swirl burners and an in-furnace air-staging system for pri-

mary control of NOx emissions. A selective catalytic reduction

(SCR18) unit to control NOx emissions located between the

boiler's exit and the air heater inlet. In addition, electrostatic

precipitators and the desulphurization plant (wet limestone

base) are placed before the flue gas stack. The CO2 removal

18 Selective catalytic reduction.

unit is based on SOTA post-combustion capture technology

using chemical absorption with a capture rate of 90%. The

chemical solvent is based on a 30 wt% aqueous solution of

monoethanolamine (MEA19). Further details can be found in

Ref. [28].

NGCC configuration

The selected NGCC with CO2 capture unit is based on a heavy

duty F-class gas turbine, the Siemens SGT5-4000F, a 300 MW

single-shaft gas turbine as topping cycle [33]. This GT is

directly connected to a 50 Hz air-cooled generator running at a

fixed speed of 3000 rpm. Downstream of the GT is a triple

pressure level HRSG with reheat (120 bar/560 �C/560 �C). The

19 Monoethanolamine.




GT block has been modeled similarly to that presented for the

GT in the selected IGCC plant. However, compressor and

expander characteristics and the boundary conditions of the

GT are based on the original design, i.e. natural gas operation.

The BFD of the NGCC is illustrated in Fig. 3.

The CO2 capture unit is similar to the SCPC plant, an SOTA

post-combustion unit using standard MEA (30 wt%) with 90%

capture rate. In addition to the capture unit, an exhaust gas

condenser is considered in which the flue gas is cooled before

entering the capture unit. Moreover, a flue gas blower is

considered to compensate for pressure losses in the subse-

quent capture unit. In the current study, it is also assumed

that seawater at a temperature of 15 �C is available to satisfy

the needs for cooling in both the capture process and the

compression stage.

Fig. 3 e The block flow diagram of the NGCC power plant

with CO2 capture.

Methodology

In the current section, various simulation tools and assump-

tions made for thermodynamic modeling of the selected

power plants are briefly described. This section presents the

methodology, assumptions, and the scope of the economic

evaluation used.

Thermodynamic modeling

In order to obtain reliable results and to utilize the possibility

of incorporating detailed component characteristics, a com-

bination of different simulation tools was used for modeling

the selected IGCC power plant. Enssim tool [34] has been used

for the modeling of coal milling and drying, the gasification

process, raw syngas cooling and scrubbing. The modeling of

ASU, AGR, SWGS, CO2 compression and dehydration has been

performed using ASPEN Plus [35]. The power block including

the GT, and the triple-pressure steam cycle were modeled in

IPSEpro [36]. Further details concerning simulation works can

be found in Refs. [22,23]. The list of assumptions for each sub-

system of the selected IGCC plant is not repeated here and can

be found in Ref. [22].

Avoiding repetition of the simulation works and utilizing

previous EU20 projects' findings, the technical performance

specifications of the advanced SCPC have been adopted from

the European Benchmarking Task Force (EBTF21) report [28];

hence, the thermodynamic modeling has not been performed

in this work. Preliminary calculations performed by the

simulation sub-group of the H2-IGCC project have shown that

the coal characteristics used for the H2-IGCC project have a

negligible effect on the performance of the SCPC plant. Hence,

technical performance indicators of the advanced SCPC

remained the same as those reported by Ref. [28].

All performance data refer to plants operating at nominal

full load, in new and clean conditions. The detailed models of

the selected IGCC andNGCCplants includemany sub-systems

with reasonable assumptions based on either commercially

20 European Union.21 European Benchmarking Task Force.22 Lower heating value.23 Higher heating value.

available technology or data provided by other subgroups of

the project. Themodeling of the gas turbine in IGCC andNGCC

power plants has been performed using ISO standard condi-

tions (1.013 bar, 15 �C, 60% relative humidity). The ambient air

composition together with the characteristics of bituminous

coal and natural gas used for simulation works are shown in

Table 1.

The modeling and simulation of the NGCC was performed

using IPSEpro. The model used for CO2 capture simulation is

based on the calculation model proposed by Kohl and Nielsen

[37] and developed by M€oller [38]. A detailed description of the

model is not further presented here and can be found in Refs.

[39,40]. The specifications of the power block in the NGCC

plant are presented in Table 2.

