Renewable Fuels: Sources, Conversion, and Utilization 9781316512883, 9781009072366, 1316512886

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Renewable Fuels Focusing on a critical aspect of the future clean energy system – renewable fuels – this book will be your complete guide on how these fuels are manufactured, the considerations associated with utilizing them, and their real-world applications. Written by experts across the field, the book presents professional perspectives, providing an in-depth understanding of this crucial topic. Clearly explained and organized into four parts, this book explores the technical aspects written in an accessible way. Part I discusses the dominant energy conversion approaches and the impact that fuel properties have on system operability. Part II outlines the chemical carrier options available for these conversion devices, including gaseous, liquid, and solid fuels. Part III describes the physics and chemistry of combustion, revealing the issues associated with utilizing these fuels. Finally, Part IV presents real-world case studies, demonstrating the successful pathways toward a net-zero carbon future. Dr. Jacqueline O’Connor is Associate Professor of Mechanical Engineering and Director of the Center for Gas Turbine Research, Education, and Outreach at the Pennsylvania State University. An American Society of Mechanical Engineers (ASME) fellow and an American Institute of Aeronautics and Astronautics (AIAA) associate fellow, she serves on executive boards and committees for the Combustion Institute, the International Gas Turbine Institute, and the AIAA. Mr. David “Bobby” Noble is Program Manager of Gas Turbine research at EPRI. He is renowned in the power industry for gas turbine monitoring and diagnostics, digital twins, and combustion. Bobby is also an ASME fellow, serving on the International Gas Turbine Institute Combustion, Fuels, and Emissions Committee. Dr. Tim Lieuwen is Regents’ Professor and Executive Director of the Strategic Energy Institute at Georgia Tech. He is the founder and chief technology officer of TurbineLogic, an energy analytics firm, and an elected member of the National Academy of Engineering. Professor Lieuwen has authored 4 books and over 400 other publications.

Renewable Fuels Sources, Conversion, and Utilization J ACQ UELINE O ’ CON N O R Pennsylvania State University

B OBBY N O BLE EPRI

T I M L IE UW EN Georgia Institute of Technology

University Printing House, Cambridge CB2 8BS, United Kingdom One Liberty Plaza, 20th Floor, New York, NY 10006, USA 477 Williamstown Road, Port Melbourne, VIC 3207, Australia 314–321, 3rd Floor, Plot 3, Splendor Forum, Jasola District Centre, New Delhi – 110025, India 103 Penang Road, #05–06/07, Visioncrest Commercial, Singapore 238467 Cambridge University Press is part of the University of Cambridge. It furthers the University’s mission by disseminating knowledge in the pursuit of education, learning, and research at the highest international levels of excellence. www.cambridge.org Information on this title: www.cambridge.org/9781316512883 DOI: 10.1017/9781009072366 © Cambridge University Press 2023 This publication is in copyright. Subject to statutory exception and to the provisions of relevant collective licensing agreements, no reproduction of any part may take place without the written permission of Cambridge University Press. First published 2023 A catalogue record for this publication is available from the British Library. Library of Congress Cataloging-in-Publication Data Names: O’Connor, Jacqueline, 1984– editor. | Noble, Bobby, 1980– editor. | Lieuwen, Tim C., editor. Title: Renewable fuels : sources, conversion, and utilization / edited by Jacqueline O’Connor, Pennsylvania State University Bobby Noble, Electric Power Research Institute, Tim Lieuwen, Georgia Institute of Technology. Description: Cambridge, United Kingdom ; New York, NY, USA : Cambridge University Press, 2023. | Includes bibliographical references and index. Identifiers: LCCN 2022025081 | ISBN 9781316512883 (hardback) | ISBN 9781009072366 (ebook) Subjects: LCSH: Renewable energy sources. | Fuel. Classification: LCC TJ808 .R4565 2023 | DDC 333.79/4–dc23/eng/20220817 LC record available at https://lccn.loc.gov/2022025081 ISBN 978-1-316-51288-3 Hardback Cambridge University Press has no responsibility for the persistence or accuracy of URLs for external or third-party internet websites referred to in this publication and does not guarantee that any content on such websites is, or will remain, accurate or appropriate.

Contents

List of Contributorspage vii Prefacexi

Part I  Users and Conversion Devices 1

Aero Gas Turbines

3

Tim Snyder, Dusty Davis, and Randy McKinney

2

Ground-Based Gas Turbines

35

Vince McDonell and Bobby Noble

3

Reciprocating Engines

75

André L. Boehman

4

Process Heaters

138

Charles E. Baukal, Jr.

5

Fuel Cells and Hydrogen Production

161

Thomas Fuller

Part II  Chemical Energy Carriers 6

Syngas and Biogas

195

Katharine Hirl, Hannah Murnen, and Tom L. Richard

7

Liquid Fuel Synthesis

216

Matthew Realff

8

Ammonia

245

Agustin Valera-Medina, Syed Mashruk, Daniel Pugh, and Phil Bowen

9

Metal Fuels Jeffrey M. Bergthorson and Keena A. Trowell

275

vi

Contents

10

Bio-based Solid Fuels

329

Andrew H. Hubble and Jillian L. Goldfarb

Part III  Fundamental Combustion Processes 11

Fundamentals of Gaseous Combustion

371

Eric L. Petersen and Olivier Mathieu

12

Liquid Fuel Atomization and Combustion

414

Ajay K. Agrawal

13

Pollutant Emissions of Alternative Fuels

451

Ponnuthurai Gokulakrishnan and Michael S. Klassen

Part IV  Case Studies 14

Certification of Drop-In Alternative Fuels for Aviation

487

Mark Rumizen

15

Fuel Composition Influences on Reciprocating Engine Performance

501

Jim Szybist, Scott Sluder, John Farrell, and Robert Wagner

16

Near-Zero- and Zero-Carbon Fuels in Industrial Gas Turbines

515

Jeffrey Goldmeer

17

Hydrogen Solutions for Net-Zero Power Generation

544

Michael J. Ducker

Index

562

Contributors

Ajay K. Agrawal University of Alabama, Tuscaloosa, AL, USA Charles E. Baukal, Jr. John Zink Combustion, Tulsa, OK, USA Jeffrey M. Bergthorson McGill University, Montreal, Quebec, Canada André L. Boehman University of Michigan, Ann Arbor, MI, USA Phil Bowen Cardiff University, Cardiff, United Kingdom Dusty Davis Pratt and Whitney, East Hartford, CT, USA Michael J. Ducker Mitsubishi Power, Gibsonia, PA, USA John Farrell National Renewable Energy Laboratory, Golden, CO, USA Thomas Fuller Georgia Institute of Technology, Atlanta, GA, USA Ponnuthurai Gokulakrishnan Combustion Science and Engineering, Inc., Columbia, MD, USA Jillian L. Goldfarb Cornell University, Ithaca, NY, USA

viii

List of Contributors

Jeffrey Goldmeer GE Gas Power, Schenectady, NY, USA Katharine Hirl Pennsylvania State University, University Park, PA, USA Andrew H. Hubble Cornell University, Ithaca, NY, USA Michael S. Klassen Combustion Science and Engineering, Inc., Columbia, MD, USA Syed Mashruk Cardiff University, Cardiff, United Kingdom Olivier Mathieu Texas A&M University, College Station, TX, USA Vince McDonell University of California – Irvine, Irvine, CA, USA Randy McKinney Pratt & Whitney (Retired), East Hartford, CT, USA Hannah Murnen Compact Membrane Systems, Newport, DE, USA Bobby Noble EPRI, Charlotte, NC, USA Eric L. Petersen Texas A&M University, College Station, TX, USA Daniel Pugh Cardiff University, Cardiff, United Kingdom Matthew Realff Georgia Institute of Technology, Atlanta, GA, USA Tom L. Richard Pennsylvania State University, University Park, PA, USA Mark Rumizen Federal Aviation Administration, Burlington, MA, USA

List of Contributors

Scott Sluder Oak Ridge National Laboratory, Knoxville, TN, USA Tim Snyder Pratt and Whitney, East Hartford, CT, USA Jim Szybist Oak Ridge National Laboratory, Knoxville, TN, USA Keena A. Trowell McGill University, Montreal, Quebec, Canada Agustin Valera-Medina Cardiff University, Cardiff, United Kingdom Robert Wagner Oak Ridge National Laboratory, Knoxville, TN, USA

ix

Preface

This book is about a key component of our society’s decarbonized future: renewable fuels. Why a decarbonized future and why renewable fuels? The purpose of this preface is to frame these questions and introduce the rest of this book. Why a decarbonized future? To avoid the worst impacts of climate change in the coming century (Masson-Delmotte et al., 2021), deep decarbonization will need to occur in the energy sector globally (IEA, 2021b). Achieving deep decarbonization across all technology sectors – heating, cooling, and lighting buildings; ground, air, and sea transportation; and industrial production of things like glass, cement, or steel – will be very challenging. Whereas certain technologies like passenger vehicles and building heating and cooling have rapid pathways to electrification, and significant portions of power generation capacity can be converted to completely renewable sources, there will be a number of critical technologies that cannot be easily electrified and will require a substitute for fossil fuels. In this book, we explore these “hard to electrify” technologies and the future fuels that will power them. Why renewable fuels? To understand this question, let’s back up a bit. The global energy system includes three major subsystems: energy sources, carriers and infrastructure for moving and storing energy, and energy consumers. Energy sources are defined as the primary sources of energy and in our modern energy system include: oil, gas, coal, biomass, sunlight, wind, hydropower, and nuclear materials. For scale, the world used 580 exajoules (EJ), or about 161,240 terawatt hour (TWh), of primary energy in 2019, including 190 EJ of oil, 140 EJ of natural gas, 160 EJ of coal, 25 EJ of nuclear energy, 38 EJ of hydropower, and 30 EJ of all other renewable energy sources. The fossil fuels sources alone led to the release of over 34 billion tons of carbon dioxide into the atmosphere (Statistical Review of World Energy, 2021). Currently, two largely independent, multitrillion dollar carrier systems dominate the energy system: electricity and hydrocarbon fuels. In the US today, roughly 40% of energy is carried via electricity and 60% via fuels (Estimated U.S. Energy Consumption in 2020, 2021). Electricity is generated using a range of energy sources but dominated by sources from natural gas, coal, and nuclear energy. The second major component of the current energy system, fuel carriers, consists of predominantly natural gas and petroleum, with a small contribution from biomass. Besides electricity production, natural gas is largely used for industrial processes, with smaller contributions toward residential and commercial needs. The majority of petroleum products are used for transportation. Given the prevalence of fuel use today, the focus of this text is fuel-based carriers.

xii

Preface

Many proposed solutions for decarbonizing the energy sector rely on the mass electrification of technologies, leveraging renewable electricity sources like wind and solar and slashing the use of fossil fuel sources like oil, natural gas, and coal. While many questions remain about the relative roles of electricity and chemical energy carriers in a decarbonized economy, two facts seem clear: (1) The use of fossil fuels as energy sources and carriers will decrease, although probably not to zero. (2) The amount of synthetically manufactured chemical energy carriers, produced using zero-carbon power, will grow. These synthetic fuels will be used to both carry and store energy. The second point above is a key motivator for this book. Fuel-based energy carriers are deeply embedded in society, have an extensive infrastructure base, and have very large energy densities. As such, even while electrification based on renewable power sources is critical, it will not be the exclusive approach to enable decarbonization. The first challenge is scale; 580 EJ of energy is a massive amount of energy to produce. For example, the largest nuclear power plant in the world is the Tokyo Electric Power Co.’s Kashiwazaki-Kariwa Nuclear Power Station plant with a net capacity of 7,965 megawatts (MW). Assuming a typical nuclear power plant capacity factor of 93.5%, almost 2,500 of such nuclear plants would be necessary to produce the 580 EJ of energy used by the planet. The challenge becomes more difficult with nonnuclear energy sources. For example, the largest solar power installation in the world is the Bhadla Solar Park in India, a solar photovoltaic power plant that covers 14,000 acres and has a capacity of 2,250 MW. Assuming a solar capacity factor of 20%, using this technology in a complete electrification scenario would require almost 41,000 of these systems. Without storage, the requirement would be four times that number of systems, covering a land area equivalent to over three times the size of the state of Texas. The second challenge to electrification is powering transportation technologies like road transport, shipping, and aviation. Both mass and volume basis of energy density are critically important for energy storage in transportation applications, where the vehicle must move not only the passengers and/or cargo but also the energy storage medium itself. In applications where drag accounts for a significant portion of the energy losses to the system, like large bodies moving rapidly through fluids (semitrucks, airplanes, and ships), the volume of the energy carrier is equally as important as the mass. As such, low-mass, low-volume applications like passenger vehicles and small or local delivery trucks will likely see significant electrification. For example, worldwide electric vehicle sales grew 70% from 2019 to 2020, despite the contraction in the vehicle market due to the COVID-19 pandemic (IEA, 2021a). Technological advances in battery technology and short-duration storage will be a key enabler of electrification of the energy landscape. Moreover, fuel-based carriers are much more cost-effective than electrification for large transportation systems and certain industrial processes. For example, a study on sustainable aviation (National Academies of Sciences Engineering and Medicine, 2016) showed the inability of battery chemistries to provide enough mass-specific

Preface

xiii

Table 0.1  Global primary energy consumption and fuel extraction/consumption level through time rounded to the nearest EJ/100 barrels

Primary energy consumption (EJ) Coal (EJ) Natural gas (EJ) Petroleum (Barrels)

2016

2017

2018

2019

2020

552

562

576

582

557

153/157 128/128 92,000/94,000

157/157 132/132 92,600/96,100

165/159 139/138 94,900/97,300

168/158 143/141 95,000/97,600

160/151 139/138 88,400/88,500

power for aviation applications, while highlighting the significant potential of sustainable aviation fuels and hybrid-electric architectures for achieving the goals of net-zero carbon aviation. Further, fuel-based carriers are also an effective means of long-duration energy storage and can be utilized for power generation, filling in for nondispatchable renewables. It is for these critical reasons, as well as the capital costs incurred with electrification, that fuels will remain an important energy carrier and long-duration energy storage medium for decades, if not centuries, to come. Today, fuel-based energy carriers are almost completely based on extracted fossil fuels, such as coal, natural gas, or crude oil. Table 0.1 shows the level of global primary energy consumption, as well as fuel extraction and consumption for several years, leading up to the COVID-19 pandemic (Statistical Review of World Energy, 2021). These fossil fuels are the backbone of modern society and quality of life for a growing segment of the world population has been improved with the increase of energy consumption. The reader is encouraged to analyze these numbers by country and region, available in the BP Statistical Review of World Energy, to see several important trends. First, coal extraction and usage are declining in North America and much of Europe, while it continues to increase in countries like China and India to support heavy industry and large modernizing populations. Opportunities for co-firing with renewable sources like biomass have been considered (Prinzing, 1996), but the most significant trend in coal is its replacement with natural gas (U.S. Energy Information Administration, 2021), particularly in North America and Europe. Natural gas p­roduces less than half the CO2 per kilowatt hour (kWh) than coal as a result of both its chemical composition and the much higher thermal efficiencies of gas turbine power plants than coal-fired boilers (Logan et al., 2020). However, the rate of natural gas installation has reduced as renewable electricity production has significantly accelerated. Extraction of natural gas has only been marginally affected, however, as natural gas is exported and used as a feedstock for refining, plastics, and petrochemical products. Finally, the demand for oil has not reduced significantly as transportation and petrochemical production have not meaningfully shifted from fossil fuel dependency. In some cases, such as coal and natural gas, these fuels serve as the source, carrier, and storage medium of energy, as they are directly burned to produce heat and power. However, the vast majority of liquid hydrocarbons are refined from their extracted

xiv

Preface

state before distribution to energy consumers. Typical refining operations produce a range of product streams, including liquid petroleum gases, light distillates (gasoline), mid-range distillates (jet fuel), heavy distillates (diesel fuel and heating oil), and heavy fuel oils. These liquid fuels offer an efficient balance of weight, volume, and energy to power even the largest transportation technologies. To summarize, net-zero carbon chemical energy carriers will likely remain as the lowest cost option for transport sectors such as aviation, cargo, for high-intensity industrial needs, and for some electric power generation through their use as long-­ duration energy storage. Moreover, as noted above, developed economies already have massive built out fuel-handling, logistical, and midstream infrastructures that can be leveraged immediately. For example, a 2021 report from the Columbia University Center on Global Energy Policy (Blanton, Lott and Smith, 2021) shows that tractable upgrades to the existing natural gas infrastructure like better leak mitigation and mandates for all pipe repairs to install hydrogen-compatible plastic pipe could lead to more rapid and economical adoption of low- and zero-carbon fuels. In this way, current infrastructure can be readily decarbonized without significant reduction in reliability or economic burden if the fuel is decarbonized. A variety of interesting questions arise around the utilization of these fuel-based energy carriers: ( 1) What are the options for these different carriers? (2) Can they be utilized in existing energy systems (e.g., power plants, aircraft engines) and, if so, at what blending fractions? (3) How should we think of optimizing, or even co-optimizing, chemical energy carriers and conversion technologies? (4) More generally, what issues do we need to think through as we transition from familiar sources (e.g., natural gas), toward energy carriers where broad public usage does not exist (hydrogen, ammonia)? The goal of this book is to explore these questions for sectors where fuel-based energy carriers are likely to remain critical in the future – power generation, long-haul cargo, high-intensity industrial applications, and aviation. The book is divided into four parts. Part I provides an overview of these high-intensity sectors where chemical energy carriers will continue to play an important role. These technologies include aircraft engines, ground-based gas turbine engines, piston engines, furnaces, and fuel cells. Part II describes the processes by which renewable fuels are synthesized, including hydrogen, renewable gaseous fuels, ammonia, liquid fuels, solid fuels, and metal fuels. Part III provides background material on the combustion processes that utilize these fuels, with particular focus on how a switch to renewable fuels is likely to affect fundamental combustion and emission formation processes. Finally, Part IV provides four case studies showing the implementation of these fuels in current technologies, including sustainable aviation fuels, renewable transportation fuels, hydrogen, and ammonia. Discussions in this book are targeted at technical, but nonexpert, readers, with the aim of providing the reader a complete picture of the synthesis and use of chemical energy carriers – fuels.

