Carbon Dioxide Emission Management in Power Generation [1. ed.] 3527347534, 9783527347537

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Carbon Dioxide Emission Management in Power Generation

Carbon Dioxide Emission Management in Power Generation Lars O. Nord Olav Bolland

Authors Prof. Lars O. Nord

NTNU - Norwegian University of Science and Technology Department of Energy and Process Engineering Kolbjørn Hejes vei 1B NO-7491 Trondheim Norway

All books published by Wiley-VCH are carefully produced. Nevertheless, authors, editors, and publisher do not warrant the information contained in these books, including this book, to be free of errors. Readers are advised to keep in mind that statements, data, illustrations, procedural details or other items may inadvertently be inaccurate.

Prof. Olav Bolland

Library of Congress Card No.:

NTNU - Norwegian University of Science and Technology Faculty of Engineering Høgskoleringen 6 NO-7491 Trondheim Norway

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v

Preface The International Panel on Climate Change (IPCC) Fifth Assessment Report (IPCC-WG1 2013) states that it is extremely likely (≥95% probability) that human activities caused more than half of the observed increase in global average surface temperature from 1951 to 2010. In order to reduce the man-made warming, concerted action to mitigate emissions of greenhouse gases is now needed. The main greenhouse gas generated by human activities is carbon dioxide (CO2 ). Other important greenhouse gases produced from human activities are methane (CH4 ) and nitrous oxide (N2 O). CO2 is produced mainly by the combustion of fossil fuels in the power sector, manufacturing industry, and in the transport sector and also in the production of energy carriers and services. Projections by the International Energy Agency indicate that fossil fuels will be the dominant source of energy until 2030 and most likely beyond. It is, therefore, becoming increasingly important that we develop and deploy mitigation technologies that can make significant reductions in CO2 emissions in all sectors. This book covers both CO2 capture technologies as well as power generation technologies. These are strongly coupled when capturing CO2 from power plants. CO2 capture technologies have many of the same components found in various chemical plants, while power generation technologies is a different world where power engineering and mechanical engineering rule the ground. CO2 capture makes it necessary to deal with these areas simultaneously, with a communication between a more diversified group of engineers and scientists that is common today. It is even more complex than that because CO2 capture is also strongly coupled to transport and storage of the CO2 , which brings geologists and reservoir engineers into the game. Another aspect of this is that if CO2 capture and storage make sense, it needs to be done on a very large scale – with big implications to not only the energy industry but also to the society in general. This makes it necessary to have the economists and social sciences taking part in the development of CO2 capture and storage technologies. Note that biomass as fuel and Bio-CO2 capture and storage (CCS) are not included in the book. Although many of the same aspects on power plant technologies and CO2 capture as for fossil fuels also apply to biomass, we believe that this subject deserves a separate treatment together with other potential negative CO2 emission technologies.

vi

Preface

Both authors have a mechanical engineering background. Olav Bolland was active in the CCS field from the late 1980s until 2017 and has led and participated in many national and European projects within CCS. Lars Nord worked in the power generation industry for seven years before returning to academia in 2006 to pursue a PhD degree within CCS under Bolland’s supervision. This work has continued until now. Both Bolland and Nord are working at NTNU – The Norwegian University of Science and Technology in the Faculty of Engineering. Some notes on terminology in the book are as follows: • The commonly used term oxy-fuel (or oxyfuel) is not used in this book because of the misconception of having an oxidised fuel, like nitromethane (CH3 NO2 ). Instead, the term oxy-combustion is used, which the authors believe describes the combustion in an oxygen-enriched environment more accurately. The term oxy-fuel combustion has also been extensively used in the literature. • The off-gas coming from a power plant, engine, or any other type of combustion device is sometimes referred to as flue gas and other times as exhaust gas. The latter is mostly used for gas turbines and other types of engines, while the former is mostly used for combustion plants like a coal-fired power plant or any type of furnace. Flue gas is the term used in this book with a few exceptions. With hopes of a good read for you! 8 November 2019

Lars O. Nord and Olav Bolland Trondheim, Norway

vii

Contents Acknowledgements xiii Nomenclature xv Organisation and Use of Book xxiii Introduction 1

1 1.1 1.2 1.3 1.4 1.5 1.6 1.7 1.8 1.9 1.10 1.11

Greenhouse Effect 1 Atmospheric CO2 3 Natural Accumulations and Emissions of CO2 4 Man-made Emissions of CO2 7 Climate Change 9 Fossil Fuel Resources 9 Definition and Rationale of CO2 Capture and Storage (CCS) Magnitude of CCS 12 Public Acceptance of CCS 13 Show-stoppers for CCS Deployment? 15 History of CCS 16

2

Long-Term Storage of CO2

2.1 2.2 2.2.1 2.2.2 2.2.3 2.2.4 2.3 2.4 2.5 2.6 2.7 2.8 2.9

19 Storage Time and Volume 19 Underground Storage 20 Aquifer 20 Enhanced Oil Recovery (EOR) with CO2 22 Enhanced Gas Recovery (EGR) 28 Enhanced Coal Bed Methane Recovery (ECBM) 29 Ocean Storage 29 Mineral Carbonation 30 Industrial Use – Products 31 Requirements for CO2 Purity and Transportation 32 CO2 Compression and Conditioning 35 Transportation Hazards of CO2 38 Monitoring of CO2 Storage 39

10

viii

Contents

3.1 3.2 3.2.1 3.2.2 3.2.3 3.2.4 3.2.5 3.3 3.4

41 Coal 41 Liquid Fuels 46 Diesel 46 Methanol 48 Ethanol 48 Kerosene 49 Ammonia 49 Gaseous Fuels 49 Fuel Usage 51

4

CO2 Generation, Usage, and Properties 53

4.1 4.2 4.3 4.4 4.5 4.5.1 4.5.2 4.5.3 4.6 4.6.1 4.6.2 4.6.3 4.6.4 4.6.5 4.6.6 4.6.7 4.6.8 4.6.9 4.6.10 4.6.11 4.7 4.8 4.8.1 4.8.2 4.8.3 4.8.4 4.8.5 4.8.6