The model acquires some input data such as information

about the exhaust gas characteristics (e.g. composition and

flow rate) and the pressure needed for the prediction of the

reboiler requirements. Due to the upper pressure limit in

IPSEpro for gaseous streams, simulation of the CO2 compres-

sion and dehydration unit has been performed using ASPEN

Plus. Table 3, which follows, shows the assumptionsmade for

the simulation of the post-combustion CO2 capture unit in the

NGCC plant using IPSEpro software tool.

Economic assessment

The cost estimation methodology for all investigated plants

with and without CO2 capture is described in this section. The

economic evaluation comprises different stages including

estimations of capital investment, fixed and variable opera-

tion and maintenance (O&M24) costs and fuel costs to calcu-

late the cost of electricity.

A publicly available report has been initially selected as a

database for economic calculations [28]. The benefit of

choosing this study is that the figures used reflect the cost of

electricity in the European power market. Furthermore, the

24 Operation and maintenance.



Table 3 e Assumptions made for simulation of the post-combustion CO2 capture in the NGCC plant.


CO2 capture rate % 90

Absorber pressure drop bar 0.15

Regeneration temperature �C 120

Reflux ratio moleH2O=moleCO2 1.0

Reboiler approach temperature �C 10

Lean/rich amine heat exchanger

approach temperature

�C 10

Absorber solvent inlet temperature �C 40

Solvent 30% MEA

Heat of reaction kJ=moleCO2 85

Inlet CO2 pipeline pressure bar 110

Water content in the CO2 pipeline mg/kg 20

Table 1 e Ambient air composition, composition andthermal properties of bituminous coal and natural gas.

Feed Parameter/component Unit Value

Air H2O wt% 0.63

N2 wt% 75.10

O2 wt% 23.01

Ar wt% 1.21

CO2 wt% 0.05

Coal Proximate analysis (dry basis)

Moisture wt% 10

Ash wt% 12.50

Volatile matter wt% 27.00

Fixed carbon wt% 50.50

LHV22 kJ/kg 25,100

HHV23 kJ/kg 26,195

Natural gas C3H8 wt% 4.02

CH4 wt% 95.53

CO2 wt% 0.40

N2 wt% 0.05

LHV kJ/kg 49,702


level of the technical performance of different plants, more

specifically the advanced SCPC, is closer to existing power

plants in Europe. A set of assumptions have been considered

in order to analyze the economic indicators of different cycles

based on a consistent basis. A Microsoft Excel-based model

has been developed containing cost data for different power

generation technologies as well as assumptions made for

economic evaluation. Such a tool provided the opportunity to

modify or change input parameters during the economic

assessment.

The economic viability of the selected cycles has been

assessed through the cost of electricity and the cost of CO2

avoided. Due to the volatility of some input parameters, a

number of sensitivity analyses have been carried out to

disclose the effect of those parameters on the economic at-

tributes of the cycle.

Table 2 e Technical specifications of the power island inthe NGCC.


Compressor inlet air flow rate kg/s 685.4

Pressure ratio e 18.2

Cooling percentage to the

compressor inlet air flow

% 23.8

Temperature increase for

1st cooling flow

�C 0

Temperature increase for

2nd and 3rd cooling flow

�C 20

Fuel flow kg/s 14.9

Combustor outlet temperature �C 1500

Expander inlet pressure bar 17.9

Exhaust gas temperature �C 577

Exhaust gas flow rate to HRSG kg/s 700.3

GT gross efficiency % 39.5

Triple pressure level HRSG bar 120/27/4.6

Steam superheating/reheat temperature �C 560

HRSG pressure drop (hot side) bar 0.04

HP steam turbine isentropic efficiency % 91

IP steam turbine isentropic efficiency % 90

LP steam turbine isentropic efficiency % 89

The COE is a standard indicator (metric) employed in the

assessment of project economics which represents the reve-

nue per unit of product that must be met to reach break-even

over the life time of a plant. It is, hence, the selling price of

electricity that generates a zero profit. For this purpose, the

net present value (NPV25) computation has been performed to

determine the COE. The cost of CO2 avoided is also a standard

cost metric indicating the cost of CO2 avoidance, which is

defined as:

Cost of CO2 avoided½V=tCO2�

¼ COECapture � COEref ½V=MWh�CO2specificref

� CO2specificcapture½tCO2=MWh�

(1)

where COE is cost of electricity generation, CO2specific is tonne of

CO2 emissions to the atmosphere per MWh (based on the net

capacity of each power plant), and the subscripts “capture”

and “ref” refer to plants with and without capture unit,

respectively. Even though the cost of CO2 avoided should

contain costs associated with transport and storage, these

costs are omitted in this study. However, the omitted costs

have no impact on the comparison outcome as applied to all

power plants in a consistent basis. Furthermore, it should be

noted that the reference plant is a similar plant to the onewith

capture unit; e.g., the reference plant of the NGCC with cap-

ture unit is the non-capture NGCC plant. The selection of a

similar reference plant has been made assuming that all

investigated technologies have a similar chance to be built in

future under a no carbon constraint scenario.

The economic assessment is based on the commercial

installation of each power plant (or nth-of-a-kind technology)

and does not cover the costs for the demonstration plants. The

following considerations have also been taken into account:

� All economic assessments are based on the reference year

2013.

� Cost estimation represents a complete power plant on a

generic greenfield site, and site-specific considerations are

not taken into account.

� The plant boundary is defined as the total power plant fa-

cility within the “fence line”.

25 Net present value.




� Costs associated with CO2 transport, storage, and moni-

toring are not included in the reported capital cost and

O&M costs, while the CO2 compression cost is included.

� All taxes with the exception of property taxes (property

taxes are included with the fixed O&M costs) are excluded.

� Any labor incentives are excluded.

� Each power plant is designed to operate at base load

operation.

� The costs associated with the plant's decommissioning are

excluded.

It should be clearly highlighted that the techno-economic

analysis presented in this article cannot provide an absolute

result, since i) there is no full-scale carbon capture unit for

power generation application, ii) the used cost data for

equipment cost calculations have some uncertainties, and iii)

assumptions made for cost calculations (e.g. capacity factor,

fuel prices, etc.) are market-dependent and uncertain by na-

ture; they can change a great deal as a function of time and

geographic location. However, the results of this work will

provide a good comparative insight highlighting the compet-

itiveness of different fossil-based power generation

technologies.

Capital costsThe capital cost assessment for the selected IGCC and NGCC

plants is based on a bottom-up approach (BUA26), while, for

the advanced SCPC plant, it is based on a top-down approach

(TDA27). The BUA is the step-count exponential costing

method using dominant parameters or a combination of pa-

rameters derived from the mass and energy balance simula-

tion. The BUA for capital costs assessment has three levels, i.e.

total direct plant costs (TDPC28), engineering, procurement

and construction costs (EPCC29), and total plant costs (TPC30)

as shown in Fig. 4(a).

The TDA is based on equipment supplier estimates of

entire EPC costs. The capital costs calculations for the

advanced SCPC are also shown in Fig. 4(b). The cost estimate

for the advanced SCPC plant without CO2 capture is based on

the TDA, while the cost estimate for the capture unit is based

on the BUA. The overall EPCC of the plant is formed by the sum

of the EPCC for the plant without CO2 capture and the EPCC for

capture unit.

The calculation of the equipment costs for a certain pro-

cess unit, based on utilization of the cost data for different

components' sizes, was performed using the following

equation:

Ci ¼ Ci;ref

�Si

�Si;ref

�f$IR (2)

where Ci is the cost of a component (sub-system), Ci,ref is the

known cost of a reference component (sub-system) of the

same type and of the same order ofmagnitude, Si is the scaling

parameter, f is the reference cost scaling exponent, and IR is

the cost index ratio. The term (f) incorporates economies of

26 Bottom-up approach.27 Top-down approach.28 Total direct plant costs.29 Engineering, procurement and construction costs.30 Total plant costs.

scale in the equation and indicates that the percentage change

in cost is smaller than the percentage change in size for each

major component. Typical values of the scaling exponent are

reported in Ref. [41]. The typical values for power utilities vary

between 0.6 and 0.7, and the value used in this study, based on

internal discussions, is 0.67. All economic assessments are

based on the reference year 2013 and the IR was adopted from

the Chemical Engineering Plant Cost Index31 (CEPCI) [42] to

incorporate the economic ups and downs (market fluctua-

tions) in the cost assessment. In the economic calculations

carried out in this study, all figures extracted from the litera-

ture given in U.S. dollars (US$) were recalculated to European

Euros (V) using the universal currency conversion XE rates

[43].