Preface

xv

References Blanton, E. M., Lott, M. C. and Smith, K. (2021) Investing in the US Natural Gas Pipeline System to Support Net-Zero Targets. www.energypolicy.columbia.edu/research/report/ investing-us-natural-gas-pipeline-system-support-net-zero-targets BP (2021). BP Statistical Review of World Energy 2021. [online] London: BP Statistical Review of World Energy. Available at: www.bp.com/statisticalreview. IEA (2021a) Global EV Outlook 2021. Available at: www.iea.org/reports/global-evoutlook-2021. IEA (2021b) World Energy Outlook 2021. Available at: www.iea.org/reports/world-energyoutlook-2021. Lawrence Livermore National Laboratories (2021) Estimated U.S. Energy Consumption in 2020. Report no. LLNL-MI-410527. Logan, B. E., Rossi, R., Baek, G., Shi, L., O’Connor, J. and Peng, W. (2020) Energy use for electricity generation requires an assessment more directly relevant to climate change, ACS Energy Letters, 5(11), 3514–3517. Masson-Delmotte, V., Zhai, P., Pirani, A., Connors, S. L., Péan, C., Berger, S., Caud, N., Chen, Y., Goldfarb, L., Gomis, M. I. and Huang, M. (2021) IPCC, 2021: Climate Change 2021: The Physical Science Basis. Contribution of Working Group I to the Sixth Assessment Report of the Intergovernmental Panel on Climate Change. Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA. National Academies of Sciences Engineering and Medicine (2016) Commercial aircraft propulsion and energy systems research: Reducing global carbon emissions. Washington, DC: National Academies Press. doi: 10.17226/23490. Prinzing, D. E. (1996) EPRI Alternative Fuels Database. U.S. Energy Information Administration (2021) Annual Energy Outlook 2021.

Part I

Users and Conversion Devices

1

Aero Gas Turbines Tim Snyder, Dusty Davis, and Randy McKinney

1.1 Introduction Gas turbine engines for aircraft applications are complex machines requiring advanced technology drawing from the disciplines of fluid mechanics, heat transfer, combustion, materials science, mechanical design, and manufacturing engineering. In the very early days of gas turbines, the combustor module was frequently the most challenging (Golley et al., 1987). Although the capability of the industry to design combustors has greatly improved, challenges still remain in the design of the combustor, and further innovations are required to reduce carbon emissions. Many companies in the aviation industry committed to a pathway to c­arbon-neutral growth and aspired to a carbon-free future in 2008 (Air Transportation Action Group, 2008). Additionally, airframers have aggressive goals to reduce carbon dioxide emissions by 50% by 2050 compared to those in 2005 (Airbus, 2021). Achieving these goals require technology advancements in all aspects of the aviation industry, including airframers, engine manufacturers, fuel providers, and all the associated supply chains. The focus of this chapter is the influence of one module of the aircraft engine – the combustor. The approach to meeting these goals must come with the combination of higher fuel-efficiency engines and the use of alternative jet fuels starting with sustainable aviation fuels (SAFs) followed by the introduction of renewable carbon-free fuels that may include hydrogen and ammonia. The transition to alternative fuels has already begun by blending 10%–50% of SAFs with jet fuel, with the additional benefit of lower carbon particulates in the exhaust. It is anticipated that gas turbine combustors will be capable of operating on 100% SAFs within the next few years, followed by demonstrators that burn carbon-free fuels. This chapter will describe how the combustor interacts with the rest of the engine and flight vehicle, by describing the relationship between attributes of the engine and the resulting requirements for the combustor. Emissions, a major engine performance characteristic that relies heavily on combustor design, will be introduced here with more detail to be found in following chapters. Another major challenge for the aircraft combustor design is the wide range of operating conditions that a combustor must meet as engine thrust varies. The combustor operability can be affected by alternative fuels. In most cases, changes to the combustor design or fuel

4

Tim Snyder, Dusty Davis, and Randy McKinney

distribution to improve combustor operability can also affect combustion dynamics, emissions, combustor durability, and the combustor exit temperature distribution, which impacts turbine section durability. Changes to the overall propulsion efficiency can be made by increasing the bypass ratio and the overall engine pressure ratio, which can further increase the combustor range of operating conditions. To meet these challenges, significant investments are expected to better understand how the combustor can meet the overall engine requirements for a variety of fuel types.

1.2

Overview of Selected Aircraft and Engine Requirements and Their Relation to Combustor Requirements Gas turbine engines have been used in many different sizes of aircraft since their introduction in the 1940s. Small aircraft such as single-engine turboprops use engines of low shaft horsepower, which are of small physical size. Business jets and smaller passenger aircraft may use turbojets or turbofans with thrust in the range of several thousand pounds, usually with two engines per aircraft. The other extreme includes four-engine aircraft with turbofan engine thrusts as high as 70,000 pounds and very large twin-engine aircraft with thrust per engine in the 100,000-pound class. These large thrust designs are also physically very large with fan diameters over 100 inches. In all of these applications, the engine system imposes a common set of requirements upon the combustor, as summarized in Table 1.1. As shown in Figure 1.1, these requirements are interdependent. Years of design and development within the industry have produced successive designs that improve upon all of the requirements concurrently. Although emissions are a key combustor constraint, each of these other requirements interacts with emissions and will be introduced briefly.

Table 1.1  Engine system-level requirements and supporting combustor characteristics Engine requirements

Combustor characteristics

Optimize fuel consumption

High combustion efficiency and low combustor pressure loss Minimize emissions and smoke Good combustion stability over entire operating range Easy to ignite and propagate flame Good combustor exit temperature distribution Meet required combustor life by managing metal temperatures and stresses

Meet emission requirements Wide range of thrust Ground and altitude starting Turbine durability Overhaul and repair cost

Aero Gas Turbines

Stability

5

Durability

Emissions

Altitude relight and starting

Exit temperature

Figure 1.1  Combustor performance requirements are interrelated.

Fan flow

Fan

Thrust

Core flow

Core

Power to operate fan + some thrust

Compressor Combustor

Pressure Temperature

Core flow

Turbine Pressure

Temperature

Figure 1.2  Summary of component characteristics.

1.3

Combustor Effects on Engine Fuel Consumption Gas turbine engines are Brayton cycle devices. An ideal version of such a cycle comprises isentropic compression, addition of heat at constant pressure, and isentropic expansion through the turbine. Figure 1.2 is a simplified schematic of the effect of such a cycle on the pressures and temperatures in the engine. In real engines, all of the processes incur some loss of performance versus the ideal, which is manifested as a stagnation pressure loss in the combustor. Combustion systems incur pressure losses because of flow diffusion and turning, jet mixing, and Rayleigh losses during heat addition (Lefebvre and Ballal, 2010). However, at most power conditions, the efficiency with which the fuel chemical energy is converted into thermal energy is very high, typically greater than 99.9%. “Low” levels of 98%–99.5% can be seen at low power levels. In general, though, the combustion system is a small parasitic effect on overall fuel consumption.

6

Tim Snyder, Dusty Davis, and Randy McKinney

1.4

Fundamentals of Emissions Formation The pollutants emitted by engines that are of most interest include carbon monoxide (CO), unburned hydrocarbons (UHC), nitric oxides (NOx), and particulate matter (PM) or smoke. At low power conditions, the inlet combustor pressure and temperature are relatively low, and reaction rates for kerosene type fuels are low. Liquid fuel must be atomized, evaporated, and combusted, with sufficient residence time at high enough temperatures to convert the fuel into CO2. If the flow field permits fuel vapor to exit the combustor without any reaction or if partially reacted to species of lower molecular weights, there will be UHC present. If a portion of the flow field subjects a reacting mixture to a premature decrease in temperature via mixing with cold air streams, these incomplete or quenched reactions lead to the production of CO, as detailed in Chapter 13. At high power conditions, high pressures and temperatures lead to fast reactions, with the result that CO and UHC are nearly zero. At these elevated temperatures, emissions of NOx and PM become more prevalent. NOx can be formed through several processes, but the dominant pathway is thermal NOx, as described by the extended Zeldovich mechanism, as also detailed in Chapter 13. The formation rate is exponentially related to the temperature in the flame peaking near stoichiometric conditions. Thermal NOx emissions can be reduced by limiting the time the flow spends at the high temperature and/or by reducing the maximum temperatures seen in the flame via stoichiometry control. Other NOx formation mechanisms, such as NOx formed in the flame zone itself, are negligible for aircraft engines. When fuel-rich regions of the combustor flow exist at high pressures and   temperatures, the formation of small particles of carbon can occur. These carbon particles result from complex chemical reactions and undergo multiple processes within the combustor like surface growth, agglomeration, and oxidation prior to leaving the combustor, as detailed in Chapter 13. The particles formed in the combustor pass through the turbine and exit the engine in the exhaust. When the concentration of the particles in the exhaust is high enough to be visible, as was often the case in early gas turbines, it is referred to as smoke or soot. Recently, the more general term of PM has been used to describe this emission. Modern engine smoke levels are invisible but still possess a large number of very small soot particles and aerosol soot precursors at the exhaust. Emerging research on the effect of PM on health and climate is focusing more attention on measuring, modeling, and understanding the processes governing PM production. These relationships between engine power conditions and emission production lead to the behavior shown in Figure 1.3. As shown in the figure, levels of UHC and CO are highest at low power and drop quickly with increasing thrust. Conversely, NOx and PM increase with engine power and are typically maximized at maximum power.

Aero Gas Turbines

7

60 HC CO NOx Smoke

EI or Smoke Number

50 40 30 20 10 0 0

20000

40000

60000

80000

100000

Thrust Figure 1.3  Emissions versus power level for the PW4084.

1.5

Effect of Range of Thrust and Starting Conditions on the Combustor Flight gas turbine engines must provide a range of thrust and thrust response in order to power the aircraft mission. Missions vary depending on the aircraft application. Commercial aircraft and military transports have similar missions. Military fighters and other specialized aircraft can have very different missions since their use is not exclusively for the transport of payload between two points. Design requirements are also very different for commercial and military applications. Military fighter engines are often designed for maximized thrust developed per unit weight so that the maneuverability of the aircraft is maximized. Military fighter engines also fly at a wide range of thrust throughout the flight envelope and must undergo frequent rapid thrust transients. Typically, commercial engines are designed for maximum fuel efficiency per unit thrust. They fly at high altitude to achieve the best fuel efficiency and often do not have to endure the aggressive and numerous thrust transients of military fighter engines. Engine combustors must be able to operate stably and efficiently over the full range of operating conditions and must reliably relight if an engine shutdown or flameout should occur in flight.

1.5.1

Engine Mission Characteristics A typical commercial engine mission consists of ground starting, taxi, take-off, climb to altitude, cruise, deceleration to flight idle and descent, approach, touchdown, thrust reverse, and taxi in. The extremes in combustor-operating conditions drive the overall design approach. The combustor must meet performance, operability, and emissions metrics over the full range of operation. In order to do so, it must operate at the following extremes:

8

Tim Snyder, Dusty Davis, and Randy McKinney

1. Minimum fuel–air ratio: This occurs during decelerations from high power to low power. Flight decelerations normally occur when descending from high-­ altitude cruise and during approach throttle movements. They can also occur in emergencies. Minimum fuel–air ratio typically depends on the thrust decay rate, as the time response of the engine turbomachinery that governs the airflow is much longer than that of the fuel flow. Risk of weak extinction (flameout) is highest during decelerations. 2. Minimum operating temperatures and pressures: These occur at flight and ground idle conditions. Low pressure and temperature challenges combustion efficiency due to slower fuel vaporization and chemical kinetics. 3. High operating temperatures and pressures: These occur at take-off, climb, thrust reverse, and cruise conditions. These conditions result in the bulk of NOx formation and the most severe liner metal temperatures. 4. Ignition conditions: Ignition normally occurs on the ground but also occasionally in flight. Ignition is required at near surrounding ambient pressure and temperature. High altitude and extremely cold conditions are typically the most challenging to achieve ignition, flame propagation, and flame stabilization. These conditions lead to low temperature (–40°F) and pressure (4 psia at 35,000 ft.) combustor inlet conditions. Thus, the combustor design must meet the performance, emissions, and durability requirements at low- and high-power operations without compromising stability and ignition. This requires favorable combustion fuel–air stoichiometry to meet requirements at all operating conditions. Two principal approaches have been used to achieve stoichiometry control in the industry. The first, fixed geometry without fuel staging, is the most common approach and is in the large majority of engines in service. These systems have all fuel injectors operating at all conditions. The second approach controls local fuel–air ratio through fuel staging. In these systems, not all fuel injectors operate at low power. This enables more active control of the local combustion fuel–air ratio.

1.5.2

Fixed-Geometry Rich-Quench-Lean (RQL) Combustors Fixed-geometry combustors have been used in the gas turbine industry since its inception. Early designs used multiple cans in a circumferential array. The cans transitioned through an annular duct to the turbine (Figure 1.4(a)). Later designs used an annular duct geometry that allowed for reduced overall length and weight (Figure 1.4(b)). Annular combustors also have a reduced liner surface area relative to can-annular combustors and therefore use less cooling. All designs use multiple fuel injectors to provide spray atomization and fuel–air mixing. Achieving good atomization and fuel–air mixing is critical for efficient combustion, low emissions, and good temperature uniformity into the turbine. Normally, the fuel is injected in the front end of the combustor, and flow recirculation is created to provide a stabilization region for the combustion process. This is typically

Aero Gas Turbines

9

(a)

(b) Figure 1.4  (a) Can-annular combustor (Pratt & Whitney JT8D-200). (b) RQL annular com-

bustor (IAE V2500). Vortex breakdown

Bluff Centerbody

Outer streamwise shear layer

Inner shear layer

Outer shear layer

(a)

(b)

(c)

Aerodynamic Centerbody

ux,0

Inner streamwise shear layer

D

(1)

(2)

(3)

(a)

(b)

Figure 1.5  Possible flow (1 and 2) and flame (3) configurations for two different vortex

breakdown bubble structures where (a) the bubble is lifted and (b, c) the bubble is merged with the centerbody wake. Left two images: courtesy of J. O’Connor. Right images are reproduced from Tim Lieuwen, Unsteady Combustor Physics, 2nd edition, January 2022, Cambridge University Press.

accomplished with air swirlers, which leads to vortex breakdown and flow recirculation (see Figure 1.5). The stabilization zone promotes recirculation of hot product gases forward to the incoming fuel spray, thereby providing a continuous ignition source and faster fuel droplet evaporation. Accelerated droplet evaporation is critical to high-efficiency combustion at low-power conditions, when low air inlet temperatures are insufficient to provide fast enough evaporation. If continuous ignition is not provided at low power, the vaporization and reaction times can exceed the combustor residence time and flameout occurs. The airflow distribution in a fixed-geometry combustor must be selected to achieve both low- and high-power performance requirements. Conditions at the combustor inlet vary significantly between low-power idle and high-power take-off conditions. At idle, inlet temperature, pressure, and global fuel–air ratio are relatively low. At take-off, the opposite is true (Figure 1.6). The operating temperatures

Tim Snyder, Dusty Davis, and Randy McKinney

Combustor inlet condition

10

Steady state fuel–air ratio

Temperature

Pressure

Idle

Thrust

Take-off

Transient decel fuel–air ratio Idle

Thrust

Take-off

Figure 1.6  Combustor operating conditions.

and pressures are largely a function of the engine thermodynamic cycle; therefore, the most significant parameter for the combustor designer to consider is the fuel–air ratio. Since air is introduced in stages along the length, the designer can tailor the airflow distribution to achieve key performance metrics. This creates a distribution in the fuel–air ratio along the length of the combustor, leading to variations in local temperature as the power level is adjusted. The difference in the fuel–air ratio between high-power take-off and low-power deceleration and idle conditions is critical since it determines the range of the local fuel–air ratio in the front end of the combustor. For most modern gas turbines, the difference is large enough that the front end is fuel rich (fuel to air ratio (f/a) of > 0.068 for jet fuel) at take-off conditions. Consequently, fixed-geometry combustors are referred to as rich burning or RQL designs. This refers to the rich front-end fuel–air ratio that is diluted (quenched) by additional airflow in the downstream section of the combustor to reach the fuel-lean conditions at the combustor exit. The RQL-type design has several advantages and challenges that are discussed in what follows. As previously described, the challenges at low power are combustion efficiency and stability. The local fuel–air ratio in the RQL combustor front end at idle is designed to generate high recirculating gas temperatures (Figure 1.7). Therefore, the local fuel–air ratio should be near the stoichiometric (f/a ~0.068 for jet fuel) fuel–air ratio to achieve high combustion efficiency. High combustion efficiency minimizes UHC and CO emissions that predominate at idle. Some increase in NOx emissions is generated by the hot front end, but emissions at idle are not significant when compared to high power. By designing for near-stoichiometric conditions at idle, stability can be ensured at deceleration conditions, where minimum fuel–air ratio occurs. If the minimum fuel–air ratio during deceleration is not more than 1/3 below idle fuel–air ratio, the local fuel–air ratio in the front end is maintained above the weak extinction limit and flameout is avoided. Limiting of minimum deceleration fuel–air ratio is accomplished by the engine control and controls the maximum thrust decay rate for the engine transient. At high-power conditions, the principal emission challenges are NOx and smoke. The RQL combustor axial temperature distribution at high power is depicted in

Aero Gas Turbines

ng Mixi n

Gas temperature

io bust Com ear at n 1 Ф=

11

CO

air

HC

s” nche “Que ction rea

CO consumed Threshold temperature

Compressor exit

Turbine inlet

Figure 1.7  Combustor at low power.