Short on CO2 53 CO2 Chemistry and Energy Conversion 53 Combustion 57 Analogy Between CO2 Capture and Desulfurisation 58 Industrial Processes 60 Ammonia Production 60 Cement Production 60 Aluminium Production 61 How Do We Use CO2 ? 61 Chemicals and Petroleum 62 Metals 62 Manufacturing and Construction 62 Food and Beverages 62 Greenhouses 63 Health Care 63 Environmental 63 Electronics 63 Refrigerant 64 CO2 Laser 64 Miscellaneous 64 CO2 and Humans 65 Properties of CO2 67 Density and Compressibility 69 Specific Heat Capacity 70 Ratio of Specific Heats 71 Thermal Conductivity 72 Viscosity 73 Solubility in Water 74

5

Power Plant Technologies 77

5.1 5.1.1 5.1.2 5.1.3 5.1.4

Coal-Fired Power Plants 77 Steam Cycle in a Coal Power Plant 77 Pulverised Coal Combustion (PCC) 80 Circulating Fluidised Bed Combustion (CFBC) 82 Pressurised Fluidised Bed Combustion (PFBC) 84

3

Fuels

Contents

5.1.5 5.1.5.1 5.1.5.2 5.1.5.3 5.2 5.2.1 5.2.2 5.2.3 5.2.4 5.2.4.1 5.2.4.2 5.2.4.3 5.2.5 5.2.6 5.3 5.3.1 5.3.2 5.4 5.4.1 5.4.2 5.4.3 5.4.4 5.5 5.5.1 5.5.2 5.5.3 5.5.4 5.6 5.7 5.7.1 5.7.2 5.7.2.1 5.7.2.2 5.7.2.3 5.7.2.4 5.7.2.5 5.7.3 5.7.3.1 5.7.3.2 5.7.3.3 5.7.3.4 5.7.3.5 5.7.3.6 5.7.3.7 5.7.3.8

Integrated Gasification Combined Cycle (IGCC) 86 Process Design 86 IGCC Availability 87 IGCC Efficiency 88 Gas Turbine Power Plants 88 Gas Turbines 88 Classification of Gas Turbines 93 Gas Turbines and Fuel Quality 94 Gas Turbine Performance Model 95 Compressor 97 Air Filter 97 Turbine 98 Part-load Performance of a Gas Turbine in a Combined Cycle Diluted Hydrogen as Gas Turbine Fuel 99 Combined Cycles 105 Combined Gas Turbine and Steam Turbine Cycles 105 Cycle Configurations 106 Heat Recovery Steam Generators 109 Introduction 109 Properties of Water/Steam 110 Dew Point of Flue Gas – Possible Corrosion 110 TQ Diagram for Steam Generation 111 Steam Cycle Cooling Systems 113 Direct Water Cooling of the Condenser (A) 113 Water Cooling with Wet Cooling Tower (B) 115 Air-Cooled Condenser (C) 116 Water-cooling with Dry Cooling Tower (D) 116 Internal Combustion Engines 118 Flue Gas Cleaning Technologies in Power Plants 118 Particle Removal from Flue Gas 119 Flue Gas Desulfurisation (FGD) 119 Wet Scrubbers 120 Spray Dry Scrubbers 120 Sorbent Injection Processes 121 Dry Scrubbers 121 Seawater Scrubbing 121 NOx Reduction 121 Dry Low NOx Burners 122 Fuel Staging 122 Reburning 122 Flue Gas Recirculation 122 Water and Steam Injection 122 Selective Catalytic Reduction (SCR) 123 Selective Non-catalytic Reduction (SNCR) 123 Mercury Control 124

98

ix

x

Contents

6.1 6.2 6.2.1 6.2.2 6.2.3 6.2.4 6.3 6.4

125 Gas Separation in CO2 Capture 125 Theory of Compression and Expansion 126 Closed Systems 126 Open Flow Systems 127 Isothermal Compression 130 Compression and Expansion with Irreversibilities 130 Theory of Separation 131 Minimum Work Requirement for Separation – Examples 135

7

Power Plant Efficiency Calculations 141

7.1 7.2 7.3 7.4 7.5 7.6 7.7 7.8

General Definition of Efficiency 141 Definition of the Term ‘Efficiency’ 142 Fuel Energy 142 Efficiency Calculations 146 Heat Rate Versus Efficiency 148 Additional Consumption of Fuel for CO2 Capture 149 Relating Work Requirement for CO2 Capture and Efficiency Terms Related to CO2 Accounting 153

8

Classification of CO2 Capture Methods 159

8.1 8.2 8.2.1 8.2.2 8.2.3 8.3

Following the CO2 Path 159 Principles for Combining Power Plants and CO2 Capture 162 Post-combustion CO2 Capture 163 Pre-combustion CO2 Capture 163 Oxy-combustion CO2 Capture 163 Dilution of CO2 163

9

CO2 Capture by Gas Absorption 167

9.1 9.2 9.3 9.3.1 9.3.2 9.3.3 9.3.4 9.4 9.5 9.6

Theory of Absorption 167 Absorption Process 170 Solvents for Absorption 173 Chemical – Organic 174 Chemical – Inorganic 178 Physical Solvents 181 Ionic Liquids 183 Solvent Contaminants 185 Solvent Loading 187 Energy Use in Absorption Processes 187

10

CO2 Capture by Other Gas Separation Methods 189

10.1 10.1.1 10.1.2 10.1.2.1 10.1.2.2

Membranes 189 General Information About Membranes 189 Inorganic Membranes for H2 , O2 , and CO2 Separation 191 Dense Pd-Based Membranes for Hydrogen Separation 192 Dense Electrolytes and Mixed Conducting Membranes 192