Assumptions made for economic assessmentThe assumptions made for the estimation of the capital costs,

O&M costs, and fuel costs for different power generation

technologies, i.e. the selected IGCC, the advanced SCPC, and

the NGCC power plants are presented here. Table 4, which

follows, shows the economic assumptions made for the

evaluation of capital costs for different plants within the H2-

IGCC project.

The assumptions made to estimate the O&M costs for

different power generation technologies are listed in the

following Table 5.

The coal price is 2.5V/GJ, while the NG price is 7.3V/GJ. The

fuel prices are for September 2013 and based on data available

in Ref. [46]. The coal price is based on API N2, 6000 kCal NAR

(CIF) while the NG price is based on the Zeebrugge price.

Results and discussion

The main objective of this study is to assess the competi-

tiveness of various fossil-based power generation technolo-

gies from a techno-economic point of view. The final aim is to

differentiate between these competing technologies bymeans

of the plant's performance and cost of electricity defined by

capital investment and production cost. Accordingly, ther-

modynamic performance indicators of the selected IGCC,

advanced SCPC, and NGCC power plants using the assump-

tions mentioned above are presented in the current section. It

should be observed that technical performance indicators of

the advanced SCPC plant have been adopted from the EBTF

report [28]. The second part of this section is dedicated to the

economic indicators of concerned power plants based on the

economic assumptions presented in Section methodology.

Thermodynamic performance

The overall efficiency as well as the net and gross power

outputs of the IGCC, advanced SCPC, and NGCC power plants

with and without CO2 capture is illustrated in Fig. 5. It should

be noted that the technical performances of the IGCC and

NGCC are based on the assumptions presented in Section

methodology and the simulation carried out by the system

31 Chemical Engineering Plant Cost Index.32 Discounted cash flow.



Fig. 4 e Capital costs levels and their elements for (a) the selected IGCC and NGCC plants and (b) the advanced SCPC plant.


analysis sub-group of the H2-IGCC project, while data for the

advanced SCPC plant are adopted from Ref. [28].

As shown in Fig. 5, regarding the overall efficiency of the

non-capture plants (or reference plants), the NGCC is themost

efficient plant, while the advanced SCPC plant is the least

efficient plant with 12.5 percentage points difference. This

trend is the same for the plants with capture unit, although

the difference between the NGCC and the advanced SCPC is

larger with 15.3 percentage points. The relative efficiency

penalty associated with the capture deployment (compared to

the reference plant of each technology) is 24%, 27%, and 16%

Table 4 e Assumptions made for capital costs calculations of d

Parameter

Base year 201

Equipment costsa Ad

Scaling exponent (f in Eq. (1)) 0.6

Escalation of equipment cost CE

Installation costs Pro

Escalation of installation costs Sam

The average currency exchange rate for September 2012 V0

Construction period 4 y

3 ½

3 y

2 ½

Capital investment distribution 4 y

3 ½

3 y

2 ½

Indirect costsb 14%

Project contingency 15%

10%

IGC

5%

Process contingency 5%

Owners' costsc 5%

Discounted cash flow32 (DCF) rate 8%

Inflation rate 3%

a It should be mentioned that additional costs for the GT modifications

capture is assumed to be 15%. Nevertheless, the increase in capital cost fo

the IGCC plant with CO2 capture.b The indirect costs are associated with the costs for yard improvementc This cost includes pre-production costs, inventory capital, and other o

for the IGCC, advanced SCPC, and NGCC plants, respectively.

The following Table 6 shows the other performance indicators

for the IGCC and NGCC power plants. Further information

concerning the advanced SCPC is available in Ref. [28]; hence,

it is not repeated here.

Economic performance

In the current section the results of capital costs estimation,

O&M costs, fuel costs, COE, cost of CO2 avoided, and economic

sensitivity for the selected IGCC, advanced SCPC, and NGCC

ifferent power plants with CO2 capture.