Figure 1.8. The front end is fuel rich and consequently has lower flame temperatures. The dilution or quench region is characterized by peak gas temperatures as the fuelrich mixture transitions through stoichiometric fuel–air ratio to the fuel-lean conditions at the combustor exit. In the front end, smoke is formed due to the combustion at fuel-rich conditions. Some of the smoke formed in the front end is oxidized in the high-temperature, oxygen-rich quench region. Thus, the front-end airflow level must be set with understanding of the formation and oxidation processes. The NOx emissions are formed in both the front end and quench regions at high power. NOx formation is exponentially a function of gas temperature, but also depends on the residence time at the local temperature. The highest rate of formation occurs in the quench region since it is the region where peak temperatures occur. However, time at peak temperature in the quench region is relatively short due to high mixing rates. In contrast, the formation of NOx in the front end is not negligible since it has relatively longer residence time due to the flow recirculation. The presence of cooling flow in the front end also leads to NOx formation when it interacts with the fuel-rich gas mixture. Recent advances have shown that substantial reductions in residence time and NOx can be achieved without compromising combustor stability and low-power performance. Use of fuel injectors that produce small droplets uniformly dispersed within the air flow and rapid air jet mixing has enabled the residence time reduction. These

Tim Snyder, Dusty Davis, and Randy McKinney

ion bust Com = 1 at Ф gen xy h c i as o ded R n o i t a s is d bu com ~ 2 Ф

Gas temperature

12

NOx Smoke

Rapid NOx formation Threshold temperature Compressor exit

Turbine inlet

Gas residence time in combustor Figure 1.8  Combustor at high power.

advanced RQL combustor designs (Figure 1.9) have demonstrated NOx reduction of over 50% when compared to early annular combustors. They are also shorter and have lower volumes in order to reduce residence times. Reduced-length combustors are lighter and also have reduced surface area requiring film cooling. Advanced cooling schemes have been deployed to minimize NOx emissions and temperature streaks into the turbines. Overall, the RQL combustor has demonstrated excellent service history. Since it does not require complex controls to modulate fuel between injectors, it has demonstrated very good reliability. It also has inherently favorable stoichiometry for stability since the front-end airflow is minimized for NOx control purposes. The front-end airflow is established as the minimum amount required for smoke control. If the fuel– air ratio range between high power and low power is large, the airflow required to control smoke can be larger than desirable for flame stability during decelerations. In these instances, the selected minimum transient fuel–air must be raised to protect flight safety and reliability. In turn, raising the minimum fuel–air ratio limit increases the time required to decelerate the engine, and can result in a safety risk during emergencies. If the deceleration time cannot be met with the revised minimum fuel–air ratio, then stability must be addressed by other means, such as by clustering fuel injectors that are provided with either more fuel or reduced airflow. This zone remains above the weak extinction level locally and protects against flameout at worst-case deceleration conditions.

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Figure 1.9  Advanced RQL combustor (Pratt & Whitney PW1500 TALON X).

The critical challenges for the RQL design approach are smoke and liner durability. As previously discussed, uniform mixing of fuel and airflow in the injectors can result in reduced smoke levels. When the fuel injector stoichiometry is fuel rich overall, the uniformity of the fuel–air distribution within the injector becomes critical. A poorly mixed injector with a wide distribution will have regions that range from fuel lean to very fuel rich. The latter can produce the bulk of the smoke in the combustor. This occurs since the highest smoke generation often occurs in the most fuel-rich regions where there is sufficient residence time. Since the front end is designed with gas recirculation to achieve stability, these zones can produce smoke. Thus, the mixing and recirculation patterns are critical to smoke control. The presence of fuel-rich and stoichiometric gases also present a liner durability challenge. Since modern gas turbines operate at high temperatures and pressures, peak gas temperatures can exceed 4200°F. Metallic liners have a practical temperature limit of 2.5 million vehicles) and has declined since then (U.S. Energy Information Administration, 2021b). Generally, ethanol has been associated with reductions in some emissions and increases in some emissions, with the outcome being dependent on the engine and test cycle. Ethanol impact on GTDI engine emissions: The combination of the high octane number of ethanol and its extremely high latent heat of vaporization enables high octane gasolines that could enable dramatic fuel economy improvements by allowing higher compression ratio engines, designed to make optimal use of the combination of ethanol properties. Before the advent of boosted direct-injection SI engines, ethanol was shown to enable higher compression ratio engines and thereby higher fuel conversion efficiency, as seen in Figure 3.8 (Brinkman, 1981). Methanol is a commodity chemical, a synthetic fuel produced from natural gas and an intermediate that can be converted into gasoline (“MTG” process) and into dimethyl ether (via dehydration) (National Research Council, 1990; Fleisch et al., 2012; Schobert, 2014). Methanol has long been considered a fuel for use in SI engines, as a blendstock, in high-level blends (M85) and neat (M100). Methanol is blended into gasoline in China, but is not widely used in gasoline in the US today. Strong interest in methanol from 1970s through the 1980s stemmed from its being a synthetic fuel as the oil crises of the 1970s raised concern about supplies of petroleum and transportation fuels (National Research Council, 1990). The continuing interest in methanol is because it could readily be produced via recycling of captured CO2, creating a

André L. Boehman

Ethanol CR=18.0 40

Indicated Thermal Efficiency (%)

94

Ethanol CR=12.0

Lean Limit

Ethanol CR=7.5

30

Gasoline CR=7.5

0.5

0.6

0.7

0.8

0.9

1

1.1

1.2

1.3

Phi Figure 3.8  Impacts of fuel, compression ratio, and equivalence ratio, phi (φ), on indicated

thermal efficiency in an SI engine (based on Brinkman, 1981).

“methanol economy” on which our energy system could be based (Olah et al., 2009). Like ethanol, methanol can promote higher fuel conversion efficiency in SI engines due to its high octane number and latent heat of vaporization (Brusstar et al., 2002). Furans: For more than a decade, bioderived furan fuels have been examined, because they have the potential to be produced from cellulosic feedstocks with relatively low process energy required (Román-Leshkov et al., 2007). A number of furanic species can provide octane number enhancement and other benefits for SI combustion, including 2-methyl furan, dimethyl furan, and HMF (Kremer et al., 2015). Among the furans, 2-methyl furan (2-MF) is commercially available and shows promise as a biofuel due to a strong nonlinear blending octane response (Boehman et al., 2020). Multiple studies have shown that 2-MF can provide a substantial octane boost and lengthening of the ignition delay. While 2-MF does not possess as high a latent heat of vaporization as ethanol, which is a significant benefit of ethanol for use in direct-­ injection SI engines, it possesses a higher laminar burning velocity (68 cm/s @ φ = 1) than iso-octane (47 cm/s @ φ = 1) (Kremer et al., 2015; McCormick et al., 2017).

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The difference between 2-MF and other fuels (e.g., ethanol and 95 RON gasoline) with regard to knock resistance in engines is less apparent at light load, but becomes more apparent at higher loads, above an indicated mean effective pressure (IMEP) of 0.6 MPa (Kremer et al., 2015). However, in the U.S. DOE Co-Optima program, based on selection criteria that included oxidative stability, while furanic species were included in an initial list of candidate fuels, down selection through the screening process excluded all furanic species (McCormick et al., 2017). Gaseous Fuels: The major gaseous fuels being used presently in SI engines is natural gas, although there is substantial interest in expanded use of hydrogen as an SI engine fuel. Natural gas is a fossil fuel, but renewable natural gas can be produced and substituted for fossil natural gas. Natural gas is comprised primarily of CH4 and modest amounts of other gases including ethane (C2H6), propane (C3H8), and nitrogen (N2) (Kirkpatrick, 2021). Natural gas engines and vehicles are abundant in the US, in transit and utility vehicle applications in particular (U.S. Energy Information Administration, 2021b). The high octane number of natural gas (RON of ~ 120) permits SI engine designs with substantially higher compression ratio than used in gasoline-fueled vehicles (12.0–13.0 or higher) (Thomas and Staunton, 1999). A challenge for natural gas is that spark timing must be fairly advanced to obtain adequate combustion phasing. Relative to a conventional SI engine that operates on gasoline, an SI engine designed for natural gas can provide a significant fuel conversion efficiency improvement. Relative to a diesel engine of similar displacement, an SI engine designed for natural gas operation may yield as much as a 25% reduction in fuel conversion efficiency, since the compression ratio will be substantially lower than in the diesel engine. As a consequence, the peak IMEP of natural gas SI engines is lower than a diesel engine of equivalent displacement. But if the natural gas SI engine is operated under stoichiometric conditions, it can utilize a three-way catalyst for emissions control. Fuel conversion efficiency improvements are possible if the natural gas engine is operated under lean burn conditions, particularly with direct injection rather than port fuel injection (Thomas and Staunton, 1999). Hydrogen has seen renewed interest as a fuel for IC engines in recent years due to its potential to be a “carbon free” and renewable fuel, as countries push toward a net-zero CO2 energy pathway. Since H2 must be produced from some other fuel or feedstock, a distinction is being made between “blue” hydrogen and “green” hydrogen, wherein blue hydrogen would be produced from a fossil fuel with CO2 capture and storage (CCS) while green hydrogen would be produced from nonfossil energy sources such as sunlight, renewable electricity or other resources (Del Pozo et al., 2021). Hydrogen as a fuel for SI engines presents both challenges and opportunities, and there is an abundance of past and recent work that has explored H2 as an SI fuel, both neat and as an ignition enhancer (e.g., Fulton et al., 1993; Zaccardi and Pilla, 2020). While H2 has a much higher laminar flame speed (3 m/s) than gasoline and methane and a high octane number (RON = 106), it has a higher adiabatic flame temperature than gasoline and with its wide flammability limits (5%–75%) hydrogen is susceptible to preignition and backfiring (Kirkpatrick, 2021). Direct injection of H2 can overcome some of these challenges, leading to the potential of high-efficiency DISI engines for light- to heavy-duty applications, with brake engine efficiency reaching nearly 45% (Yamane,

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2018). Either EGR or lean operation is required to achieve acceptable engine-out NOx emissions, in practice (Yamane, 2018; Walter et al., 2021). Water injection has been considered to mitigate preignition, provide cylinder cooling, and reduce NOx emissions (Kirkpatrick, 2021). With further development, the SI H2 engine can be competitive with H2 fuel cells in terms of overall fuel conversion efficiency (Yamane, 2018). Hydrogen addition to natural gas can yield improvements in combustion properties of the fuel due to the higher flame speed of H2 and its broader flammability limits, that lead to extension of the lean limit of SI combustion and reduced coefficient of variance under lean combustion conditions (Swain et al., 1993; Hoekstra et al., 1996; Fox et al., 2009). Fueling an SI engine with hydrogen or with a 30% blend of hydrogen in natural gas allows operation at sufficiently lean conditions to reach engine-out NOx emissions equivalent to tail-pipe NOx emissions from ultralow-emission vehicles (Hoekstra et al., 1996). Liquefied Gases: Liquefied petroleum gas (LPG), which is primarily composed of propane in the US, is a widely used alternative transportation fuel. Propane (autogas) for use in vehicles is specified as HD-5 and is a mixture of at least 90% propane, no more than 5% propylene, and 5% other gases, primarily butane and butylene (U.S. Department of Energy, 2021). Typical applications include light trucks, vans, school buses, shuttle buses, delivery vehicles, and police vehicles. Benefits of use of propane in SI engines stem from its high octane number (104–112), its low sooting tendency, and its potential to enable higher efficiency engines through increased compression ratio and intake boost. Typically, toxic emissions (1,3-butadiene, benzene, acetaldehyde) are greatly reduced when using propane in SI engines (Wang et al., 1993). Propane in direct-injection and port-injected SI engines has demonstrated dramatic reductions in particulate mass emissions and particle number emissions relative to gasoline, ranging from a factor of 6 decrease in particle mass for slightly rich conditions to a decrease by orders of magnitude in particle number for stoichiometric and lean operation, particularly for DI engines (Fanick et al., 1996; Oh et al., 2010; Krieck et al., 2015). A major challenge with propane fueled engines is fuel vaporization in the fuel supply and injection system. Under hot-soak conditions, where the vehicle is re-started while still hot from prior engine operation, the propane fuel can become so hot that it exceeds its critical point (Krieck et al., 2015). During the DI fuel injection process, the propane fuel may flash vaporize, which will dominate the spray atomization process (Lacey et al., 2021). Nonetheless, Splitter et al. demonstrated achieving 45% brake thermal efficiency with a direct-injection SI propane engine, using a combination of high stroke-to-bore (1.5:1), cooled EGR and high compression ratio (16.8:1), which is nearly at parity with an equivalent medium-duty diesel engine (Splitter et al., 2021). Propane (or more generally, LPG which may contain substantial amounts of butane outside of the US) and DME (dimethyl ether) are liquefied gases and as such can be blended and distributed as a mixture of liquefied gases using the same LPG distribution system. Because of its potential to provide extremely low carbon intensity, even a substantial negative carbon footprint, dimethyl ether is being considered for blending into propane at modest concentrations ( di- > mono-aromatics (Takei et al., 1995). Increasing aromatic content of the fuel increases particulate mass emissions due to the increase in the soluble organic fraction (SOF) composition, which may be from incomplete combustion at light loads (Asaumi et al., 1992). At moderate to high loads, aromatic content plays a key role in determining peak flame temperature, which in turn significantly affects NOx emissions (Rosenthal and Bendinsky, 1993). Lubricity: The lubricity of diesel fuel is directly related to the performance of fuel injection systems for diesel engines. Sometimes lubricity is referred to as the film strength of a liquid, and viscosity is referred to as the resistance to flow of a liquid. Recent developments have shown that lubricity and viscosity are correlated, but this is dependent on the test procedure used to determine lubricity. Fluids with the same viscosity display different friction or wear due to differences in the lubricity of the fluids. The lubricity of a finished diesel fuel depends on the parent crude oil and the process used to manufacture the fuel. The most common and widely used diesel fuel test apparatus is the High Frequency Reciprocating Rig (HFRR) following ASTM D6079-18. The test temperature can be either 25°C or 60°C (ASTM International, 2018). A maximum wear scar diameter of 380 μm at 25°C and 460 μm at 60°C are considered acceptable (Lacey and Howell, 1998). The severe limits of diesel fuel specifications on sulfur and aromatics have resulted in producing fuels of lower lubricating quality, referred to as lubricity. The hydrotreating process that is used to reduce sulfur and aromatic content has the potential to reduce the lubricating quality of the fuel due to the reduction of polyaromatics and polar compounds (Lacey and Westbrook, 1995). Lubricity may be improved by the use of a high concentration of a lubricity enhancing additive. Oxygen Content: Renewable fuels for diesel combustion can be oxygenates or hydrocarbons. This depends on the process chemistry and feedstock composition. Almost all the oxygenates possess a lower heating value (LHV) that is substantially lower than that of diesel fuel. Oxygen-containing components in diesel fuel have been shown to substantially reduce particulate emissions, in some cases accompanied by small but statistically significant reductions in NOx. However, the effectiveness of an oxygenate for suppressing soot is affected by the location and type of ­oxygen-containing moiety in the oxygenate (Pepiot-Desjardins et al., 2008). Some studies have shown that smokeless engine operation is possible with oxygen content of the fuel above 35%–38% by weight (Bertoli and Del Giacomo, 1997; Miyamoto et al., 1998; Miyamoto et al., 2000). As the preceding discussion indicates, the properties of diesel fuels and fuels used in the diesel combustion process can have strong effects on engine performance and emissions. Table 3.4 shows the properties of the typical properties of diesel fuels (focused on No. 2 diesel, intended for onroad vehicle use) and some of the dominant alternative fuels for CI engines that we consider in specific detail in the next section.