6

Theory of Gas Separation

150

Contents

10.1.2.3 10.1.3 10.1.3.1 10.1.3.2 10.1.3.3 10.1.4 10.1.5 10.1.6 10.2 10.2.1 10.2.2 10.2.3 10.3 10.4 10.5 10.6 10.7

Microporous Membranes for Hydrogen or CO2 Separation 195 Polymeric Membranes for CO2 Separation 196 Dense Polymeric Membranes 196 Polymeric Membranes with Fixed-site-carrier (FSC) 197 Polymeric Membranes Supported Liquid Membrane (SLM) 197 Membrane Absorber 197 Flux Through Membranes 199 Challenges Facing Membrane Technology 200 Adsorption 201 General About Adsorption 201 Adsorbent Material 202 Adsorption–Desorption 205 Calcium Looping 206 Anti-sublimation 207 Distillation 208 CO2 Hydrate Formation 209 Electrochemical Separation Processes 209

11

Removing Carbon from the Fuel – Pre-combustion CO2 Capture 211

11.1 11.2 11.3 11.4 11.4.1 11.4.2 11.4.3 11.4.4 11.5 11.6 11.6.1 11.6.2 11.6.3 11.6.4 11.6.5 11.6.6 11.6.7 11.6.8 11.7 11.8 11.9 11.10 11.11 11.11.1 11.11.2 11.11.3 11.11.4

Principle 211 Hydrogenator and Desulfuriser 212 Pre-reforming 212 Reformers 214 Steam Reforming (SR) 215 Partial Oxidation Reforming (POX) 215 Autothermal Reforming (ATR) 216 Combined Reforming 217 Gasification Theory and Principles 218 Gasifiers 221 Sasol–Lurgi Dry-ash Gasifier 223 BGL Gasifier 223 High-temperature Winkler (HTW) 225 General Electric Gasifier 226 Shell Gasifier 226 ConocoPhillips E-Gas Gasifier 227 Siemens SFG Gasifier 227 Selection of Gasifiers 227 Syngas Quenching 229 Syngas Coolers 230 COS Hydrolysis 230 Water—Gas Shift (WGS) 231 Integrated Pre-combustion Approaches 233 Membrane-Enhanced Water–gas Shift 233 Sorption-Enhanced Water-gas Shift 234 Membrane-Enhanced Reforming 235 Sorption-Enhanced Reforming 238

xi

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Contents

12.1 12.2 12.2.1 12.2.2 12.3

Pre-combustion CO2 Capture in Power Cycles 239 Classification 239 IGCC with CO2 Capture 239 Process Design 239 IGCC with CO2 Capture – Efficiency 242 IRCC – Integrated Reforming Combined Cycle 243

13

Post-combustion CO2 Capture in Power Cycles 247

13.1 13.2 13.3 13.4 13.5 13.6

Classification 247 Power Plant with Absorption of CO2 from the Flue Gas 249 Post-combustion Efficiency Penalty – Absorption 251 Steam Turbine Steam Extraction 251 Flue Gas Pressure Drop 253 Post-combustion CO2 Capture at Atmospheric Pressure with Flue Gas Recirculation (FGR) 255 Post-combustion CO2 Capture at Elevated Pressure 256 High-Pressure CO2 Absorption Cycle 256 Sargas Cycle 258 Combicap Cycle 259

12

13.7 13.7.1 13.7.2 13.7.3 14

14.1 14.2 14.2.1 14.2.2 14.2.3 14.2.4 14.3 14.3.1 14.3.2 14.4 14.4.1 14.4.2 14.4.3 14.4.4 14.4.5 14.4.6 14.4.7 14.4.8

Oxy-combustion CO2 Capture in Power Cycles 261 Classification 261 Air Separation for Production of Oxygen 264 Methods and Applications 264 Air Separation by Cryogenic Distillation 266 Mixed Conducting Membrane 271 Chemical Looping Combustion (CLC) 272 Oxy-combustion with Coal 274 Pulverised Coal Oxy-combustion 274 Circulating Fluidised Bed Oxy-combustion 276 Oxy-combustion with Natural Gas 277 Water Cycle 277 S-Graz Cycle 278 MATIANT Cycle 279 Allam Cycle 279 SCOC-CC 279 AZEP – Advanced Zero Emission Power Plant 280 Solid Oxide Fuel Cell (SOFC) with CO2 Capture 280 Chemical Looping Combustion (CLC) with Natural Gas 284 References 285 Glossary

307

Index 311

xiii

Acknowledgements We convey our thanks to many persons that in one way or another have been involved in the book. Thanks to Olav Kaarstad for inputs to CO2 storage, Kjell Erik Rian for gas compression and separation, Ivar Ertesvåg for efficiency definitions and separation work, and Tord Ursin for efficiency calculations and definitions. Multiple experts have provided inputs and feedback on the CO2 capture methods including Hallvard Svendsen for gas absorption, Konrad Eichhorn Colombo for inputs on membranes and the AZEP, May-Britt Hägg on membranes, Giorgia Mondino on adsorption, Ed Blekkan on gas reforming, Ola Maurstad on coal gasification, and Peter Koch on combustion. Thank you all! For proofreading, we thank Zeinab Amrollahi, Aldo Bischi, and Rahul Anantharaman. Many thanks to Konstantinos Kyprianidis and the SOFIA research group at Mälardalen University for hosting Lars Nord during his sabbatical under which the book was finalized. And of course, last but not the least, we thank our wives Synnøve (Olav) and Nataša (Lars) for the patience and having to hear more than you probably have liked to about this book.