Assumption

3

opted from Refs. [27,28,44]

7

PCI

portional to the equipment costs

e as inflation rate

.7485/US$ [43]

ears for IGCC and SCPC with capture

years for non-capture IGCC and SCPC

ears for NGCC þ CCS

for non-capture NGCC

ears: 20%, 30%, 30%, 20%

years: 20%, 35%, 35%, 10% (for last half a year)

ears: 40%, 30%, 30%

years: 40%, 40%, 20% (for last half a year)

of TDPC

of the EPCC for the IGCC with capture

of the EPCC for the SCPC and NGCC with capture, and non-capture

C

of the EPCC for the non-capture SCPC and NGCC

of the EPCC for all plants

of EPCC for all plants

(real discount rate)

due to the combustion of H2 rich syngas in the IGCC plant with CO2

r the modified GT would have little impact on the total plant costs of

, buildings, sundries, and engineering services.

wners' costs (excluding any financing costs).



Table 5 e Assumptions made for O&M costs calculations of different power plants with CO2 capture.

Parameter Unit Assumptions

Capacity factora % 1st year of operation for IGCC and SCPC: 40

2nd year of operations for IGCC and SCPC: 65

Rest of plant's operational life time: 80 for IGCC and 85 for SCPC

1st year of operation for NGCC: 65

Rest of plant's operational life time for NGCC: 85

Plant life timeb Year 30 for coal-based and 25 for NG-based plants

Labor costc V/h 43.8 [28,45]

Number of labors per shift Person 30 for IGCC

25 for SCPC

22 for NGCC þ CCS

Escalation of the variable O&M costs % 3

Maintenance cost % EPC 1.5 for IGCC and SCPC with capture

1.3 for non-capture IGCC and SCPC

1.25 for NGCC with capture

1.0 for non-capture NGCC

Property taxes and insurance cost % TPC 1.5 for all plants

CO2 allowances price V/t CO2 0

a This percentage shows the operating hours of the power plant in a year at full load. It should be noted that 80% is a conservative assumption

for the capacity factor of the IGCC plant. Historical data from current IGCC plants (without CCS) showed successful operational hours up to this

level.b This period starts from commissioning and extends up to decommissioning.c Although the labor rate seems rather high, this cost includes overheads, training, etc.


power plants are presented. It should be highlighted again

that the cost estimation performed includes a level of uncer-

tainty (±30%) given the fact that there is no power plant with a

CO2 capture unit in operation and based on the methodology

selected for cost assessments, i.e. using available equipment

cost data.

Capital costsFig. 6 illustrates different components of the total plant costs

for the selected IGCC, advanced SCPC, and NGCC power plants

with and without CO2 capture unit. As shown in Fig. 6, the

lowest capital investment is required for the NGCC plant

without CO2 capture unit. Even with the CO2 capture feature,

the NGCC requires less capital investment compared to the

cheapest coal technology, i.e. the advanced non-capture

SCPC. The results also show one important advantage of the

IGCC cycle compared to the other coal technology, the

advanced SCPC plant, when the CO2 capture is incorporated

Fig. 5 e The overall plant efficiency and power output of

various fossil-based power plants.

into the system and that is less capital requirement for CO2

capture deployment.

The following Table 7 shows different cost indicators such

as total plant costs and specific investment for the concerned

power plants. The updated cost figures for the advanced SCPC

plant are also given in Table 7 based on the assumptions

presented in Section methodology. As mentioned, the calcu-

lations of capital costs for the selected IGCC and NGCC plants

are based on a bottom-up approach. In contrast, the capital

costs calculation for the SCPC is based on a top-down

approach. Therefore, the total equipment costs and installa-

tion costs are not explicitly given for the advanced SCPC plant.

As shown in Table 7, the highest absolute capital invest-

ment is required for the SCPC plant with CO2 capture. How-

ever, it should be noted that the production capacity (or power

output) of the advanced SCPC is higher than those for the IGCC

and NGCC plants. As shown in Fig. 6, a better indicator is the

specific investment of a certain plant, in which the capacity of

the plant is embedded in the value. Please note that indirect

costs, owner's costs and contingencies are based on the as-

sumptions given in Section methodology, and these cost in-

dicators for the SCPC plants (with and without capture) have

been calculated backward using the updated EPC costs.