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101

Renewable Fuels and CI Combustion Bio-Hydrocarbons: The most straightforward approach to displacing petroleum-derived diesel fuel with a renewable fuel is for the renewable fuel to be comprised of the same types of compounds as found in diesel fuel. Renewable diesel and Fischer–Tropsch diesel fuel both approach this “drop-in” replacement capability, since they are primarily comprised of normal and branched alkanes. Pyrolysis oil-derived fuels may require more processing to serve as “drop-in” blendstocks, due to the presence of organic acids and other compounds that may not be suitable for finished diesel fuels (Huber et al., 2006; National Science Foundation, 2008). Renewable diesel and Fischer–Tropsch fuels with their high alkane content display a high cetane number, provide a short ignition delay, high EGR tolerance and low sooting tendency. Renewable diesel fuel is a relatively new fuel, but Fischer–Tropsch synthesis originated in the 1920s. So, there is a large body of combustion studies of Fischer–Tropsch (F-T) fuels. The high cetane number arises from the abundance of longer chain alkanes, but will be tempered by isomerization to form branched alkanes which may be necessary to achieve acceptable low-temperature behavior. The low sooting tendency arises from a combination of high H/C ratio, lack of aromatics, and lack of C–C double bonds (McMillian and Gautam, 1998). The reduced sooting tendency results in low particulate matter emissions and less nucleation mode particles (52°C), because addition of ethanol immediately decreases the flash point to below the ASTM specification for diesel fuel (Pidol et al., 2009). Higher alcohols (butanol and longer chains) can be blended into diesel fuel with less concern over stability while meeting diesel fuel property specifications (Esper et al., 2008). Blends with 1-butanol may need to be limited to below 20 vol.% to meet the ASTM specification for cetane number, but this will depend on the cetane number of the base diesel fuel. A high blend level of 1-butanol (40 vol.%) was observed to lead to an 80% reduction in smoke number from a test vehicle without a diesel particulate filter, but drivability decreased significantly for such a high butanol blend (Esper et al., 2008). Preuss et al. (2019) formulated blends of 2-ethylhexanol (an isomer of octanol and potentially produced from bioethanol) with renewable diesel fuel and conventional diesel fuel to maintain a constant cetane number of 52 (CN of the base diesel fuel) (Preuss et al., 2019). For such fuel blends, the liquid penetration length for the fuel spray increased, but the lift-off length where the flame stabilizes on the spray remained the same as for the base fuel. The 2-ethylhexanol suppressed soot emissions by suppressing soot formation, with greater amounts of 2-ethylhexanol leading to the lowest soot formation. Preuss et al. (2019) found that in heavy-duty diesel engine studies C8 and C10 alcohols (n-octanol, 2-ethyl-hexanol, 2-propyl-heptanol, and ­n-decanol) provided improved diesel combustion in terms of CO emissions and soot emissions, with soot mass emissions decreased by 47% on average across the speed-load map with a particle mass reduction of 62% at high load. These fuel blends included a combination of diesel fuel and renewable diesel fuel, and up to 58 vol.%

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alcohol, to achieve a cetane number of around 50–52. Operation on neat decanol was included in their test matrix, which possesses a cetane number of 48, and showed promise as a drop-in replacement for diesel fuel (Preuss et al., 2019). Even with poor auto-ignition quality, diesel engines can operate on short-chain alcohols in dual fuel combustion processes, where the alcohol is fumigated or port injected, and diesel fuel is direct injected. In early work on dual fuel combustion, smoke emissions were reduced with little change in fuel conversion efficiency (Barnes et al., 1975). Later work on dual fuel combustion has shown substantial fuel conversion efficiency improvements (peak gross indicated efficiency from 48% to 51%) with low PM and NOx emissions, using advanced combustion strategies and optimized piston bowl designs in a light-duty diesel engine (Dempsey et al., 2013). A further evolution of CI engines operating on methanol is demonstrated by Saccullo et al. in which the main DI injector operates with methanol and a second DI injector delivers diesel fuel to serve as a pilot ignition source (Saccullo et al., 2021). This “alcohol flexible” HD engine approach yields indicated thermal efficiency improvements of 3.5 percentage point increase, while reducing NOx by 20% and soot emissions by a factor of 40. Neat short-chain alcohols have been studied as CI fuels. Given the low ignition quality of these alcohols, operation of a CI engine on neat ethanol or methanol requires one of more strategies: high compression ratio, an igniter like a glow plug, or addition of chemical ignition assistance through use of a cetane improver or high ignition quality fuel. The chemical assistance route has been explored using dimethyl ether (DME), since it can readily be produced by dehydration of methanol (Panzer, 1983; Karpuk and Cowley, 1988). The DME would be fumigated into the intake air and the methanol direct injected (Brook et al., 1984) or injected via an indirect injection (a prechamber referred to as a torch ignition chamber, TIC) to initiate combustion (Murayama et al., 1992; Guo et al., 1994). With intake fumigation of DME, at light load and idle, the DME ratio may need to be >50 wt.%, but as little as 1 wt.% at high load (Green and Cockshutt, 1990). With the TIC approach, the required amount of DME is reduced from 50 wt.% to less than 5 wt.% even at light load (Guo et al., 1994). The chemical assistance route with DME showed improvements in terms of ignition delay and combustion variability, in comparison to use of a glow plug as an ignition source (Green and Cockshutt, 1990). Moreover, using DME as the ignition improver leads to dramatic (>95%) reductions in unburned methanol and aldehyde emissions. The undesirable performance with the glow plug for a neat methanol (M100) CI engine can be highly dependent on the glow plug temperature and proximity to the fuel jets emanating from the DI injector, as shown by Mueller and Musculus in an optical engine (Mueller and Musculus, 2001). Examples of high compression ratio engines to use ethanol and methanol as DICI fuels have included both engine studies and deployment of transit buses. A European study used a Scania 9L diesel engine operating at elevated compression ratio (28:1) on ethanol fuel formulations with and without water and with ignition improver (Olofsson et al., 2009; Nylund et al., 2016). The engine achieves a cycle average fuel

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conversion efficiency of 42.5% over the ESC cycle and engine-out NOx of 2.0 g/kWh. The need for ignition improver was reduced by using manifold injection of a portion of the fuel, which facilitates ignition and reduced the ignition additive requirement for stable combustion by 75%. The Scania development efforts have settled on an ethanol fuel formulation, “ED95,” which is 95% ethanol with the remaining 5% consisting of denaturing agents, lubricity additive, and ignition improver (Shamun et al., 2017). A subsequent study with a Scania 13L diesel engine with 27:1 compression ratio operated on 99.85% methanol with 200 ppm Infineum R566 lubricity additive (Shamun et al., 2017). Optimization of fuel injection strategy, EGR and other parameters yielded a maximum gross indicated efficiency of 52.8% at gross IMEP of 6 bar and 1200 rpm. Unburned hydrocarbon emissions were high, likely consisting of unburned methanol and NOx emissions were compliant with the EURO IV emissions regulations. These studies have demonstrated that alcohol fueled CI engines are feasible, can provide high fuel conversion efficiency, and can meet strict emissions regulations. Ethers: In the 1990s and early 2000s, a great deal of work on oxygenated diesel fuels was published, much of which considered ether compounds. Many studies considered glycol ethers, such as “diglyme” (e.g., Miyamoto et al., 1998), diethylene glycol dimethyl ether, which has a cetane number of ~126. For longer ethers such as diglyme, the high oxygen content (>35 wt.% O) and high cetane number provided extremely low particulate emissions and very effective diesel combustion. However, while diglyme and similar glycol ethers can exhibit very effective combustion, they may possess highly undesirable properties such as severe incompatibility with standard automotive materials such as elastomers that seal the fuel system; high water solubility which can affect stability of fuel blends and effectiveness of fuel filters and water separators; short-chain oxygenates, which can dramatically lower the flash point of the fuel blend, creating safety hazards that diesel vehicles are not equipped to manage; and some are potential “teratogens,” compounds which can attack the reproductive system of organisms at high exposure levels. As a consequence, consideration was given to safety and hygiene issues of oxygenated fuel compounds, including biodegradability and toxicity, which are crucial if fuel leaks into soil and groundwater (Murphy, 1999; Natarajan et al., 2001). One of the glycol ethers selected by the U.S. Department of Energy for more extensive consideration is tri-propylene glycol monomethyl ether, because of its favorable properties for blending into diesel fuel including good biodegradability (Natarajan et al., 2001). Wide-ranging studies were performed comparing oxygenates and their potential to reduce diesel particulate emissions, since at that time (late 1990s) diesel particulate filters were not considered to be a practical solution for the diesel particulate emissions challenge. Among those studies that screened various oxygenates, including ethers, esters, and alcohols, Liotta and Montalvo compared a variety of compounds from these classes (Liotta and Montalvo, 1993). Figure 3.11 shows that at low dosing levels of some oxygenates, indicated by the weight percent addition of oxygen atoms to the fuel blend, substantial reductions in particulate emissions reduction can be achieved. This oxygen addition trend is, however, linked also to the oxygen content

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Oxygen Weight Percentage 0

5

10

15

Percent Reduction in PM Mass

10 15 9

10

8

7 5 6

0 0

0.5

1

1.5

2

5 2.5

Percent PM Mass Reduction Per Weight Percent Oxygen

11

20

Oxygen Weight Percentage

Figure 3.11  Examination of soot suppression by various oxygenates including aromatic alcohols,

glycol ethers, methyl soyate and other species (based on Liotta and Montalvo, 1993).

of the oxygenated fuel, because for an oxygenate with a lower oxygen content, a greater amount of the oxygenated fuel needs to be blended into the base fuel to reach this oxygen addition in Figure 3.11. That in turn creates greater dilution of the aromatics and other compounds in the base diesel fuel, which in turn can add to the reduction in particulate emissions. Also shown in Figure 3.11 is a trend for a particular oxygenate mixture of the diminishing impact of oxygen addition with increasing amounts of oxygenate. The nominal “rule of thumb” is that one observes 5 wt.% PM mass reduction for each 0 wt.% addition. But oxygenates may display a high impact on PM mass reduction per amount added at low addition, and have less impact at higher levels of addition per amount added. Also shown in Figure 3.11 is the diminishing impact of addition of an oxygenate (in this case diglyme) on particulate matter emissions with increasing amount of oxygenate addition. The impact of oxygenate (% PM mass reduction per wt.% oxygen addition) falls off from 10:1 to around 5:1 as wt% oxygen addition increase from 2% to 15% addition. Eventually with sufficient oxygen addition, PM emissions will be negligible, but not until roughly 35 wt.% oxygen addition. We will consider some of these ethers, which can be drop-in fuels and others that, while not drop-in fuels, have great promise as renewable fuels for the future. The shortest chain either of significant commercial interest and importance is dimethyl ether (DME) as a long-term renewable replacement for petroleum-derived diesel fuel. Like propane, DME is a liquefied gas (see properties in Table 3.4), so under modest pressure it resides in a liquid state. Some interesting aspects of DME are that: it is an isomer of ethanol (CH3–O–CH3 vs. C2H5OH); it contains no C–C bonds, so it does not form soot even in a pure diffusion flame; and it is a synthetic fuel so it can be

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made from virtually any source of H2 and CO (and CO2). Thus, much of the interest in DME stems from the many pathways to produce the fuel and its smokeless combustion behavior which allows the traditional NOx–PM trade-off in diesel engines to be circumvented. As mentioned above in the context of methanol CI engines, DME had been considered even in the 1980s as an ignition improver for methanol (Panzer, 1983). The use of DME as a neat fuel for DICI engines became a topic of worldwide interest after a series of papers were published at the 1995 describing DME production and utilization in diesel engines (Charbonneau et al., 1995; Kapus and Ofner, 1995; Hansen et al., 1995; Sorenson and Mikkelsen, 1995; Kapus and Cartellieri, 1995). The promise of DME, as well as the challenges of DME, stirred engine and fuel injection development projects in many parts of the world, including the formation of various DME associations at the national and international level. This decade of research and development has been chronicled by the Japan DME Forum in the “DME Handbook” (Forum, 2007). Dimethyl ether (DME) has received much attention as an alternative diesel fuel due to  its high ignition quality (Park and Lee, 2013), soot-free combustion characteristic (Sorenson & Mikkelsen, 1995), and non-toxicity. Moreover, DME can be produced from various low-grade biomass and waste feedstocks, such as biogas from anaerobic digesters and can serve as a low carbon intensity fuel (Semelsberger et al., 2006). Recent well-to-wheels life cycle assessments show that bio-DME or renewable DME (“rDME”) can have a “negative” carbon intensity (versus ULSD: +95 gCO2e/MJ). Making DME from dairy gas has been certified with a carbon intensity (CI) of −278 gCO2e/MJ, while DME derived from animal manure and landfill gas has carbon intensity of −1 gCO2e/ MJ and 6 gCO2e/MJ, respectively (Lee et al., 2016). In spite of these advantages, adoption of DME in CI engines has been a long-term challenge due to its significantly different physical properties from diesel fuel, such as low viscosity and low lubricity. This challenge has resulted in efforts to develop fuel injection systems suited specifically to operation on DME (Kapus and Ofner, 1995; McCandless and Li, 1997; McCandless et al., 2000). Arcoumanis et al. point out that several aspects of the properties of DME can create challenges for fuel injection system durability and performance: (1) viscosity, (2) lubricity, and (3) compressibility (Arcoumanis et al., 2008). The low viscosity of DME leads to leakage of fuel past the barrel and plunger interface in high-pressure pumps and requires the design of novel fuel pumps and injectors to circumvent or mitigate the problems associated with such leakage (McCandless and Li, 1997). Problems with the low lubricity of DME lead to scuffing and polishing wear on reciprocating components in the fuel injection or common rail pump and in the fuel injectors. On the other hand, problems with the high compressibility and low critical pressure of DME relative to diesel fuel can include residual pressure waves in the fuel injection system (ringing) leading to needle bounce, higher compression work requirements and intensified cavitation phenomena within the injection system (Arcoumanis et al., 2008). To overcome the lubricity-related challenges, anti-wear additives must be dosed into the DME; the use of up to 2000 ppm of lubricity additives, including Lubrizol 539 (1000 ppm), Ethyl Hitec 560 (100 ppm), and Infineum R655 (500 ppm) have been reported. Improving

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Figure 3.12  Images of fuel injector needle wear from a novel wear test apparatus involving a reciprocating needle moving in a barrel in the presence of DME fuel and lubricity additives with an applied load of 1000 N. The presence of additives shows significant reduction in scuffing wear (based on Kajitani, 2006).

the viscosity of DME, by mixing with a wide variety of fuels and additives including diesel, biodiesel, and many commercial lubricity additives has been considered, but generally requires a high percentage (50% or more) of the blending agent to approach the ASTM recommended range of viscosity for diesel fuel (1.4–4 cSt) (Bhide et al., 2003). As Kajitani (2006), Sivebaek and Sorenson (2000), and many others have shown, lubricity additives can serve to mitigate scuffing wear in injectors operating with neat DME (Figure 3.12). Figure 3.13 also highlights this challenge, that rapid wear of the fuel system can lead to loss of rail pump and fuel injector performance due to loss of dimensional tolerance. However, concerns exist over the combustion behavior of the lubricity additive. A high viscosity additive may not atomize effectively in the spray and may lead to formation of nanoparticulate emissions. With the EU regulations on total particle number emissions, formation of nanoparticles from the lubricity holds the potential of putting a DME vehicle in violation of the particle number standard, despite the smokeless character of DME. The injection characteristics of DME are unique from diesel fuel and more similar to those of propane, since both propane and DME are liquefied gases (Arcoumanis et al., 2008; Park and Lee, 2013). DME in particular is known to flash vaporize upon injection into the combustion chamber of a CI engine, making mixing with the cylinder charge more difficult. Past work with low-pressure direct injection of DME

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Figure 3.13  Comparison of wear scars from a medium frequency pressurized reciprocating rig (MFPRR2) for assessing lubricity of fuels (based on Sivebaek and Sorenson, 2000).

showed poor air utilization and consequently high CO emissions, with a requisite penalty on combustion efficiency (Ochoterena & Denbratt, 2009; Sasaki et al., 2015). More recent work on DME fuel injection system development has focused on higher injection pressures, in the range of 750–1250 bar rail pressure (Cung et al., 2016). Another issue is that fuel-grade DME will contain both water (80% of air) will dilute the syngas heating value as it is inert during combustion. Using pure oxygen, though more expensive than air, allows for greater control of partial