xv

Nomenclature Latin Symbols

a

effective interfacial area per unit volume of packing

m2 /m3

A

cross-sectional area

m2

Am

membrane surface area

m2

cp

specific heat capacity at constant pressure

kJ/(kg K)

cv

specific heat capacity at constant volume

kJ/(kg K)

dg

abundance of gas component g

kg

F

Faraday constant

—

h

specific enthalpy on mass basis

kJ/kg

h

specific enthalpy on molar basis

kJ/kmol

h

specific enthalpy of formation on molar basis

kJ/kmol

H

enthalpy

kJ

H0

enthalpy of formation

kJ

He

Henry’s law constant

Pa/kmol fraction gas in liquid

′

Henry’s law constant

(Pa m3 )/kmol gas in liquid

HHV

higher heating value

kJ/kg

HR

heat rate

kJ/kWh

Ji

flux through a membrane

m/s

LHV

lower heating value

kJ/kg

0

He

xvi

Nomenclature

m

mass

kg or t

ṁ

mass flow rate

kg/s

MW

molecular weight

kg/kmol

n

polytropic coefficient

—

ni

number of moles for specie i

mol

Nu

Nusselt number

p

absolute pressure

Pa, bar

pf

partial pressure of the permeated gas at the feed side of a membrane

Pa, bar

pi

partial pressure of component i

Pa, bar

pp

partial pressure of the permeated gas at the permeate side of a membrane

Pa, bar

P

membrane permeability

m3 (STP)/(m h bar)

Pr

Prandtl number

qi

gas adsorbed per unit mass of adsorbent

mol gas/kg adsorbent

qp,i

volumetric flow rate through membrane

m3 (STP)/h

Q Q̇

heat

kJ

heat transfer rate

kW

r

radiative forcing

W/(kg m2 )

R

specific gas constant

kJ/(kg K)

Ru

universal gas constant

kJ/(kmol K)

Re

Reynolds number

s

specific entropy on mass basis

kJ/(kg K)

S

entropy

kJ/K

Sads

adsorption selectivity

—

t

time

s or h

tm

membrane thickness

T

temperature

m ∘ C or K

u

absolute velocity

m/s

U

internal energy

kJ

v

specific volume on mass basis

m3 /kg

V

volume

m3

Nomenclature

V̇

volumetric flow rate

m3 /s

w

specific work on mass basis

kJ/kg

w

specific work on molar basis

kJ/kmol

W Ẇ

work

kJ

power

kW

x

vapour quality

kgvapour /kgvapour+liquid

xi

mole fraction in liquid phase for component i

—

yi

mole fraction in gas phase for component i

—

Z

compressibility factor

—

Greek Symbols

𝛼

heat-to-power ratio

kWh /kWe

𝛼 i,j

membrane selectivity of components i and j for gas mixture

—

0 ΔHreaction

heat of reaction

kJ

𝜂 cap,e

CO2 capture efficiency

—, %

𝜂

efficiency

—, %

𝜂 cap

CO2 capture ratio

—, %

𝜂 is

isentropic efficiency

—, %

𝜂p

polytropic efficiency

—, %

𝜅

ratio of specific heats, cp /cv

—

𝜆

excess air ratio

—

𝜉

friction factor

—

𝜌

density

kg/m3

𝜎

ionic conductivity

S/m

𝜎 inj

CO2 formation by combustion per tonne of CO2 injected

t CO2 by combustion/t CO2 injected

𝜎 store

CO2 formation by combustion per tonne of CO2 stored

t CO2 by combustion/t CO2 stored

xvii

xviii

Nomenclature

𝜑

equivalence ratio (1/𝜆)

—

𝜙

ratio of additional oil or gas to CO2 injected

t fuel/t CO2

𝜒

CO2 generated per lower heating value of fuel

kg CO2 /MJ

𝜓

CO2 formation by combustion per tonne of CO2

t CO2 /t fuel

𝜔

ratio of recycled CO2 to stored CO2

t CO2 recycled/t CO2 stored

Abbreviations ACGIH AEPD AMP AMPD Ar ASHRAE ASU ATR AZEP BGL BoA

BOD CA CAR CC CCS CF CFB CFBC CH4 CHP CLC CLM CO CO2 COS CPO

American Conference of Governmental Industrial Hygienists 2-amino-2-ethyl-1,3-propandiol 2-amino-2-methyle-1-propanol 2-amino-2-methyl-1,3-propandiol Argon American Society of Heating, Refrigeration and Air Conditioning Engineers air separation unit autothermal reforming advanced zero emission power plant British Gas Lurgi Braunkohlekraftwerk mit optimierter Anlagentechnik (lignite-fired or Brown coal-fired power station with optimised plant engineering) biological oxygen demand carbonic anhydrase ceramic autothermal recovery combined cycle carbon dioxide (CO2 ) capture and storage correction factor (considers real gas effects) circulating fluidised bed circulating fluidised bed combustion methane combined heat and power chemical looping combustion contained liquid membrane carbon monoxide carbon dioxide carbonyl sulfide catalytic partial oxidation

Nomenclature

DCC DEA DEG DGA DIPA DRA ECBM ECO EDTA EG EGR EMC ENCAP EOR ESA ESP EU EVA EXH FBHE FGD GDP GE GHG GWP H2 H2 O H2 S HCN HEED HEEU Hg HHV HP HR HRSG HSE HPT HT HTC HTS HTW HV ICE IEA IEA GHG

direct contact cooler diethanolamine diethylene glycol diglycolamine diisopropylamine drag reducing agent enhanced coal bed methane economiser ethylenediaminetetraacetic acid ethylene glycol enhanced gas recovery electrochemically modulated complexation ENhanced CAPture project enhanced oil recovery electric swing adsorption ElectroStatic Precipitator European Union evaporator exhaust (gas) fluidised bed heat exchanger flue gas desulfurisation gross domestic product General Electric Company GreenHouse Gas global warming potential hydrogen water hydrogen sulfide hydrogen cyanide hydroxyethylethylenediamine hydroxyethylethyleneurea mercury higher heating value high pressure heat rate heat recovery steam generator health, safety, and environment high-pressure turbine high temperature hydrotalcite high-temperature water-gas shift high-temperature Winkler heating value (?) Internal combustion engines International Energy Agency International Energy Agency Greenhouse Gas R&D Programme