O&M costs and fuel costsTable 8 presents the calculated operation and maintenance

costs for the selected IGCC plant, advanced SCPC, and NGCC

power plants. The calculated labor costs seem on the high

side. However, it should be mentioned that any training,

holidays, pension, overheads, etc. are included in the

assumed labor costs. Since the details of variable O&M costs

were not available for the advanced SCPC, the variable cost

items have been escalated using the same rate as the inflation

rate from the year of cost data to the base year of this study

(i.e. 2013). Amongst plants with capture, the selected IGCC



Table 6 e Thermodynamic performance indicators of the IGCC and NGCC plants with(out) CO2 capture.

Parameter Unit IGCC NGCC

Non-capture Capture Non-capture Capture

Gross plant's power output MW 521.5 490.7 429.4 384.7

Net plant's power output MW 461.7 394.4 428.0 359.3

Overall efficiency %LHV 47.0 35.7 58.0 48.7

Fuel flow kg/s 39.1 44.0 14.9 14.9

Gas turbine net power output MW 304.4 314.0 288.6 288.6

Steam turbine net power output MW 217.1 176.7 140.8 96.1

Total auxiliaries MW 59.8 96.3 1.3 25.4

- HRSG pumping power MW 2.7 3.4 1.3 1.3

- Gasification power demand MW 4.4 4.9 e e

- ASU compression power demand MW 43.5 48.9 e e

- AGR pumping and compression power demand MW 0.7 10.8 e e

- AGR refrigeration power demand MW 8.5 8.5 e e

- CO2 compression power demand MW e 19.7 e 11.3

- CO2 capture plant including blower, etc. MW e e e 12.8

Specific CO2 emissions t CO2/MWh 0.70 0.08 0.35 0.04


plant has the highest specific fixedO&Mcosts, while the NGCC

has the lowest costs. This trend is similar for the non-capture

plants. The advanced SCPC in both capture and non-capture

cases requires 5% and 13% less fixed O&M costs compared to

the corresponding IGCC cases, respectively.

With respect to the variable O&M costs, the advanced SCPC

with and without capture unit has the highest costs. Similarly

to the fixed O&M costs, the NGCC in both cases (capture and

non-capture) has the lowest costs compared to the corre-

sponding capture or non-capture cases in other plants.

The fuel costs for the selected IGCC, advanced SCPC, and

NGCC power plants with and without CO2 capture are illus-

trated in Fig. 7. Please note that the amount of fuel (or annual

fuel costs) from capture case to non-capture case only

changes for the IGCC plant, as the capture takes place up-

stream of the GT. The estimation results of the fuel costs

shown in Fig. 7 confirm that the specific fuel costs (V/MWh

net) are more than two times higher for the NGCC plant than

for other technologies in both capture and non-capture cases.

Fig. 7 also shows that clean fossil fuel-based power generation

(i.e. plants with capture unit) will cause increased primary

energy consumption (i.e. an increased CO2 production) but a

Fig. 6 e The breakdown of the specific total plant costs for

various power plants.

lower CO2 emission compared to corresponding non-capture

plants.

Costs of electricity generation and CO2 avoidanceAs mentioned before, the cost of electricity in this study is

calculated as the break-even point for the electricity selling

price. Fig. 8, which follows, shows the breakdown of the cost

of electricity into different cost elements for various investi-

gated power plants, viz. the selected IGCC, the advanced SCPC,

and the NGCC power plants. As shown in Fig. 8, the cost of

electricity for the advanced SCPC plant with capture unit is

higher than the corresponding values for the selected IGCC

and NGCC plants with capture unit. The COE for the non-

capture NGCC plant is the highest among other non-capture

plants. The difference in the COE between the most expen-

sive non-capture technology (i.e. the non-capture NGCC) and

the cheapest power generation technology (i.e. the advanced

SCPCwithout capture unit) is only 4%. The difference between

the most expensive and cheapest technologies with capture

plants is only 6%. Nevertheless, supporting any decision

against or in favor of one of the concerned technologies based

purely on the estimated COE is not wise as the difference

between the COEs is marginal (when plants from one cate-

gory, i.e. either with capture or without, are compared

together).