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oxidation leading to decreased concentration of carbon dioxide in favor of energy containing carbon monoxide and methane gases, as well as avoiding high concentrations of nitrogen in syngas. The introduction of steam or steam/air/oxygen mixtures are favored for direct combustion of syngas as it promotes hydrogen and methane formation via water gas shift and steam methanation reactions, respectively (Worley and Yale, 2012; Molino et al., 2018). Gasifier configuration will impact syngas composition as well, especially in the concentration of contaminants, for example, tar and particulates in the gas. Fixed bed gasifiers feed the biomass in from the top of the reactor, and it travels downward where the char settles forming a bed at the bottom. The GA may be fed in from the bottom (updraft gasifier), top (downdraft gasifier), or side (crossdraft gasifier). Downdraft gasifiers are favored for small-scale power generation facilities due to simplicity and minimal tar/particulate in the syngas. However, that comes at a cost of poor temperature control and requires less than 20% moisture in the feed. Updraft gasifiers have higher tar and particulate concentrations in the gas stream compared to downdraft; however, they also have improved temperature control and energy efficiency. Crossdraft gasifiers are not widely used due to limited occurrence of reduction and stringent feed requirements. In principle, crossdraft gasifiers are more flexible in terms of variable feed loads and start-up times compared to other fixed bed systems (Worley and Yale, 2012; Molino et al., 2018). Fluidized bed reactors use the GA to cause the bed of feed and inert or catalytic material to behave as a fluid by forcing the GA upward through the bed at sufficient velocity. These gasifiers are configured as either a single reactor or dual bed reactor where partial oxidation occurs in a separate chamber from pyrolysis and reduction. Using a fluidized bed increases transfer of heat and chemical components between the solid and gas phases compared to fixed bed gasifiers. Fluidized bed gasifiers are also more controllable in terms of final syngas composition because a catalyst may be added to the bed along with the feed. Catalysis may be added to the bed to promote tar cracking, methanation, and/or in situ removal of trace contaminants (Woolcock and Brown, 2013; Molino et al., 2018; Ren et al., 2020). In a fluidized bed application where the catalyst is comingled with biomass, catalyst materials must be especially low cost given their short retention time in the reactor and/or extremely durable so they can be recovered from the residual char and ash and reused. Possibilities include mineral-based catalysts such as olivine, calcined rocks, zeolite, clay or lignite, or even biomass char (Woolcock and Brown, 2013). Some mineral materials, such as zeolite, char, and alumina, are used as a support for metal (e.g., nickel), alkaline, and/or acidic catalysts (Ren et al., 2020). Entrained flow reactors co-feed biomass with the GA at sufficient velocity to entrain the solid particles in the GA. This type of gasifier requires the feed to be pulverized into fine particles in order for it to properly entrain. GA and feed are introduced either at the top (top-fed) or side (side-fed) of the gasifier and come in contact with an inverted burner to promote gasification. The design allows for the gasifier to operate at high temperatures (≥1,300°C) which limits tar concentration in the product gas as well as promotes high conversion efficiency (Molino et al., 2018).

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After gasification, the syngas needs to be cleaned up before downstream use. Syngas may contain tar, sulfur compounds (H2S, COS, and CS2), nitrogen compounds (NH3 and HCN), halides (HCl), and alkali metals (potassium and sodium). These contaminants can cause corrosion, fouling, and/or catalyst poisoning of downstream processes. Syngas cleanup is separated by the temperature a specific unit operation requires. Cold gas cleanup operates below the boiling point of water, warm gas cleanup operates below the boiling point of ammonium chloride, 673 N/A 2,248

527 30 2,297

25.0

100.0

12.5

17.8

~17.6

N/A

~14.0

Production Methods Ammonia has been obtained from the destructive distillation of coal since the 1860s, period in which the chemical was initially used as a source of nitrogen for fertilizer purposes. Using sulfuric gas absorption after scrubbing coal gas with water, ammonia was obtained. Ammonium sulphate, obtained from the process, was then used as a fertilizer (Hignett, 1985). Approximately 140,000 tons/year of ammonia were produced around Europe using this method by the end of the nineteenth century. However, this method of processing would be superseded by the production of the “Mond” gas. In 1889, Ludwig Mond found that coal combustion could produce ammonia when air and steam are included in the reaction. The process took over previous industries such as “guano” and became the preferred method for ammonia production until World War II (Wood, 1903; Valera-Medina and Roldan, 2020). However, the introduction of cheap natural gas would lead to the use of hydrogen produced via steam methane reforming from the 1960s, which was coupled with the Haber–Bosch process conceived earlier in the century for ammonia production. In the first part of the twentieth century, plasmas-assisted nitrogen fixation (the Birkeland–Eyde process), a cyanamide process (the Fran–Caro process), and a thermochemical synthesis process (the Haber–Bosch process) were competing to produce ammonia industrially (Valera-Medina and Banares-Alcantara, 2021). After decades of material and thermodynamic developments, the Haber–Bosch process started to win over, exclusively leading the nitrogen fixation process since the 1940s due to its lower energy consumption and upscaling potential (Smill and Streatfeild, 2002). Nowadays, the process provides ammonia for fertilizer and refrigeration applications, with a market value that exceeds US$200 billion and production above 180 million tons annually (YARA, 2018).

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A reversible exothermal reaction (8.1) summarizes the synthesis of ammonia (Lan, Irvine and Tao, 2012; Brown et al., 2014; Cherkasov, Ibhadon and Fitzpatrick, 2015): N 2  g   3H 2  g  → ← 2 NH 3  g  ,

∆H° = −46 kJ mol . (8.1)

High temperatures (1800 K), the biomolecular reaction between molecular N2 and O atom generates NO and a N atom via reaction (13.9). This is the important rate limiting step for the overall NO formation via thermal-NO route. N 2  O NO  N. (13.9) Due to the importance of this NO formation route and sensitivity of the reaction to temperature, the rate constant has been studied extensively (Glarborg et al., 2018). Buczkó et al. (2018) reviewed the rate constant for reaction (13.9), and provided an optimized rate constant based on literature data. The N atom generated from reaction (13.9) then reacts with molecular O2 to form NO via reaction (13.10). This process (i.e., 13.9 and 13.10) is collectively known as the Zeldovich mechanism (Zeldovich, 1946). N  O 2  NO  O. (13.10) Furthermore, the N atom from reaction (13.9) also reacts with an OH radical to form NO via reaction (13.11), which, when included with (13.9) and (13.10), is generally known as the extended Zeldovich mechanism.

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Figure 13.1  Major NOx formation reaction pathways and their interconnections  (reproduced from Gokulakrishnan & Klassen, 2013).

N  OH  NO  H. (13.11) The thermal mechanism becomes an important pathway for NOx formation at high temperatures because of the high activation energy required for breaking up the nitrogen triple bond to form a N atom during the reaction. As this is a kinetically slow process relative to other combustion chemistry, this pathway is often computed independently of the fuel oxidation in computational fluid dynamics simulations as a way to reduce computational time.

13.3.2 N2O Pathway The reaction between molecular N2 and O atom, with its large activation energy, is the rate-limiting step for thermal NO at high temperatures. However, at moderate temperatures and high pressures the recombination reaction (13.12) is a preferred pathway between molecular N2 and O atom to form nitrous oxide (N2O) (Malte and Pratt, 1975). N 2 + O (+M ) = N 2 O (+M ) . (13.12) The reaction rate of (13.12) is well established (Glarborg et al., 2018). The nitrous oxide produced in reaction (13.12) will be then converted to either NO or N2 through bimolecular reactions. Reaction between N2O and an O atom is the primary pathway for N2O decomposition at fuel-lean conditions to form NO and N2 via competing product channels (13.13) and (13.14), respectively. N 2 O + O = NO + NO (13.13) N 2 O + O = N 2 + O 2 . (13.14) Similarly, reaction between N2O and a H atom will produce either NO or N2 via competing product channels (13.15) and (13.16), respectively.

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N 2 O + H = NO + NH (13.15) N 2 O + H = N 2 + OH. (13.16) Therefore, N2O decomposition to form NO is sensitive to the branching ratios of the multiple product channels in reactions (13.13)/(13.14) and (13.15)/(13.16). Chemical kinetic models in the literature show disagreement in predicting NO formation via the N2O route due to model uncertainty for the branching ratios. This is further discussed in Section 13.5.1.

13.3.3

Prompt NO Prompt-NO formation occurs due to the reactions between N2 molecules and small hydrocarbon radicals (i.e., CH, CH2, etc.). The prompt-NO pathway generally has a significant contribution to the total NOx production of hydrocarbon flames under stochiometric and fuel-rich conditions. The prompt-NO formation pathway was first proposed by Fenimore (1971), and the formation of HCN via reaction (13.17) was thought to be the primary route that leads to NO formation (Fenimore, 1971; Hayhurst and Vince, 1980). CH + N 2 = HCN + N. (13.17) However, recent theoretical (Cui et al., 1999; Klippenstein et al., 2018; Moskaleva and Lin, 2000) and experimental (Lamoureux et al., 2010; Vasudevan et al., 2007) works showed that the formation of NCN is the plausible intermediate that can conserve electron spin (Harvey, 2007) via reaction (13.18). CH + N 2 = NCN + H. (13.18) Although reaction (13.18) is the dominant route for NCN formation, it competes with the following product channel to form HNCN: CH + N 2 = HNCN. (13.19) Klippenstein et al. (2018) discussed in detail the effect of pressure on CH + N2 product channels and their impact on prompt NO formation. Reaction (13.18) is the main contributor for prompt-NO formation through further oxidation of the NCN. The branching fraction of reaction (13.18) increases with temperature and decreases with pressure (Glarborg et al., 2018). This will lead to a reduction in prompt-NO contribution to overall NOx formation at higher pressures. Another notable route for the formation of NCN involves C and molecular N2 via reaction (13.20). C + N 2 + M = NCN + M. (13.20) The NCN and HNCN intermediates further reacts with H, O, and OH species to produce NO along with cyanide- and amino-compounds which will also lead to NO formation (Glarborg et al., 2018). Reactions (13.21) to (13.23) are the important NCN consumption pathways, with relative importance depending on the conditions.

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NCN + O = CN + NO (13.21) NCN + H = HCN + N (13.22) NCN + OH = HCN + NO. (13.23) As the prompt mechanism involves reactions between molecular N2 and hydrocarbon radicals (i.e., CH, CH2, C, and C2), NO formation is dependent on their concentrations. The hydrocarbon radical concentrations are in turn influenced by the fuel structure and its oxidation process. For example, it was shown that C1 to C3 alcohols (i.e., methanol, ethanol, and propanol) tend to produce lower amounts of prompt NO compared to compared to C1–C3 alkanes (i.e., methane, ethane, and propane) due to a lower rate of CH radical formation (Bohon et al., 2018; Watson et al., 2016). Therefore, it is critical for chemical kinetic models to properly predict intermediate hydrocarbon radicals, especially CH radical, for accurate prediction of prompt-NO formation (Lamoureux et al., 2010, 2021).

13.3.4

NNH Route The formation of NO through a NNH intermediate was first proposed by Bozzelli and Dean (1995). NNH is formed via N2 fixation reaction (13.24): N 2 + H (+M )= NNH (+M ). (13.24) The main consumption pathways for NNH intermediate are the bimolecular reaction of O2, OH, O, and H to regenerate the N2 molecule. However, at lower temperatures, NNH also reacts with an O atom to form NO via reaction (13.25). NNH + O = NO + NH. (13.25) At higher temperatures, the reverse reaction of (13.25) is favored, and this diminishes the role of NNH route for NO formation. Hence, NO formation via reaction (13.25) is more viable at lower temperatures.

13.3.5

Fuel-Bound Nitrogen Fuel-bound nitrogen is an important source of NOx emissions for fuels with a chemical structure that contains nitrogen atoms. Fuel-bound nitrogen is typically found in heavier liquid fuels such as diesel oil or solid fuels such as biomass or coal. Most of this nitrogen is initially converted to HCN and/or NH3 intermediates during the gasification and pyrolysis processes, and then these molecules undergo further oxidation to form NOx (Glarborg et al., 2003). NH3 and HCN chemistry are also responsible for the destruction of NO in the thermal-deNOx (Kasuya et al., 1995; Kjaegaard et al., 1996) and reburning (Glarborg et al., 1998) processes, respectively. The formation of NCO from HCN and NH from NH3 act as the main precursors for the formation of NO from fuel-bound nitrogen. Reactions (13.26) to (13.30) show the main reaction pathways for the formation of NO from HCN.

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HCN + O = NCO + H (13.26) HCN + OH = CN + H 2 O (13.27) CN + OH = NCO + H (13.28) NCO + O = NO + CO (13.29) NCO + OH = NO + CO + H. (13.30) Dagaut et al. (2008) provide a detailed review on HCN chemistry. A discussion on NO formation from NH3 is included in Section 13.5.2. Fuel-bound nitrogen is a characteristic of many forms of biomass, including feedstocks generated from most woods and grasses. Hence, during gasification of these fuels, the fuel-bound nitrogen is released and much of the nitrogen is oxidized during the combustion process and released as NOx (Glarborg et al., 2003). Furthermore, in many biomass combustion applications, the combustion temperature is relatively low, making fuel-bound nitrogen the predominant mechanism for NOx formation (Ozgen et al., 2021). However, the starting point of the fuel as a solid can open some additional complexities to the nitrogen chemistry, as char and ash formed during fuel pyrolysis can contain nitrogen which can evolve to NO during oxidation (Karlström et al., 2017; Liu et al., 2019). Nitrogen species evolved in volatiles from biomass will follow similar pathways as found for liquid fuels containing fuel-bound nitrogen, via NH3 and HCN formation (Anca-Couce et al., 2018). The relative importance of the NOx formation via char and volatile pathways will depend on the feedstock composition as well as the structure of fuel-bound nitrogen (Zhou et al., 2000).

13.4

Formation of Soot Formation of soot particles during combustion has been and continues to be an area of intensive research. There are a number of extensive review articles that detail the soot formation process (see for example Michelsen, 2017; Michelsen et al., 2020). As such, only a short synopsis of soot formation will be discussed here, with the reader encouraged to refer to the various review articles for more in-depth details of the chemistry that is important for the formation of soot during combustion. Soot has important and typically detrimental effects on air quality on both local and global scales (Finlayson-Pitts and Pitts, 1997; Highwood and Kinnersley, 2006). Soot can react with nitrogen dioxide, sulfur dioxide, and ozone (Stanmore et al., 2008; Stanmore et al., 2001; Nienow and Roberts, 2006). Soot particles can have adverse effects on human health as the particles are toxic on a cellular level and when inhaled can affect cardiovascular and pulmonary health (Finlayson-Pitts and Pitts, 1997; Janssen et al., 2011; Lighty et al., 2000; Lippmann, 2014). Soot also plays a role in climate change due to the absorptive nature of these particles. Soot particles, containing a mixture of elemental carbon and other organic and inorganic species, can influence the climate due to their strong absorption of light in the visible and ultraviolet regions

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of the electromagnetic spectrum (Browne et al., 2015). The absorption and scattering of solar radiation by carbonaceous particles in the atmosphere can affect the radiative forcing balances important in climate change.

13.4.1

Soot Chemistry Soot is formed during the incomplete combustion of carbon-containing fuels. During the breakdown of fuel molecules due to oxidation and decomposition reactions, large hydrocarbon radicals and polycyclic aromatic hydrocarbons (PAHs) are formed (Frenklach, 2002; McEnally et al., 2006). These gas-phase molecules are considered soot precursors as they react, combine, and form a nucleus for incipient soot particles (Michelsen et al., 2020). These incipient particles are condensed-phase nanoparticles (diameters less than 10 nm) with properties that can vary depending on the conditions under which they are formed (e.g., fuel lean versus fuel rich) (Commodo et al., 2015; Commodo et al., 2015; Michelsen, 2017). Incipient particles are not solidified, as this will happen as they mature and carbonize. Incipient particles continue to grow due to coalescence and surface addition. During this process, hydrogen is lost (known as dehydrogenation), allowing the particles to solidify as they grow in size due to agglomeration. Hence, the C/H ratio increases as soot matures, which changes a variety of characteristics including structure, optical, and electrical properties (Russo et al., 2015; Alfè et al., 2009).

13.4.2

Soot Formation Mechanisms Incipient and very young soot particles have been shown to be primarily composed of aromatic hydrocarbons (D’Alessio et al., 1992; Russo et al., 2015), and the role of PAHs have been studied in depth (Richter and Howard, 2000). Frenklach and co-­workers (­Frenklach and Wang, 1991; Frenklach, 2002) proposed the HACA (H-abstractionC2H2-­addition) mechanism, where an H atom is abstracted from the PAH and replaced by an acetylene molecule. This mechanism has been researched extensively, with various other pathways explored (e.g., H-abstraction-vinyl-addition (Shukla and Koshi, 2012); H-abstraction-methyl-addition (Liu et al., 2015)). However, a common issue with the HACA pathway has been the high-energy barrier that must be overcome (Zhang et al., 2016). This has led to recent proposals of additional formation mechanisms such as the CAHM (carbon-addition hydrogen-migration) (Zhang et al., 2016) and CHRCR (­clustering of hydrocarbons by radical-chain reaction) (Johansson et al., 2018). Clustering of hydrocarbons by radical-chain reaction provides a pathway with a ready supply of radicals to keep the reactions moving forward. Chain reactions of resonance-stabilized radicals (RSR) with closed-shell hydrocarbons and other radicals permit steady growth (clustering) of stable particles (Johansson et al., 2018; Thomson and Mitra, 2018). Figure 13.2 shows a cartoon of the steps of soot growth. Clustering of hydrocarbons by radical-chain reaction presents a pathway that overcomes difficulties with rapid development of nascent soot particles involving PAH that provides a means to provide the observed creation rates and lessen dependence on reactions with high-­ energy barriers and remain consistent with thermodynamic principles.