xix

xx

Nomenclature

IGCC IL IPCC IP IPT IRCC ISO ITM IUPAC LHV LIDAR LNG LP LPT LT LTS MCM MDEA MEA MHI MIX MOFs MMV MP MWGS N/A N2 N2 O NB NETL NG NGCC NH3 NIOSH NIMBY NO NOx NTNU NTP O2 OSHA OSPAR PCC PE PEI

integrated gasification combined cycle ionic liquid Intergovernmental Panel on Climate Change intermediate pressure intermediate pressure turbine integrated reforming combined cycle International Organization for Standardization ion transport membrane International Union of Pure and Applied Chemistry lower heating value light detection and ranging liquefied natural gas low pressure low-pressure turbine low temperature low-temperature water-gas shift mixed conductive membrane methyl diethanolamine monoethanolamine Mitsubishi heavy industries mixer metal–organic frameworks measurement, monitoring, and verification medium pressure membrane water-gas shift not available nitrogen nitrous oxide nota bene (Latin for pay attention, take notice) National Energy Technology Laboratory natural gas natural gas combined cycle ammonia US National Institute of Occupational Safety and Health not in my backyard nitric oxide term for mono-nitrogen oxides – NO and NO2 Norwegian University of Science and Technology normal temperature (298.15 K or 25 ∘ C) and pressure (1 atm) oxygen US Occupational Safety and Health Administration name of both, a commission and convention for the protection of the marine environment of the north east Atlantic pulverised coal combustion polyethylene polyethyleneimine

Nomenclature

PFBC pH PI PLONOR

POX PP PRE PS PSA PTFE PVDF PTFE RTI RTIL SACS SCOC SCR SE SERP SEWGS SF SFGD SMR SNCR SO2 SOFC SPECC SR ST STP

SUP TEA TEG THAM THF ThOD TIT TSA TSIL

pressurised fluidised bed combustion measure of the acidity or basicity of a solution polyimide pose little or no risk to the environment (a list of substances/preparations used and discharged offshore, which are considered to pose little or no risk to the environment; it is prepared and released by OPAR) partial oxidation polypropylene pre-reformer polysulfone pressure swing adsorption polytetrafluoroethylene polyvinylidene fluoride polytetrafluoroethylene, also known by the DuPont brand name Teflon Research Triangle Institute room temperature ionic liquids saline aquifer CO2 storage programme, monitoring the sleipner CO2 injection project semi-closed oxy-combustion selective catalytic reactor (for the removal of NO and NO2 ) sorption-enhanced sorption-enhanced reaction process sorption-enhanced water-gas shift supplementary firing seawater flue gas desulfurisation steam methane reforming selective non-catalytic reduction sulfur dioxide solid oxide fuel cell specific energy penalty steam reforming steam turbine standard conditions for gases; standard temperature (273.15 K or 0 ∘ C) and pressure (105 Pa) as defined by IUPAC (McNaught 1997) super-heater triethanolamine triethylene glycol tri(hydroxymethyl) aminomethane tetrahydrofuran theoretical oxygen demand turbine inlet temperature temperature swing adsorption task-specific ionic liquid

xxi

xxii

Nomenclature

US USA VPSA VSA WGS YSZ

United States (refers to USA) United States of America vacuum pressure swing adsorption vacuum swing adsorption water-gas shift yttria-stabilised zirconia

xxiii

Organisation and Use of Book The first chapter gives a general introduction on CO2 emissions and CO2 capture and storage (CCS). CCS also involves both CO2 transport and storage, and although not the focus of the book, Chapter 2 gives an overview related to long-term storage of CO2 . Before covering thermal power plant technologies in Chapter 5, both the fuels used in the power plants, and CO2 and its properties are covered in Chapters 3 and 4, respectively. Chapters 6 and 7 deal with fundamentals of gas separation and plant efficiencies, important topics related to CO2 capture. The CO2 capture methods are covered from Chapter 8 and onwards, both in terms of gas separation methods, Chapters 9–11, and capture processes integrated in power plants, Chapters 12–14, dealing with pre-combustion, post-combustion, and oxy-combustion capture methods. Absorption is the most commonly used method to separate CO2 from gas mixtures. This method is discussed in separately in Chapter 9, while other methods, such as membranes and adsorption, are lumped together in Chapter 10. This text was designed to bridge the gap between the many disciplines involved in CO2 capture and is fit for undergraduate students, graduate students, practicing process engineers, and others interested in an understanding and overview of CO2 capture from thermal power plants in particular and of CCS in general. The research in the field is evolving and it is not the purpose of the book to cover all the latest developments and research within CCS. If this was the goal, the book would be outdated already at the time of publishing. For the latest in research, the reader is referred to review and research journal articles.

1

1 Introduction 1.1 Greenhouse Effect The temperature in the Earth’s atmosphere and at ground level is a result of a complex energy balance between incoming solar radiation energy and outgoing radiation energy from the Earth’s surface and atmosphere. This balance varies naturally in daily and annual cycles. There are also variations with long-term cycles, such as the Milankovitch cycles, which are related to the Earth’s orbital patterns (Milankovitch 1941). The heat balance is the basis for the temperatures that we have in the atmosphere and at ground level. In general, the gases present in the atmosphere convert radiation energy into thermal energy – by absorption1 of electromagnetic radiation, and vice versa – by radiation. The mechanism for absorption of radiation in a gas is that the gas molecules absorb the radiation energy by increasing its kinetic energy through molecular translation, rotation, and vibration, as well as electron translation and spin and nuclear spin. The increase in thermal energy of a gas translates into increased temperature. The longer the radiation travels through a gas, the more energy is converted. The radiation is at various wavelengths. The solar radiation is at rather low wavelengths (0.2–3 μm), either in the visible (0.4–0.8 μm) or in the near-visible (e.g. ultraviolet 0), 𝜙 needs to be considerably less than experienced in ongoing EOR projects to actually remove CO2 from the atmosphere. However, there is more to this discussion than the simple analysis resulting in Table 2.1 and Eq. (2.6). The production of oil is demand driven. It can be argued that if CO2 was not used for EOR in a specific project with a corresponding reduction in production, the same amount of oil would be produced elsewhere. One could also argue that the same amount of oil could be produced using other production-enhancing technologies, such as waterflooding. On the other hand, in the remaining lifespan of the oil reserves, it is likely that CO2 will add to the total production of oil in the sense that EOR with CO2 has properties that cannot be matched with other production-enhancing techniques. It could also be argued that EOR with CO2 could contribute to more production of light crude oil and less production of heavy bitumen/oil sand, which have