The other important aspect which is not shown in Fig. 8 is

the share (percentage) of each cost element in the COE for a

certain technology. The highest capital costs share is related

to the IGCC plant without capture unit (~55% of the COE). The

share of fuel costs is about 60e70% of the cost of electricity for

the NGCC plant (with and without capture unit), while it is

approximately 30% of the COE for the other power plants. The

highest fixed O&M costs share is related to the selected IGCC

plant with capture unit (~15% of the COE), while the COE for

the advanced SCPC with capture has the highest share of

variable O&M costs (~8% of the COE).

The cost of CO2 avoided is also calculated based on the

equation presented in Section methodology. The cost for CO2

avoided is in fact the break-even price for CO2, where it starts

to make economic sense to build plants with carbon capture.



Table 7 e The capital costs for the selected IGCC, SCPC, and NGCC plants with(out) CO2 capture.

Cost components Unit IGCC SCPC NGCC

Non-capture Capture Non-capture Capture Non-capture Capture

TPC þ DCF (8%)a MV 1094 1392 1697 2066 347 729

TPC MV 899 1144 1434 1699 304 619

Owner's costs and contingencies MV 150 229 187 283 40 103

EPCC MV 750 916 1247 1416 264 515

Indirect costs MV M 112 153 174 32 63

TDPC MV 657 803 1093 1242 232 452

Total equipment costsb MV 356 427 e e 136 237

Installation costsb MV 302 376 e e 96 215

Specific investment (gross) V/kW gross 1725 2332 1750 2482 708 1608

Specific investment (net) V/kW net 1948 2902 1901 3091 710 1723

a This value is to consider the escalation during the construction period.b This value is not available for the advanced SCPC plant since it is based on a top-down approach.


This cost for different technologies with capture unit when

compared to similar reference plants without capture unit is

illustrated in Fig. 9. Please note that the costs associated with

transport and storage are excluded from the cost of CO2

avoided. The specific CO2 emissions for each technology with

or without CO2 capture unit are also shown in Fig. 9.

The reason for such a high avoidance cost for the NGCC is

the low specific emissions from the plant without capture unit

which, according to Eq. (1) (presented in Section economic

assessment), results in a high CO2 avoided cost. The CO2

avoided cost shown in Fig. 9 might be a better indicator

compared to the COE to support which technology is better for

CO2 mitigation. However, it should be noted that costs asso-

ciated with transport and storage will increase the presented

cost of CO2 avoided and will change the trend shown in Fig. 9.

Economic sensitivityIn order to evaluate the sensitivity of the COE to variations in

the inputs for each plant, an economic sensitivity analysis has

been performed to identify the most influential parameter

with the strongest impact on the results. Two parameters are

considered as the most uncertain parameters for the calcu-

lation of the COE. These parameters are the capacity factor (or

load factor) of the plant and the fuel price. The variation range

of capacity factor is 40e90%. The upper limit is selected based

on the technical limitations such as minimum time required

for any overhaul and maintenance activities. The lower limit

is selected based on the experience during recent years which

Table 8 e The operation and maintenance costs for the IGCC, U

Cost item Unit IGCC

Non-capture

Fixed O&M costs

Labor costs MV/a 9.6

Maintenance costs MV/a 9.9

Property taxes and insurance costs MV/a 13.7

Total fixed O&M costs MV/a 33.1

Specific fixed O&M costs V/kW gross/a 63.5

Variable O&M costs

Total variable O&M costs MV/a 4.0

Specific variable O&M costs V/MWh net 1.2

confirms decreasing electricity production form fossil-based

plants. It is assumed that the load of power plants remains

constant at the design condition. The fuel prices also vary 50%

from the prices presented in Sectionmethodology. The results

of the sensitivity analysis under the variation of the plant'scapacity factor and the fuel price are shown in Fig. 10(a) and

(b), respectively. Please note that the capacity factor for the

IGCC plant (with and without capture) is 80%, while it is 85%

for the other technologies. Please also note that each plant is

compared to its reference COE (at mentioned capacity factor

or fuel price in Section methodology).

Results in Fig. 10 highlight possible drivers which may in-

fluence market attention on different technologies. It is

evident from this figure that the COE for both NGCC plants

(with and without capture unit) is less sensitive to changes of

capacity factor compared to other plants. The COE for the

advanced SCPC is the most sensitive amongst concerned

technologies. As shown in Fig. 10(b), the change of fuel price

has a significant effect on the COE for the NGCC with and

without capture unit. Any reduction in the NG price will

change the market tendency towards higher electricity pro-

duction from NGCC plants compared to coal-based technolo-

gies, even at a similar reduction in the coal price.