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Figure 13.2  Soot formation pathways, including possible RSR growth mechanism  (reproduced from Thomson & Mitra, 2018).

13.4.3

Soot Consumption Mechanisms As soot formation is proceeding, competing processes in the flame are causing the fragmentation and oxidation of the particles. The oxidation process can define important characteristics such as soot size, morphology, and structure (Echavarria et al., 2011). O2 and OH radicals were shown to have heightened importance for soot oxidation in different combustion regimes. In fuel-lean combustion, soot oxidation rates were increased in regions of high oxygen concentration. In fuel-rich combustion, the presence of OH was found in regions of high soot oxidation rates (Echavarria et al., 2011). Soot oxidation is complicated by the relationship between soot structure and reactivity. Vander Wal and Tomasek (2003) found that the underlying soot structure is dependent on the synthesis conditions (temperature, time, fuel type) and that the oxidation behavior and rates will vary with this structure. Figure 13.3 shows partially

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Figure 13.3  TEM images of acetylene soot generated under different levels of oxygen (­reproduced from Vander Wal et al., 2005).

oxidized acetylene soot sampled at various levels of oxygen (Vander Wal et al., 2005). Recently Toth et al. (2019) confirmed via in situ visualization that several of the proposed oxidation modes, surface fullerene formation, internal burning, fragmentation and densification, are viable mechanisms for this process.

13.5

Emissions from Alternative Fuels Alternative fuels can be categorized into hydrocarbon and non-hydrocarbon (i.e., carbon-free) fuels. The two main goals of alternative fuels are (a) to reduce the CO2 emission impact on the environment (b) reduce energy dependency on petroleum. In this respect, alternative hydrocarbon fuels are often derived from either nonpetroleum energy sources (e.g., natural gas, coal, etc.) or bio-feedstocks (e.g., biomass, alcohol, etc.). Combustion characteristics of these fuels have been studied extensively (Blakey et al., 2011; Braun-Unkhoff et al., 2017; Gokulakrishnan et al., 2008; Gokulakrishnan et al., 2014; Wang et al., 2018) in order to establish their viability for practical applications. In this section, emission characteristics of various types of alternative fuels (i.e., H2, H2–CO, H2–CH4, and bio-derived jet fuel) will be discussed in comparison to the conventional fuels such as CH4, Jet-A, or JP-8. Hydrogen is expected to play a critical role in achieving decarbonization of the global energy system. Hydrogen fuel cells have already made inroads in land transportation, and progress is being made in other sectors including heat and electricity (Staffell et al., 2019). Technological developments for industrial combustion applications of H2 is making rapid advancement (Noble et al., 2021; Patel, 2019). With the current state of the art technology, gas turbines, for example, can meet the dry-low-NOx emission standards with approximately 60% or less H2 in fuel mixture (Noble et al., 2021). New technology developments (Noble et al., 2021; Patel, 2019) have been undertaken to

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meet the emission standards burning 100%H2. The emission characteristics (i.e., NOx) of H2 in the context of syngas or high-H2 fuels have been studied extensively in the literature (Asgari and Padak, 2018; Delimont et al., 2021; Yoshimura et al., 2005). Furthermore, in recent years, interest in technology development for ammonia combustion has also increased as it has the potential to be an energy carrier for safer storage and transportation of H2. However, high levels of NOx emissions from NH3 combustion remain a challenge which could hinder its ability to be a viable gas turbine fuel. Similar to other alternative fuels, ammonia has also been investigated (Kobayashi et al., 2019; Valera-Medina et al., 2018) as a potential fuel for a variety of combustion applications. This is further discussed in Chapter 8, where NOx formation from NH3 combustion is discussed.

13.5.1

Emissions from H2 Combustion One of the major impediments in the adoption of H2-fired combustion systems is the potential to generate high levels of nitrogen oxides (Noble et al., 2021; Therkelsen et al., 2009). The main pathways for NO formation from H2 combustion are the (a) thermal NO, (b) N2O route, and (c) NNH route. Therefore, it is important to understand the role of different pathways of NOx formation in order to mitigate the emission effectively. However, chemical kinetic models in the literature show disagreement in predicting NOx for H2/air combustion at fuel-lean conditions as shown in Figure 13.4. The source of variation in model predictions is twofold: (a) hydrogen combustion chemistry and (b) nitrogen chemistry. The chemical kinetics of H2 oxidation and combustion has been studied extensively over the years, which has reduced the overall model uncertainty (Varga et al., 2015). However, the variations in model predictions for H2 combustion with nitrogen chemistry remain relatively high (Kovács et al., 2020). As the reaction rates of the thermal-NOx mechanism are fairly well established (Abian et al., 2015; Buczkó et al., 2018), the various models yield similar NOx predictions for flames near stochiometric conditions with temperatures greater than 2000 K. These conditions are prime for thermal-NO production. However, there is a wide variation in the model predictions for fuel-lean conditions when NO formation involves significant contribution from the non-thermal mechanisms such as the N2O and NNH pathways. In particular, different kinetic models have varying branching fractions for bimolecular reactions of N2O with O (i.e., 13.13 and 13.14) and H (i.e., 13.15 and 13.16), which are critical steps for NO formation via N2O pathway. To highlight these differences in kinetic models, perfectly-stirred reactor (PSR) simulations were performed assuming a residence time of 2 ms, using various chemical kinetic mechanisms from the literature (i.e., DTU (Glarborg et al., 2018), GRI (Smith et al., 1999), Konnov (Han et al., 2021), NUIG (Zhang et al., 2017), and UCSD (University of California at San Diego, 2018)). Figure 13.4 shows NOx concentration predictions for H2/air at 300 K as a function of pressure at equivalence ratios of 0.5 and 1.0. The pressure was varied between 0.5 and 50 atm. As seen in Figure 13.4a, the models exhibit significant disagreement for NOx predictions at an equivalence ratio of 0.5, where the reactor temperature varies from 1525 to 1650 K across the range

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Figure 13.4  PSR model predictions of NOx for H2/air at 300 K with 2 ms residence time.

of reactor pressure. At these conditions, the major pathways for NOx formation are the (a) N2O route and (b) NNH route. Chemical kinetic analysis based on Glarborg et al. (2018) (i.e., DTU) model shows that the N2O route is the dominant NOx pathway (with contributions varying between 60% and 90% of the total NO) except for atmospheric and subatmospheric conditions. The model predictions for stochiometric conditions, where the reactor temperature varies from 1975 to 2265 K across the range of pressures, are shown in Figure 13.4b. As the thermal-NO route is the dominant pathway at these conditions, all the models have similar predictions, with the exception of the Konnov mechanism (Han et al., 2021). Figure 13.5 shows the nitrogen oxide emissions for H2/air combustion obtained from a Monte-Carlo simulation of a PSR-PFR reactor using the Glarborg et al. (2018) model. Input variables for pressure (1–50 atm), temperature (300–600 K), and equivalence ratio (0.3–1.7) were varied. The PSR and PFR reactor residence times were maintained at 2 and 3 ms, respectively. As shown in Figure 13.5b, a significant amount of NO is formed for conditions between equivalence ratios of 0.5 and 1.5, primarily due to the thermal-NO formation. Figure 13.5e and f shows the ratio of the NO formed via the N2O route and the NNH route to the total NO, respectively. At very lean conditions (i.e., ϕ = 0.3–0.5), the N2O route is the biggest contributor to the total NO formation as it generates 60 to 95% of all the NO formed. In summary, non-thermal-NOx pathways play a critical role for NOx formation under fuel-lean conditions. The NNH route becomes a significant contributor to the overall NO formation at low pressures and low temperatures. Based on the model analysis, the N2O route is the dominant pathway for NO formation at high pressures under lean conditions. The existing chemical kinetic models have good agreement in predicting NOx formation for conditions dominated by the thermal-NOx route. However, the model predictions show a wide variation at fuel-lean conditions where non-thermal-NOx pathways become significant. This indicates that further experimental validation of the kinetic models is necessary to improve the fidelity of the predictions at these conditions.

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Figure 13.5 NOx emission profiles from H2/air combustion using a Monte Carlo simulation

of a PSR-PFR reactor network. Input variables – temperature (300–600 K), pressure (1–50 atm) and equivalence ratio (0.3–1.7).

13.5.2

Emissions from Ammonia Combustion There is a growing interest in the production of H2 from renewable sources (i.e., green hydrogen) or carbon-neutral processes (i.e., blue hydrogen) to achieve zero-carbon future. However, the transport of hydrogen from these sources to the final power generation location is logistically difficult. One potential method for overcoming this issue is to convert H2 to ammonia (NH3) as an energy carrier (Elishav et al., 2020; Valera-Medina et al., 2018; Valera-Medina et al., 2021). This is an attractive option as existing infrastructure facilities can be used for transportation and storage. However, there are many challenges for NH3/air combustion in the existing gas turbines due to its

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Figure 13.6  Reaction path diagram following the fluxes of nitrogen for the oxidation of ­stochiometric NH3/air mixture at 10 atm. The scale of the arrows indicates relative value of the fluxes.

low calorific value (on a mass basis) which results in a lower flame temperature and lower burning velocity compared to conventional gas turbine fuels. Several recent research efforts (Kobayashi et al., 2019) have been focused on enhancing NH3/air combustion efficiency with co-firing of H2 (Pugh et al., 2019; Valera-Medina et al., 2017; Valera-Medina et al., 2019) or CH4 (Kurata et al., 2017a). On-site hydrogen generation is possible with NH3 cracking (Evans, 2013a) for flame enhancement with fully carbon-free combustion. Experimental measurements (Ichikawa et al., 2015) found that the laminar flame speeds of H2–NH3 binary mixtures with 30 to 50 mole% of H2 are close to the flame speed of conventional gas turbine hydrocarbon fuels. Another challenge of using NH3 and its binary mixtures as a gas turbine fuel is that they have the potential to produce exceedingly high NOx emissions during combustion (Valera-Medina et al., 2017; Kurata et al., 2017b), primarily due to the presence of fuelbound nitrogen. The chemistry of NH3 combustion from the perspective of NOx formation has been extensively studied (Kjaegaard et al., 1996; Lyon & Benn, 1978; Miller & Glarborg, 1999; Schmidt, 2001; Song et al., 2016) because of the interest in using NH3 for the post–combustion NOx control technique known as the selective non–catalytic reduction (SNCR). In SNCR, also known as the thermal-deNOx process, NH3 is used in the post-combustion zone to promote reactions that can convert NO into N2. In the presence of excess O2, the addition of NH3 was found to convert the NO into N2 over a narrow window of temperatures in the range of 1100 to 1400 K (Kjaegaard et al., 1996). This range of temperatures is found in the exhaust flow of a typical industrial gas turbine. Figure 13.6 shows the main reaction pathways for the formation of NO and N2 during NH3 oxidation. In the absence of hydrocarbon fuels, most of the NH3 is consumed via reactions (13.31) to (13.33) to form NH2 radical:

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NH 3 + H = NH 2 + H 2 (13.31) NH 3 + O = NH 2 + OH (13.32) NH 3 + OH = NH 2 + H 2 O. (13.33) As shown in Figure 13.6, the reaction paths that determine the formation of NO and N2 do largely depend on the subsequent oxidation of the NH2 radical to form NH and N2H2 intermediates. Under fuel-lean conditions, the primary consumption route for NH2 leads to NH formation via reaction (13.34). However, under fuel-rich conditions, reactions (13.35) and (13.36) also become important consumption pathways for NH2 to form N2H2 due to the abundance of fuel radicals. NH 2 + OH = NH + H 2 O (13.34) NH 2 + NH = N 2 H 2 + H (13.35) NH 2 + NH 2 = N 2 H 2 + H 2 . (13.36) The main consumption route for NH under fuel-lean conditions leads to the formation of the HNO radical, which becomes the precursor for NO production via unimolecular thermal decomposition as well as bimolecular reactions with O, H, OH, and O2 species. On the other hand, the N2H2 intermediate is mainly converted to NNH, which leads to N2 formation via reverse reaction (13.24) under fuel-rich conditions. It also is noteworthy that the reaction of NH2 with NO via the termination reaction (13.37) and chain-branching reaction (13.38) also leads to N2 formation during NH3 combustion. This is also the critical pathway in the thermal-deNOx process for the destruction of NO in the post-combustion zone using NH3. NH 2 + NO = N 2 + H 2 O (13.37) NH 2 + NO = NNH + OH. (13.38) For the thermal-deNOx process to be effective, it is important to maintain a balance between the reactions (13.37) and (13.38) to sustain the NO reduction by NH3, while minimizing the NO formation via reaction (13.25) under oxidizing conditions. Due to this constraint, the thermal-deNOx process is effective between 1100 and 1400 K at atmospheric conditions (Kasuya et al., 1995), and this window shifts toward higher temperatures with increasing pressure (Kjaegaard et al., 1996). A Monte Carlo simulation using a PSR-PFR reactor network was conducted to demonstrate the challenges in designing a gas turbine combustor that can meet the current NOx emission standards burning NH3/air. The simplified PSR-PFR reactor network can be considered an suitable approximation to study the combustion zone of practical devices (Gokulakrishnan et al., 2012). Figure 13.7 shows the emission profiles of NH3/air combustion obtained from a Monte Carlo simulation of the PSRPFR reactor network by varying pressure, temperature, and equivalence ratio with PSR and PFR reactor residence times of 2 and 3 ms, respectively. Pressure was varied between 1 and 50 atm, and temperature was varied between 300 and 600 K. The equivalence ratio was varied between 0.5 and 1.5. The conditions were chosen to

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Figure 13.7  Emission profile of NH3/air combustion from Monte Carlo simulation of a

­ SR-PFR reactor network. Input variables – temperature (300–600 K), pressure (1–50 atm), P and equivalence ratio (0.5–1.5).

cover the operating conditions of typical gas turbine combustors. The simulations were performed using the chemical kinetic mechanism of Glarborg et al. (2018). Figure 13.7a–f shows the PFR exit temperature and emissions for NO, N2O, NO2, H2, and NH3, respectively. It can be seen in Figure 13.7b that the amount of NO produced under fuel-lean conditions is as high as 1.3 mole% (13,000 ppm) with a wide variation compared to fuel-rich conditions (i.e., ϕ > 1.0). However, NO is reduced drastically under fuel-rich conditions though it is still too high to meet typical NOx emission standards. The contrast between fuel-lean and fuel-rich conditions for NOx formation is mainly due to the formation of HNO and NNH intermediates, respectively, as discussed previously.

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As expected, H2 formed via partial oxidation of NH3 increases drastically under fuel-rich conditions (i.e., at equivalence ratios greater than 1.1). It can also be seen that the impact of pressure and temperature on H2 formation increases with equivalence ratio under very fuel-rich conditions (ϕ > 1.2) as shown in Figure 13.7e. In summary, the simulation results indicate that NH3 combustion strategy may require some form of staged combustion (Goh et al., 2021) where a fuel-rich region is used to suppress the NOx formation, and a fuel-lean region is used to convert the remaining H2 and NH3 into H2O and N2. It is also possible to reduce NO through the in-situ thermal-deNOx process with the unburnt NH3 if the reactor conditions are proper to induce this reaction pathway. Post-combustion catalytic reduction may also be necessary to reduce NOx to meet current environmental standards.

13.5.3

Emissions from Alternative Jet Fuels There have been numerous experimental works reported in the literature ­(see ­Table 13.1) to study the emission characteristics of alternative jet fuels in relation to conventional fuels such as Jet-A, Jet-A1, and JP-8. Blakey et al. (2011) and Braun-Unkhoff et al. (2017) discussed the impact of alternative jet fuels on emissions from gas turbines. Lobo et al. (2011) reported a slight 5% reduction in NOx emissions with paraffinic synthetic jet fuels fuel (FT-SPK) compared to Jet-A1. Experimental work of Bhagwan et al. (2014) found that NOx emissions characteristics of paraffinic synthetic jet fuels (i.e., FSJF and FT-SPK) are very close to that of standard Jet-A1 for high-pressure conditions relevant to gas turbines. The variations in NOx observed (Bhagwan et al., 2014) at lower pressures were attributed to the different degrees of fuel–air mixing. For hydrocarbons, flame temperature is also influenced by the H/C ratio of the fuel composition. For example, due to the lack of aromatic components, paraffinic alternative fuels tend to have a higher H/C ratio than conventional fuels such as Jet-A and JP-8. However, in practical combustors, it is not anticipated that there will be major differences in NOx or CO emissions between conventional and alternative hydrocarbon fuels. This is due to the tight control of combustor exit temperature employed in these devices. Engine tests (Bulzan et al., 2010; Corporan et al., 2007) with paraffinic alternate jet fuels showed that the NOx emissions have very similar profiles as in conventional fuels such as Jet-A and JP-8. For example, Figure 13.8 shows the NOx and CO measurements obtained from a CFM56-2C1 engine test on NASA’s DC-8 aircraft using JP-8, and Fischer–Tropsch synthetic jet fuels (i.e., FT1 and FT2) (Bulzan et al., 2010). Figure 13.8 also shows emission data for the 50 vol%/50 vol% blend of FT fuels with JP-8. The emission index (i.e., grams of NOx per kilogram of fuel) is provided as a function of fuel flow rate (pounds per hour), which is proportional to the engine speed. For example, 1000 and 8000 lbs/h flow rates are equivalent to an engine operating at around 20% and 90% of the load, respectively (Bulzan et al., 2010). As shown in Figure 13.8, the emission indices for NOx and CO do not have significant variation between the alternate and conventional fuels and their blends.