2.2 Underground Storage

substantially higher CO2 emissions in the production process. Nevertheless, the latter could be produced anyway, just somewhat delayed by EOR with CO2 . The impact of large-scale EOR with CO2 could be that the price of crude oil would be lower than without and may be delaying energy conservation measures and the development of renewable energy. One possible impact of not carrying out EOR with CO2 could be that a transition to coal-to-liquid-fuel production, as well as fuel production from oil sands and shale oil, could arrive sooner and with a higher emission of CO2 . Refer to Example 2.2 for a comparison of crude oil production from EOR with CO2 , with crude oil from Canadian oil sand. The production of a synthetic crude oil from oil sand requires substantial energy use. Depending on the production method (mining or in situ production) and upgrading technology, the energy consumption may be around 20–30% of the energy content of the synthetic crude oil (Bergerson and Keith 2006). Most of this energy consumption is provided by natural gas, which is assumed to be pure methane in the example. Also, assume that one additional tonne of crude oil will be produced anyway, either by EOR or by production from oil sand. Example 2.2 oil sands.

Comparison between CO2 emissions from EOR with CO2 and

Crude oil from EOR with CO2

Crude oil from oil sands

Assumptions: CO2 formation by combustion: 𝜓 = 3.2 tCO2 ∕toil ;

Assumptions: CO2 formation by combustion: 𝜓 = 3.2 tCO2 ∕toil ;

Energy consumption in production: 25% of crude oil energy content; LHVoil = 43.45 MJ/kg;

Benefit 𝜙 = 0.41 toil ∕tCO2 ; Recycling 𝜔 = 1.15 tCO2 ,recycle ∕tCO2 ,import ; Assumptions of 𝜙 and 𝜔 are from the Weyburn–Midale project (Wilson 2007). EORCO2 ,emit = −EORCO2 ,net = 𝜓 − = 3.2 −

1 0.41(1+1.15)

𝜓 = 2.75 tCO2 ∕tCH4 ;

≈ 2.1

LHVCH4 = 50.0 MJ∕kg; Oil SandCO2 ,emit = 0.25 =

)

( LHVoil LHVCH4

•2.75 0.25• 43.45 50.0

•

𝜓CH4 + 𝜓oil

+ 3.2 ≈ 3.8

t CO2 t oil

1 𝜙(1+𝜔) t CO2 t oil

Example 2.2 shows that the oil sand production results in about 80% more CO2 emissions compared to a typical EOR project. This indicates that production of crude oil from oil sand results in more CO2 put into the atmosphere compared to CO2 -EOR. One could also say that CO2 emitted from CO2 -EOR oil production is less than that emitted from any oil reservoir without CO2 -EOR (2.1 tCO2 ∕toil compared to 3.2 tCO2 ∕toil in the example). However, the discussion boils down to whether additional oil from EOR comes in addition to, or in substitution for, production from oil reserves that require substantial energy input in the production process.

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If EOR projects were designed to maximise the storage of CO2 , the value of 𝜙 could probably be much smaller. However, so far, all EOR projects have been motivated by the potential increase in oil production and not by environmental concerns for CO2 emissions. It is therefore important to distinguish between EOR projects, depending on what motivates the projects: maximum oil production or maximum storage of CO2 . The goal to store maximum CO2 while not diminishing the production of oil from an oil reservoir is substantially different from the goal of oil recovery alone. CO2 is relatively mobile in reservoir media because CO2 viscosity is low compared to oil and water. In the case of EOR, where the amount of stored CO2 is maximised, a strategy for controlling the mobility of CO2 should be applied to prevent excessive recycling of the injected CO2 . Note that when maximising the CO2 storage, the value of CO2 will be less for the oil production because of smaller 𝜙. A high recycling (a high 𝜔) reduces the amount of imported CO2 to be stored. In total, the environmental benefit of EOR with CO2 can be questioned, although its quantification is very difficult as it depends on assumptions about what may happen many decades in the future. However, one can argue that EOR projects could help large-scale CCS to happen sooner than they would without it. EOR projects have a certain willingness to pay for the CO2 , which can help reduce the cost of CO2 capture. EOR projects may very well pave the way for building up an infrastructure for CCS, with a pipeline system, and development of capture technologies and operational organisations, through which very useful large-scale CCS could be achieved.