It should be highlighted that economic sensitivity analysis

could be performed based on variation in the cost of CO2 al-

lowances. However, the impact of CO2 allowances cost on the

COE would be negligible (more specifically for the plant with

capture unit as most of the carbon emissions were already

SCPC, and NGCC plants with(out) CO2 capture.

SCPC NGCC

Capture Non-capture Capture Non-capture Capture

11.5 7.7 9.6 6.5 8.4

13.8 16.2 21.2 2.7 6.5

17.2 21.5 25.5 4.6 9.3

42.5 45.4 56.3 13.8 24.3

86.6 55.4 82.2 32.2 63.1

5.2 10.7 28.4 2.8 4.7

1.9 1.9 6.9 0.9 1.7



Fig. 7 e Annual fuel costs and specific fuel costs for

different power plants.

Fig. 8 e The breakdown of the cost of electricity for the

selected IGCC, the advanced SCPC, and the NGCC power

plants with(out) CO2 capture.

Fig. 9 e The cost of CO2 avoided, COE, and specific CO2

emissions for the selected IGCC, advanced SCPC, and

NGCC.

Fig. 10 e Sensitivity response of the COE for different

power plants under variation of (a) the capacity factor and

(b) fuel price.


captured from the plants), as the absolute value of CO2 al-

lowances cost is very low (about 5.5V/t CO2 [46]) and currently

any large variation could not be expected. Nevertheless, its

influence will change depending on the CO2 market develop-

ment and changes in global mitigation policies.

Conclusion

The thermodynamic performance indicators of various power

plants including IGCC, advanced supercritical pulverized coal

and natural gas combined cycle power plants were presented

in this article. The NGCC is the most efficient plant, while the

advanced SCPC plant is the least efficient plant amongst non-

capture cases. This trend is similar for the plants with capture

unit. The relative efficiency penalty associated with the cap-

ture deployment (compared to the reference plant of each

technology) is 24%, 27%, and 16% for the IGCC, advanced SCPC,

and NGCC plants, respectively.

A comparative study was also conducted, comparing the

COE and the cost of CO2 avoided for thementioned fossil-based

power plants. The economic performance indicators of each

plant were estimated using the developed model and the




results are presented and thoroughly discussed. It should be

highlighted that the estimation is highly dependent on the

selected assumptions. It is also important to note that techno-

economic analysis cannot provide an absolute result, since the

cost data and assumptions are uncertain by nature. The COE

for the IGCC plant with and without capture is 91 and 59 V/

MWh, respectively. The COE for the advanced SCPC is 96 and

59V/MWh for the capture and non-capture cases, respectively.

The COE for the NGCCwith andwithout capture is 61 and 91V/

MWh, respectively. The results show that the less capital-

intensive plant is the NGCC plant without CO2 capture. How-

ever, the high fuel costs for this plant decrease the gap between

the COE for this plant compared to that for the other plants.

The COE for the NGCC technology was the most sensitive to

changes in the fuel price amongst other COEs for different

technologies. However, the COE for the NGCC technology was

also the least sensitive to variations of the plant's capacity

factor. The estimated costs of CO2 avoided for the IGCC, SCPC,

and NGCC technologies are 51, 57, 99 (V/t CO2 avoided).

Results highlighted that, based purely on the COE for

different plants, it cannot be concluded which technology is

better and more cost-effective than other technologies,

considering the level of uncertainty in the economic results of

this study (±30%). Other main drivers such as proven tech-

nology and operational flexibility will, therefore, play an

important role in the widespread utilization of these

technologies.

Acknowledgment

The authors are grateful to the European Commission'sDirectorate-General for Energy for financial support of the Low

Emission Gas Turbine Technology for Hydrogen-rich Syngas

(H2-IGCC) project with the grant agreement number of 239349.

The authors wish to acknowledge Chris Lappee at Vattenfall

for sharing constructive opinions about the selection of cost

estimating methodology as well as results and discussion of

this article. The authors are also thankful to Han Raas at

Vattenfall for performing the gasification simulations, Karel

Dvorak and Adam Al-Azki at E.ON UK for being involved in

many discussions at different stages of the H2-IGCC project.

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