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Table 13.1  Experimental work on emissions from alternative jet fuels Reference

Fuels

Measurements

1. Corporan et al. (2007) 2. DeWitt et al. (2008) 3. Moses and Roets (2008) 4. Bulzan et al. (2010) 5. Saffaripour et al. (2011)

FT fuel, JP-8 and FT fuel +JP-8 FT fuel + aromatic solvents Jet A-1 and FSJF FT fuel, JP-8 and FT fuel + JP-8 Jet A-1, FT-SPK, FSJF, FTSPK+Hexanol and FT-­ SPK+Naphthenic cut Jet-A, Jet-A1, FAME, FT SPK Jet-A-1, FT fuels Jet-A1, FSJF, FT-SPK, FTSPK+Hexanol, and FTSPK+Naphthenic cut Jet-A, JP-5, JP-8, ATJ, FT-SPK, HEFA-Camelina

CO, CO2, NOx, SO2, and PM CO, UHC, and PM CO and smoke number CO, NOx, SO2, UHC, and PM Soot

6. Lobo et al. (2011) 7. Lobo et al. (2012) 8. Bhagwan et al. (2014)

9. Xue et al. (2017)

PM CO, NOx, and PM CO, CO2, NOx, and UHC Soot

120

20

(b) CO Emission

(a) NOx Emission

JP8 FT1 (shell) FT2 (sasol) FT1 Blend FT2 Blend

15 ElCO (g/kg-fuel)

ElNOx (g/kg-fuel)

100

10

5

JP8 FT1 (shell) FT2 (sasol) FT1 Blend FT2 Blend

0

80 60 40 20 0

0

2000

4000 6000 Fuel Flow, pph

8000

10000

0

2000

4000

6000

8000

10000

Fuel Flow, pph

Figure 13.8  Emission index for NOx (EINOx) and CO (EICO) as a function of fuel flow (in lbs/h)  (reproduced from Bulzan et al., 2010).

13.5.4 NOx Emission Comparison of Alternative Fuels The main sources of NOx in practical devices are the thermal NO, prompt NO, N2O route and NNH route for fuels that do not have fuel-bound nitrogen. Specific contributions of different routes to overall NOx formation are influenced by operating conditions such as fuel type, temperature, fuel–air ratio, and pressure. The NOx emissions in practical combustion devices that operate under diffusion or non-premixed mode are dominated by the thermal-NO route as they typically operate at high flame temperatures (>2000 K). Prompt NOx and the N2O route have significant contributions to the total NOx for systems that operate under fuel-lean conditions with hydrocarbon fuels. For non-hydrocarbon fuels such as H2 and syngas, the N2O route is the dominant pathway at high-pressure lean conditions. To further investigate the NOx formation characteristics of alternate fuels in relation to conventional fuels, PSR simulations were performed to investigate the NOx

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alkybenzene 13% cycloaromatics 3% dicycloparaffins 7% others 3% Jet A (A2)

n-paraffins 20%

iso-paraffins 29%

monocycloparaffins 25%

Average Formula: C11.4H21.7, H/C = 1.91, LHV = 43.1 MJ/kg others 0.4% Gevo (C1)

iso-paraffins (99.6%)

i-C12H26

i-C16H34

Average Formula: C12.5H27.1, H/C = 2.16, LHV = 43.9 MJ/kg Figure 13.9  Fuel characteristics of Jet-A and Gevo ATJ fuels  (reproduced from Wang et al., 2018).

formation of various gaseous alternative fuels, namely, H2, 50%CH4–50%H2 and syngas (50%CO–50%H2). The emission characteristics of these fuels are benchmarked against CH4, which is a representative fuel for natural gas. The computations were performed using the Glarborg et al. (2018) model. Simulations were also conducted for a bio-derived Gevo Alcohol-to-Jet (ATJ) alternative fuel (Wang et al., 2018). The emission characteristics are compared with the conventional jet fuel, namely, Jet-A. Figure 13.9 shows the chemical class composition of Jet-A and ATJ fuels (Wang et al., 2018). Jet-A consists of 20 vol% normal-paraffins, 29 vol% iso-paraffins, 32 vol% cycloparaffins, and 16 vol% aromatics whereas ATJ primarily consists of iso-paraffins. The PSR simulations were performed using the HyChem Models (Wang et al., 2018), developed for Jet-A (POSF10325) and Gevo ATJ (POSF11498), which are coupled with the nitrogen chemistry of Glarborg et al. (2018) to make the NOx predictions. Figures 13.10 and 13.11 show the results obtained from adiabatic PSR simulations on the effects on NOx formation of varying equivalence ratio and pressure, respectively, for the alternative fuels, H2, 50%CH4-50%H2, and 50%CO-50%H2 (syngas) and ATJ. The figures also show NOx emissions for CH4 and Jet-A. Figure 13.10 shows the results for fuel–air mixtures performed at 10 atm and an initial temperature of 300 K by varying the equivalence ratio between 0.5 and 1.5 with a constant residence time of 2 ms. 50%CH4–50%H2 produced the lowest amount of NOx of the alternative fuels investigated. As expected, the NOx emission profile of 50%CH4–50%H2 is higher than CH4 due to the difference in flame temperature. Syngas (i.e., 50%CO–50%H2) generated the most NOx. It produced consistently higher NOx than 100%H2 mixture for pressures above 5  atm. Alternative jet fuel ATJ, produced slightly higher NOx than Jet-A, but it follows a very similar trend as Jet-A for the effect of pressure. It is also noteworthy that at pressures above 5 atm, NOx emissions decreased with pressure for ATJ and Jet-A. On the other hand, 50%CH4–50%H2 has a slight increase in NOx emissions with pressure whereas syngas and H2 exhibit a very strong dependence on pressure at stochiometric conditions as shown in Figure 13.11a.

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Figure 13.10  Effect of equivalence ratio on NOx formation for fuel–air mixtures at 10 atm for various fuel types. Note that the NOx levels in (a) for H2 and 50%CO–50%H2 are scaled by factor of 2.

Figure 13.11  Effect of pressure on NOx formation for stochiometric fuel–air mixtures for various fuel types. Note that the NOx levels in (a) for H2 and 50%CO–50%H2 are scaled by factor of 2.

Perfectly-stirred reactor simulations, shown in Figures 13.12 and 13.13, were performed to understand how different NOx pathways contributed to the total NOx formation of different fuels as a function of reactor residence time (0.1 to 3 ms) at 10 atm. In order to isolate temperature effects, a similar flame temperature profile was maintained for all the fuels by adjusting the equivalence ratio of the reacting mixture. The simulations shown in Figure 13.12 were conducted for fuel–air mixtures at fuellean conditions, maintaining the flame temperature at a value corresponding to CH4/ air combustion at an equivalence ratio of 0.7. Hence, the equivalence ratios for Jet-A, ATJ, H2, 50%CH4–50%H2 and syngas were adjusted to keep their flame temperature in agreement with that of CH4 (Figure 13.12a). Figure 13.12 shows (a) the flame

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Figure 13.12  PSR results for NOx formation pathway contribution at fuel-lean conditions at 10 atm. Flame temperature (consistent with a CH4 flame at ϕ = 0.7) is held constant for all fuels.

temperature, (b) total NOx, (c) thermal NOx, (d) prompt NOx, (e) N2O route, and (f) NNH route for different fuels. At lean conditions, syngas produced the most NOx for the same power rating. Alcohol-to-Jet fuel generated slightly lower NOx compared to Jet-A. It is also noteworthy that 100%H2 and ATJ have similar NOx profiles at these conditions. Inspection of the NOx formation by individual pathway are in Figure 13.12c–f and show that the N2O route is the main NOx formation pathway (above 60%) for the gaseous fuels whereas the N2O route and prompt NOx are the main contributors for the jet fuels. The contribution of thermal NOx is less than 30%, but it increases with longer

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Figure 13.13  PSR results for NOx formation pathway contribution at near-stoichiometric conditions at 10 atm. Flame temperature (consistent with a CH4 flame at ϕ = 1.0) is held constant for all fuels.

residence time in the reactor. The NNH route contributed less than 20% of the NOx, and it becomes less than 5% at residence times greater than 0.5 ms. Figure 13.13 shows similar PSR simulation results as in Figure 13.12, but with flame temperature benchmarked for a stochiometric CH4/air flame. For residence times greater than 0.5 ms, the ranking of gaseous fuels in terms of NOx formation is syngas > H2 > 50%CH4–50%H2 > CH4. Figure 13.13b shows the total NOx formed for a given fuel. Based on the results in Figure 13.13c–f, the thermal-NO mechanism is the dominant NOx pathway for H2 and syngas. For hydrocarbon fuels, the prompt-NO pathway has significant contribution to NOx formation at shorter residence times. As the residence

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time increases, the thermal-NOx contribution becomes significant for hydrocarbon fuels. Overall, the N2O route makes up less than 15% of the total NOx formation for residence times less than 1 ms whereas contribution of the NNH pathway is negligible. In summary, gaseous alternative fuels such as H2 and 50%CH4–50%H2 produced less than 10 ppmv NOx at fuel-lean conditions benchmarked for a flame temperature of CH4/air at an equivalence ratio of 0.7. The N2O route is the primary source of NOx formation, and thermal mechanism is second at fuel-lean conditions for these fuels. At fuel-rich conditions, syngas and H2 produce significantly higher NOx than 50%CH4– 50%H2. Overall, CH4 produced the lowest NOx while syngas (i.e., 50%CO–50%H2) produced the highest amount of NOx. With the constraints of a constant temperature, ATJ produced slightly lower NOx than Jet-A at lean conditions whereas it generated slightly higher NOx at rich conditions.

13.5.5

Soot Emissions The sooting tendency of hydrocarbon fuels is often influenced by the chemical composition, and fuels with aromatic content have significantly higher soot formation rates than other fuels (Das et al., 2018). The order of the soot sooting tendency of common chemical groups present in hydrocarbon fuels is aromatics > cyclo-alkanes > iso-alkanes > normal alkanes (Dryer, 2015). Sooting tendency of fuels has been shown to be directly linked to smoke point, which is the wick flame height at which incipient sooting appears at the flame tip (Dryer, 2015), with higher smoke points correlating with lower sooting tendency. As smoke point measurements are difficult to make, especially ones that are independent of operator and apparatus, various sooting indexes have been developed. Threshold Sooting Index (TSI) was created to provide a normalized scale with means to account for fuel molecular weight and sooting point while correcting for the tendencies of a given apparatus (Calcote and Manos, 1983). Yang et al. (2007) showed that TSI correlated very well with radiation output from a variety of jet fuels. Efforts have been made to create additional indices that better account for fuels with both high- and low-sooting tendencies, including aromatics (McEnally and Pfefferle, 2007; Mensch et al., 2010) and for fuels with oxygen content (Barrientos et al., 2013). Recently, Das et al. developed a unified database of sooting tendency measurements which included a wide range of chemical structures, including oxygenates, alkanes, and aromatics among others (Das et al., 2018). As found in multiple studies (Barrientos et al., 2013; Das et al., 2018), fuels containing oxygen functional groups tend to have lower sooting contributions than those fuels containing only carbon and hydrogen. Furthermore, different classes of aromatics influence sooting tendencies with mono-aromatics < cyclo-aromatics < bi-aromatics (Ladommatos et al., 1996; Richter et al., 2021). Hence, fuel composition will play an important role in sooting behavior of the fuel. Many alternative fuels, especially those synthesized from nonpetroleum or gaseous sources (i.e., syngas, natural gas, etc.), tend to have low aromatic content, especially compared to petroleum-derived fuels (Braun-Unkhoff et al., 2017; Richter et al., 2021; Saffaripour et al., 2011). Figure 13.9, for example, shows the chemical composition

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1.90 SPK surrogate + Toluene + n-Propylbenzene + Indane + 1- Methylnaphthalene + Biphenyl + Aromatic mixture

Jet A-1 ReadiJet AtJ-SKA AtJ-SPK Farnesane

1.85

ST (soot threshold)

1.80

1.75

1.70

1.65

1.60

0

5 10 15 20 25 concentration of aromatics (vol-%)

12.0

12.5 13.0 13.2 14.0 14.5 amount of H-atoms (mas-%)

15.0

15.5

Figure 13.14  Soot thresholds in fuels with varying amounts of aromatics  (reproduced from

Richter et al., 2021).

of petroleum-based Jet A and bio-derived alcohol-to-jet synthetic jet fuel, which have 16% and 0%, aromatic content, respectively. Aromatic-free fully synthetic jet fuel (FSJF) and Fischer–Tropsch synthetic paraffinic kerosene (FT-SPK) are two common synthetic jet fuels produced using the Fischer–Tropsch process. Feedstock derived from coal is used to produce FSJF whereas FT-SPK is generated with the feedstock derived from either natural gas or biomass. Based on the sooting tendencies of various functional groups, it would be anticipated that highly paraffinic fuels like FT-SPK will have lower particle and soot formation in most gas turbine applications. Note, however, that some aromatic content for fuels can be desirable from a material properties standpoint, as the aromatics can preserve and extend the life of certain elastomers in aircraft and power generation equipment (Richter et al., 2021). Figure 13.14 shows the onset sooting equivalence ratio (soot thresholds) for a petroleum-based fuel (Jet A-1) and a number of synthetic jet fuels with varying amounts of aromatic content (reproduced from Richter et al., 2021). SPK and AtJSKA contain no aromatics, while the other fuels contain varying amounts of aromatic content. Furthermore, the SPK surrogate was spiked with aromatics of varying structures, with mono-aromatics (toluene; n-Propylbenzene), cyclo-aromatics (indane; 1-­Methylnaphthalene), and bi-aromatics (biphenyl) as well as at increasing concentrations. As seen in Figure 13.14, sooting tendency for these fuels followed the expected pattern, with an increased propensity for soot generation as the aromatic content increased. Das et al. (2017) also have shown that the sooting tendency will follow the aromatic content of the fuel, as long as the poly-aromatics and mono-aromatics ratios of various fuels are relatively constant. Deviations from this ratio will result in more variability in the predicted sooting tendency based solely on aromatic content. Table 13.1 provides several studies that made emission measurements of alternative jet fuels including UHC, soot, and particulates. Corporan et al. (2007) studied

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the emissions characteristics of natural-gas derived FT-SPK, JP-8, and their blends using a T63 turboshaft engine as well as an atmospheric swirl-stabilized research combustor. Test measurements (i.e., particle number, size, and mass) showed over 90% reduction in particle number and over 80% reduction in smoke number with the neat FT-SPK compared to JP-8. A similar test campaign was carried out by Buzlan et al. (2010) to measure particulate emissions (i.e., particle number density, size and mass) from a NASA DC-8 aircraft with GE CFM56-2C1 engine using FT-SPK, JP-8 and their 50vol%/50vol% blend. The results showed a drastic reduction in particulate emissions from FT-SPK compared to JP-8 without impacting the engine performance.

13.6 Summary The use of fuels not derived from traditional petroleum sources in power generation devices has potential benefits in a number of areas, including combating climate change and providing certainty in the supply chain. However, the combustion behavior of a given fuel can be tied back to its chemical composition. Hence, alternative fuels may impact combustor performance and this is an important consideration for operation of these devices. The production of most criteria pollutants (e.g., NOx, CO) from hydrocarbon combustion is largely independent of the fuel composition but is closely tied to combustion conditions such as temperature and pressure. However, soot production for hydrocarbon fuels will depend on the chemical composition as well as mode of combustion. For lean, premixed combustion, little soot is generally produced regardless of the fuel. For fuel-rich conditions or non-premixed combustion, the sooting tendency of a fuel is tied to its chemical structure, with fuels with aromatic content having a higher propensity to soot than straight-chained molecules. In addition to the alternative hydrocarbon fuels, carbon-free fuels such as H2 are getting much interest in recent years to combat climate change caused by CO2 emissions. Combustor development is underway to use H2 as the gas turbine fuel for power generation. However, there are many economical, logistical, and operational challenges for mass production and distribution of H2. Ammonia has been identified as a potential energy carrier for safer storage and transportation of H2. However, one of the challenges of burning NH3 in gas turbine combustors is that it can generate a significant amount of NOx from its fuel-bound nitrogen. Therefore, novel combustion strategies are needed to make NH3-fired gas turbines a reality for low-pollution, carbon-free power generation.