2.2.3

Enhanced Gas Recovery (EGR)

While EOR involves several different mechanisms, such as lowering the viscosity of the oil or decreasing the capillary pressure in the reservoir, EGR works by means of compression and displacement of the gas in the reservoir. The injected fluid compresses and pushes the reservoir gas towards a production wellbore. As with EOR, waterflooding is, in this context, not considered an enhanced recovery method, however gasflooding is. The injection of a displacement gas works on a similar principle as that which is currently, to some extent, used in the gas storage industry. This concept is utilising a ‘cushion gas’, where a gas, such as nitrogen or CO2 , is injected to aid the extraction of the stored gas (typically natural gas). Typical numbers for CO2 -EGR are presented in Table 2.1. By using average numbers from the table, the net storage of CO2 in EGR can be calculated: 1 1 −𝜓 = − 2.75 𝜙 (1 + 𝜔) 0.04 (1 + 1.15) [ ] t net storage of CO2 ≈ 8.9 t additional gas

EGRCO2 ,net =

From a net CO2 storage perspective, EGR is more attractive than EOR. However, the benefit, as expressed with the term 𝜙, is less. This could mean that there is less incentive to start an EGR project than an EOR project if the goal is to

2.3 Ocean Storage

produce more fossil fuel. If the goal is to store CO2 , EGR is more attractive based on the numbers shown in Table 2.1. 2.2.4

Enhanced Coal Bed Methane Recovery (ECBM)

Unminable coal seams may be used to store CO2 . This has been suggested as a method that combines the long-term storage of CO2 and the production of methane from the coal seam. When injected into a coal seam, CO2 diffuses through the pore structure of coal and is physically adsorbed; thus, retention on a permanent basis is possible. An important assumption here is that the coal is considered unminable because it may be too deep, under the seabed, of poor coal quality, or for other reasons. Coal beds often contain large amounts of methane. The CO2 replaces the methane because coal has a higher affinity to adsorb CO2 than methane, thereby enhancing the extraction of methane from a coal seam. This could represent a value-added process. A number of ECBM projects are ongoing or have recently been in operation (IPCC-CCS 2005). One was the Coal-Seq project, which included the Allison Unit CO2 -ECBM Recovery pilot and the Tiffany N2 -ECBM pilot. In the former, 0.07 Mt CO2 per year in the period 1995–2001 was injected into a deep coal formation located in the San Juan basin, USA; in the latter, nitrogen was injected into the same basin. ECBM is not, as of 2018, a mature technology and there are a number of fundamental issues not yet fully understood (Mazzotti et al. 2009). Further research is needed in this area before a conclusion can be made about the potential for large-scale long-term storage of CO2 . Worldwide storage capabilities for CO2 storage within deep coal beds are estimated to be in the range of 3–200 Gt (IPCC-CCS 2005). Note that a coal seam considered uneconomic today may be looked upon quite differently in the future if the production technology progresses and the price of coal increases sufficiently. When mining or gasifying a coal seam filled with CO2 , the CO2 will likely be released to the atmosphere.

2.3 Ocean Storage A potential CO2 storage option is the injection of captured CO2 into the deep ocean, where most of it would be isolated from the atmosphere for a very long time, probably several hundreds of years. There is no practical physical limit to the amount of anthropogenic CO2 that could be stored in the ocean; however, experiments show that adding CO2 can harm marine organisms (IPCC-CCS 2005). Observed phenomena include reduced rates of calcification, reproduction, growth, circulatory oxygen supply and mobility, as well as increased mortality over time. In some organisms, these effects are seen in response to small additions of CO2 . Immediate mortality is expected close to injection points or CO2 lakes. The chronic effects of direct CO2 injection into the ocean on organisms or ecosystems over large ocean areas and long timescales have not yet been studied and are consequently not fully understood.

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The oceans can absorb large quantities of CO2 from the atmosphere because CO2 is an acidic gas, and the minerals dissolved in seawater have created a mildly alkaline ocean. Oceans store more CO2 than terrestrial vegetation. The ocean contains about 38 000 Gt of carbon, and about 1.7 ± 0.5 Gt is taken up annually from the atmosphere (Yamasaki 2003). The exchange of atmospheric CO2 with ocean surface waters is determined by the chemical equilibrium between CO2 and carbonic acid, H2 CO3 , in the seawater, the partial pressure of CO2 in the atmosphere, and the mass transfer relation between the air and the ocean surface. Carbonic acid dissociates into bicarbonate ion HCO−3 , carbonate ion CO2− 3 , and hydronium ion H+ by Reactions (4.17)–(4.20). Even though the oceans represent a huge storage capacity, there is so much uncertainty related to large-scale CO2 storage that it is less likely to gain public acceptance. A general attitude many people have is that ocean storage of CO2 is to solve one problem by creating another one.

2.4 Mineral Carbonation Mineral carbonation involves the fixation of CO2 as solid inorganic carbonate minerals, such as calcite (CaCO3 ) and magnesite (MgCO3 ). As naturally occurring stable products, these substances provide an estimated storage capacity of 1 × 104 to 1 × 106 Gt on a geological timescale (over 10 000 years) (Lackner 2003). Silicate rocks such as serpentine (Mg3 Si2 O5 (OH)4 ), olivine (Mg2 SiO4 ), and wollastonite (CaSiO3 ) are possible starting materials. The carbonation process can be accomplished either in situ, by injecting CO2 into suitable geological formations, or ex situ in a chemical processing plant. The in situ carbonation is similar to geological storage and is exemplified in the CarbFix project on Iceland (Gislason et al. 2010). The pilot project features the capture of CO2 from a geothermal plant, the dissolving of CO2 in water, and the injection of the mixture into deep geothermal reservoirs. The raw rock materials typically contain other minerals, which hinder the further dissolution of the reacting component, and need to be removed in a separation step such as, e.g. magnetic extraction of magnetite (Fe3 O4 ). This could be accomplished in an ex situ plant. The other pre-treatment measures may include crushing, grinding, and milling. The mining process in this case does not differ from the conventional mining of other minerals such as copper ores and would be feasible from a technical point of view and from resource availability. For the purpose of CO2 capture, the dimension of such an operation would be comparable to the scale of the coal industry (Hartman 1992). In ex situ carbonation, a wet process scheme is preferred, resulting in the separation (filtration and drying) of the formed compounds such as magnesium carbonate (MgCO3 ) and calcium carbonate (CaCO3 ), as well as by-products and non-reacting materials. The enthalpy of formation of mineral carbonates is about 60–180 kJ/mol lower than that of CO2 , which implies an exothermic reaction. The heat released by the carbonation process is typically in the range of 50–100 kJ/mol CO2 (Maroto-Valer et al. 2005a). Thus, low temperatures (below 900 ∘ C for the system Ca/CaCO3 and below 300 ∘ C for the system

2.5 Industrial Use – Products

Mg/MgCO3 ) are more favourable for the carbonation reaction. The temperature in aqueous systems is typically kept in a range from 100 to 200 ∘ C, whereas gas–solid reactions are carried out between 300 and 500 ∘ C (Butt et al. 1996). Concerning the carbonation process, the build-up of an inhibiting layer (silicaor carbonate-based) on the mineral surface forms one limitation affecting the reaction and conversion rate. In general, the slow kinetics of the CO2 binding process require the application of pre-treatment measures for the mineral activation, such as thermal treatment (serpentine) or ultrafine grinding (wollastonite). Other measures are the addition of catalytic substances or a change in the pH value. Therefore, the chemical activation measures are considered to be more effective than the physical ones (Maroto-Valer et al. 2005a). The major goal of all activation methods is to increase the surface area and to enhance metal oxide dissolution, which marks the rate-limiting step. However, all these measures are either technically not viable, such as the recovery of used catalysts or additives, or suffer from overall process limitations because of the large energy input, such as reaction processes in an acid or alkaline solution. In practice, the reaction is carried out at CO2 pressure levels close to CO2 pipeline conditions (IPCC-CCS 2005). In an in situ operation, pre-treatment could involve hydrofracturing to increase the mineral–fluid surface area and an optimisation of the temperature and composition of the injected fluid (Gislason et al. 2010). Mineral carbonation offers two unique advantages compared to other storage technologies. Firstly, the quantity of metal oxides in silicate rocks that can be found in the Earth’s crust exceeds the amounts needed to fix all the CO2 that would be produced by the combustion of all available fossil fuel reserves (Lackner et al. 1995; Lackner 2003). Secondly, there is virtually no practical limitation in storage time. However, there are major challenges associated with mineral carbonation. Fixation in an ex situ plant would likely be expensive and energy intensive resulting from processes concerning the mineral mining, pre-treatment, and disposal. Also, in order to fix 1 kg of CO2 , 1.6–3.7 kg feed material (rock) is required. In the case of a coal-fired power plant, the amount of rock that needs to be mined and subsequently disposed, in a mineral carbonation setup, is six times higher than that of the fuel material (Newall et al. 2000; IPCC-CCS 2005; Zevenhoven et al. 2006).

2.5 Industrial Use – Products Another storage option for CO2 is the industrial use of CO2 , either directly or as feedstock for the production of various carbon-containing chemicals, as discussed in Section 4.5. It is highly questionable whether carbon fixation in industrial products is really a long-term storage option. Most industrial products have a limited life cycle, at the end of which they are either recycled back into a new or a different industrial product or become waste. The typical lifetime of products, in which most of the CO2 is currently used by industrial processes, provides storage times of only days to months. Real storage can only be accomplished by increasing the amount of carbon in industrial products by increasing the number of these products over time or by

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having an increasing amount of industrial waste where carbon remains fixed for a very long period.

2.6 Requirements for CO2 Purity and Transportation Requirements regarding the CO2 quality are defined by the requirements for CO2 transport, storage, environmental regulations, and costs. There are generally no big technical barriers to provide high purity of the captured CO2 . However, high-purity requirements are likely to induce additional costs and higher energy demand. The key issue is to economically reduce the concentration of compounds other than CO2 in the captured stream to acceptable levels for transport and storage and to meet given environmental and legal requirements. Depending on the method of CO2 capture, there is quite a difference in the extent to which the CO2 captured in a power plant is diluted with other gases. In particular, oxy-combustion methods (refer to Chapter 14) result in a number of substances with the captured CO2 . Work has been carried out to find proper specifications for CO2 purity. Examples of operational conditions and recommendations from cases and studies are given in Table 2.2. The first column shows gas composition for the US Canyon Reef EOR project where captured CO2 from several Shell Oil Company processing plants is transported to the Val Verde basin. The second column shows requirements for composition for the Weyburn–Midale pipeline and EOR; here, CO2 is transported about 330 km from the Great Plains Synfuels Plant in the United States to the Weyburn–Midale EOR project in Saskatchewan, Canada. The rather high fraction of H2 S should be noted. This project is not only capturing and storing CO2 but also dealing with the sulfur in the same way. There is comprehensive experience in Western Canada of sour gas (H2 S and CO2 ) injection in the ground. The Weyburn–Midale pipeline is located in a sparsely populated area, where a pipeline rupture would have less impact on humans. If such a pipeline goes through a densely populated area, it is highly questionable whether so much H2 S would be allowed. The third column shows specifications from the DYNAMIS project, which was part of the EU’s 6th Framework Programme. Finally, the fourth column shows the National Energy Technology Laboratory’s (NETL’s) specifications for CO2 pipeline transport. In the case of storage of CO2 in aquifers, the limits will be less stringent than for EOR except for the limitations that are found in the handling and transportation system before storing the CO2 . It is a general consensus that the CO2 concentration should be higher than 95 vol%. There are, as of 2018, no common standards for CO2 quality for storage. The requirement of H2 O content in the transportation-ready CO2 is normally stringent because of corrosion in the presence of free water. This necessitates going below the fraction given by phase equilibrium. Other technical reasons are the formation of carbonic acid or hydrates, which can lead to corrosion and plugging, respectively. Glycol dryers are widely employed in the natural gas industry for bulk removal of water and can also be applied for drying of CO2 . Triethylene

2.6 Requirements for CO2 Purity and Transportation

Table 2.2 CO2 quality requirements for transport and storage.

Component

Canyon Reef EOR

Weyburn EOR

DYNAMIS

NETL

CO2

>95 vol%

>96 vol%

>95 vol%

—

CO

—