References Abian, M., Alzueta, M. U. & Glarborg, P., 2015. Mixtures in a flow reactor: Toward an ­accurate prediction of thermal NO. International Journal of Chemical Kinetics, 47(8) pp. 518–532.

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Part IV

Case Studies

14 Certification of Drop-In Alternative Fuels for Aviation Mark Rumizen

14.1 Introduction In the mid-2000s, a confluence of environmental and supply security concerns drove the aviation community to consider alternatives to petroleum-derived jet fuels. It was recognized early on in the process that the sheer size of the existing aircraft fleet and supporting jet fuel infrastructure, along with regulatory constraints, precluded the introduction of a chemical energy carrier requiring aircraft or fuel handling equipment modifications. Consequently, the chosen path forward was focused on synthetic alternatives with essentially identical chemical compositions and physical properties, called drop-in fuels. This chapter will describe the regulatory basis enabling the use of these fuels by the existing aircraft fleet and the technical approach used to validate the drop-in nature of these fuels.

14.2 Background 14.2.1

Airworthiness Authority Regulatory Oversight of Aviation Fuels Regulatory Accommodation of Fuel Physical Characteristics: The Federal Aviation Administration (FAA) regulations applicable to aviation fuel are structured to accommodate liquid fuel’s unique physical nature as compared to aircraft parts. Once produced, aviation fuel enters a fungible supply system where it travels in close proximity to other types of fuel. For example, in the United States, fuels such as diesel, jet, and gasoline travel through multiproduct pipelines where jet fuel is exposed to possible mixing and contamination with these other, non-aviation fuels. Other sources of contamination exist at all points in the supply chain, requiring periodic spot checking of fuel quality relative to the specification requirements. Also, jet fuel is shipped in very large batches that can be combined with other jet fuel batches from other sources while in transit, thereby losing initial batch identity and associated fuel property data. Because jet fuel is traded as a commodity, ownership of batches of fuel can change hands several times throughout its journey to the airport. In recognition of this distribution system and the possible changing nature of liquid fuels, FAA regulations are targeted at the end point of the system: the aircraft. The regulations require the aircraft and engine manufacturer to specify the fuel (or fuels)

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that are permitted for use on the aircraft, and the regulations then require the aircraft operator (or airline) to only use those fuels listed by the manufacturer. How those fuels are produced, transported, or otherwise handled upstream of the wing of the aircraft is beyond the reach of FAA (and other national aviation authorities) regulations. On the other hand, the solid, non-changeable physical nature of aircraft parts warrants a different regulatory approach. Parts are manufactured under an FAA approved quality control system to an FAA approved type design and are not subject to property or performance changes as they travel from the factory to ultimate installation on an aircraft. The parts are tagged as “FAA approved” when they leave the factory and are not subject to any additional regulatory oversight such as inspection, or testing, other than verifying the correct part is installed based on the part number. Aircraft and Engine Design Oversight: The FAA approval of an aircraft or engine design is accomplished by issuance of a type certificate (TC). The TC consists of the type design, the operating limitations, the TC data sheet, and the applicable airworthiness regulations (14CFR Part 21.41) associated with the approval. The type design includes all the design details of the aircraft or engine such as drawings, software, and material specifications (14CFR Part 21.31). However, the type design does not include the aviation fuel, but rather the aviation fuel is specified as an operating limitation by the manufacturer (14CFR Parts 25.1521.c.2, 33.7.c.2). So, unlike the physical components of the type design, the FAA does not directly “approve” the fuel, but rather approves the engine or aircraft to operate on the specified fuel or fuels. In other words, any jet fuel that fits within the definition of the operating limitation may be used on the particular aircraft or engine. The aviation fuel community has leveraged this regulatory concept to facilitate the use of alternative jet fuels by the existing fleet of aircraft. Aircraft Operation Oversight: Once an aircraft and engine type design is approved by issuance of the TC, it may enter production and be delivered to operators, such as airlines or business jet owners. These operators must adhere to FAA operating regulations that include a requirement to comply with the airplane’s operating limitations (14CFR Part 91.9(a)). As discussed above, one of these operating limitations is the fuel designation or specification. Because aviation is a global business with aircraft flying to many different countries, the manufacturers rely on a small number of industry (or military) fuel specifications to define the fuels permitted for use on their aircraft. And, the fuel defined in those specifications for virtually all gas turbine powered aircraft is Jet A or Jet A-1.

14.2.2

Commercial Aviation Fuel Initiative (CAAFI) Commercial Aviation Fuel Initiative (CAAFI) was formed in 2006 by the commercial aviation community to promote the introduction of alternative jet fuels in response to environmental and energy security concerns relating to petroleum-derived jet fuel. Commercial Aviation Fuel Initiative is a coalition that is sponsored by the FAA, Airlines for America (A4A), Airports Council International-North America and the Aerospace Industries Association. Its members include US Government agencies and

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research institutions, academia, aircraft and engine manufacturers, along with both alternative and conventional fuel producers. As a coalition, it relies on its members to contribute to CAAFI’s goals and objectives by participating in the activities of four focus area groups: Fuel Certification and Qualification, Research and Development, Sustainability and Business. As CAAFI was being formed, its leadership decided to focus on “drop-in jet fuels” that could seamlessly enter into the existing jet fuel supply chain in recognition of the breadth and complexity of that supply chain and the economic value of the existing fleet of aircraft. This decision was also influenced by an understanding of the airworthiness authorities’ regulatory approach to the oversight of jet fuel (as explained above). Consequently, the FAA took lead on developing the regulatory approach established by CAAFI’s Fuel Certification and Qualification group. This approach relies on a determination of identicality to petroleum-derived jet fuel of any new alternative fuel produced from a nonpetroleum feedstock. If the resulting alternative jet fuel is essentially identical in composition and performance, it is handled and used as a Jet A or Jet A-1 fuel without restrictions.

14.2.3

ASTM International Aviation Fuels Subcommittee The primary fuel specification listed by aircraft manufacturers as their aviation fuel operating limitation is ASTM International D1655, “Standard Specification for Aviation Turbine Fuels.” This specification defines criteria for Jet A and Jet A-1 fuel. There are many other specifications such as national standards issued by a particular country or military standards that define criteria for these same fuels, but those specifications are aligned with ASTM D1655 and therefore support global availability of Jet A and Jet A-1 fuel for all aircraft1. Consequently, the global aviation expertise for jet fuel has coalesced around ASTM subcommittee D02.J that has oversight over this specification. In addition, the aviation regulatory agencies such as the FAA and the European Union Aviation Safety Agency (EASA) have grown to rely on this same ASTM fuel specification when certifying new aircraft and engines. It was a natural evolution of the activities of ASTM subcommittee D02.J to facilitate the issuance of standards to accommodate the introduction of synthesized jet fuels into the aviation fuel supply chain. The first standard, D7566, “Standard Specification for Aviation Turbine Fuel Containing Synthesized Hydrocarbons” was issued in 2009. This specification is called the drop-in fuel specification, because it specifies criteria for fuels made from nonpetroleum materials, but that are also Jet A and Jet A-1 fuels. Because of cross-referencing provisions in D7566 and D1655, Jet A or Jet A-1 fuels meeting D7566 are handled and used as D1655 fuels without need for any special accommodations. Subcommittee D02.J also published and updated version of D4054, “Standard Practice for Evaluation of New Aviation Turbine Fuels and Fuel

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This excludes specifications issued in Russia and China that are used by many countries still aligned with them.

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Figure 14.1  Alternative jet fuel approval process.

Additives” in 2009. This standard describes the evaluation process and data required to develop specification criteria for new drop-in alternative jet fuels. Both of these standards are key elements of the process utilized to validate that a new alternative jet fuel is safe to use on aircraft and will be described in detail later in this chapter.

14.3

Airworthiness Authority Approval of Drop-In Alternative Jet Fuels The regulatory concepts, fuel standards, and aircraft and engine design and operating requirements discussed above have been applied to an approval process that facilitates the approval to use these new, alternative jet fuels on virtually all gas turbine powered aircraft operating around the globe. This approach was conceived by the FAA working as the leader of the CAAFI Certification and Qualification (CQ) group and has led to the approval of seven different alternative jet fuel pathways (discussed later in this chapter). The process is described in Figure 14.1 and discussed in the following text. Block 1: As discussed above, each aircraft manufacturer defines the required fuel that must be used on the aircraft when certified by the aviation regulatory authorities. In most of the world, all manufacturers specify Jet A and Jet A-1 fuel. And as discussed above, these fuel types effectively rely on ASTM D1655 for global definition. So, any fuel that is considered Jet A or Jet A-1 can be used on virtually all existing gas turbine engine powered aircraft.

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Figure 14.2  Seamless integration of alternative jet fuels into supply chain.

Block 2: In recognition of this, the physical properties, chemical composition, and materials compatibility of all new, candidate alternative jet fuels are compared to typical petroleum-derived Jet A/A-1 fuels. ASTM has issued standard practice D4054 that defines the testing required to accomplish this. If the test data indicates that the candidate alternative jet fuel is essentially identical to petroleum-derived jet fuel, then the ASTM subcommittee considers it Jet A/A-1 fuel. Block 3: After the above determination is made by the subcommittee, the alternative jet fuel is added to ASTM D7566, the drop-in jet fuel specification, as a new annex. The annex includes descriptive criteria for the feedstock, conversion process, and composition, along with prescriptive criteria for the physical properties and composition. Currently, all of the fuels defined in the D7566 annexes require blending with conventional jet fuels at concentrations not exceeding a defined percentage, such as 50% or 10%. During production, testing of each batch of alternative fuel to the annex criteria is first required, followed by testing of the finished jet fuel after blending to the criteria in the main body of the specification. Block 4: Because the criteria in D7566 is more stringent than the criteria in D1655, each of these specifications includes language that allows the re-designation of D7566 fuel as D1655 Jet A/A-1 fuel. Once the new alternative jet fuel is added to D7566, and because of the re-designation provision in that specification, it is now considered a Jet A/A-1 fuel and therefore meets the certificated aviation fuel operating limitations of virtually all jet powered aircraft. In other words, it now fits the existing approval basis and can be used without any limitations, restrictions, or special handling provisions, effectively fitting into Block 1 of Figure 14.1. It can seamlessly enter the jet fuel supply chain without any additional approvals (see Figure 14.2). This is why the issuance of a particular alternative jet fuel annex in D7566 is considered “approval to fly” for that new fuel.

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14.4

Technical Evaluation of Drop-In Jet Fuels: ASTM D4054

14.4.1

Overview and Structure The critical role that jet fuel plays in the safe operation of an aircraft necessitates a very rigorous and comprehensive approach when evaluating candidate alternative jet fuels. ASTM D4054, “Standard Practice for Evaluation of New Aviation Turbine Fuels and Fuel Additives,” was developed and issued to standardize and define the criteria and testing necessary to ensure that alternative jet fuels are just as safe as petroleum-derived jet fuels. D4054 evolved from research conducted in the late 1990s by Dr. C. A. Moses of Southwest Research Institute to support the incorporation of SASOL’s semi-synthetic jet fuel into the United Kingdom’s Ministry of Defense DEF STAN 91-91 jet fuel specification (Moses, Stavinoha and Roets, 1997). The approach toward evaluating alternative (or synthetic) jet fuels was further defined in a protocol developed for the Coordinating Research Council and the US Army published in late 1997 (Moses, 2007). A task group was then established at ASTM to take this preliminary work and convert it into an ASTM standard practice to provide a more structured approach to develop data to support issuance of specification criteria for these fuels. D4054 specifies four tiers of testing described below, with periodic evaluations of that data by key stakeholder ASTM members such as engine and aircraft manufacturers. Once the data is complete, it is compiled in an ASTM Research Report along with other information on the conversion process, feedstocks, and other data and is balloted to ASTM subcommittee D02.J along with the proposed specification criteria for inclusion in D7566. The four tiers of testing are described below.

14.4.2

Tier 1: Jet Fuel Specification Properties Test data for the basic physical properties and some compositional criteria that are listed in the key jet fuel specifications such as D1655, D7566, DEF STAN 91-091, and MIL-DTL-83133 are provided under this tier. This includes testing for such properties as distillation, freezing point, thermal stability, and viscosity.

14.4.3

Tier 2: Composition and Fit for Purpose Properties This tier requires a full compositional analysis of hydrocarbons and trace materials such as organics (nitrogen, oxygen, sulfur) and in-organics (metals, phosphorus, etc.) along with more expansive testing of fuel properties called fit-for-purpose (FFP) properties. Fit-for-purpose properties are relatively stable and well understood for jet fuels derived from petroleum, so there is no need to include them in the jet fuel specifications. But, for fuels derived from other feedstocks using new conversion technologies, these properties may vary so they are checked for candidate alternative jet fuels. Properties such as surface tension, dielectric constant, specific heat, thermal conductivity, water solubility, dielectric constant, and autoignition are tested under this tier.

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Tier 3: Component/Rig Testing and Materials Compatibility The Tier 3 testing requirements, if any, are determined based on a review of the Tier 1 and 2 data by the engine and aircraft manufacturers. This testing may not be required for fuels exhibiting very nominal properties and composition, but for other candidate fuels this tier could require tests such as combustor rig, fuel nozzle rig, and auxiliary power unit altitude starting. Testing to evaluate the alternative fuel’s compatibility with fuel system materials and approved jet fuel additives may also be conducted under this tier if deemed necessary by the ASTM subcommittee.

14.4.5

Tier 4: Engine/Aircraft Testing Similar to Tier 3, testing requirements for Tier 4 are determined based on a review of the Tier 1 and 2 data by the engine and aircraft manufacturers. This testing may not be required for fuels exhibiting very nominal properties and composition, but for other candidate fuels this tier could require testing of complete turbine engines in test cells and/or aircraft flight testing. Engine parameters such as turbine temperatures and profiles, fuel flow, and combustor lean blow out would be evaluated during this testing.

14.4.6

Engine/Aircraft Manufacturers Engagement As stated earlier in this chapter, the performance and quality of aviation fuel is critical for ensuring safe operation of aircraft. The aviation industry has collaborated with the petroleum industry over the last 80 years of commercial operations to develop and maintain specifications that control the performance and quality of aviation fuel. The criteria in those specifications is driven primarily by the operational and safety demands of aircraft and aircraft engines. So, it was a natural evolution of this arrangement for the engine and aircraft manufacturers, or original equipment manufacturers (OEMs), to take a lead role in overseeing the evaluation of alternative fuels made from nonpetroleum materials. The OEMs conduct periodic reviews of the test data generated during the D4054 evaluation process to determine if the candidate alternative jet fuel exhibits any properties or performance that might compromise the current high level of safety of the existing aircraft fleet and aviation jet fuel supply. This is an iterative process, where data is examined and questions are generated by the OEMs and answered by the prospective fuel producer. The OEMs coordinate their own internal company review of the data with the ASTM subcommittee review to facilitate the ultimate approval to use the fuel once added to the D7566 drop-in fuel specification.

14.4.7

Fast Track Provision While the D4054 test criteria is intended to support approval of alternative jet fuels that exhibit properties that are within the range of petroleum-derived jet fuels, the OEM reviewers typically demand properties that are better than the outer bounds of

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Figure 14.3  D4054 fast track provision is for alternative jet fuels with nominal ­properties and composition.

the jet fuel range. As more and more D4054 alternative jet fuel evaluations were conducted over the last decade, it became apparent that there was a trade-off between the proximity of a particular alternative jet fuel’s properties and composition to those of a nominal jet fuel, and the scope of the required evaluation testing necessary to validate its acceptability. This led to the development and incorporation of the fast track annex in D4054 in 2019. The fast track annex provides a scaled-down test program for candidate alternative jet fuels with a nominal jet fuel hydrocarbon composition and physical properties (see Figure 14.3). However, in exchange for the scaled down testing requirements, a candidate alternative jet fuel utilizing the fast track process is limited to a 10% blend concentration when approved for incorporation into the D7566 specification. The one example to date of a fast track approval, HC-HEFA fuel of Annex A7 of D7566, was evaluated and issued in a relatively short time frame of approximately fourteen months, thereby validating the benefit of this new provision.

14.4.8

Pre-Screening of Prototype Sustainable Aviation Fuels The D4054 evaluation process is intended for alternative jet fuel pathways that have achieved a level of maturity that is indicative of a viable commercial-scale process. This typically requires a significant producer investment to scale up their operations to produce sufficient volumes of test fuel to support the testing and evaluation. Candidate producers found it difficult to obtain the necessary investment to support the D4054 process given the uncertainty of successfully completing it. To reduce this uncertainty, the CAAFI Research & Development group developed a pre-screening process that allows candidate producers to refine their conversion process to produce a fuel composition more closely aligned with conventional jet fuel, thereby increasing the probability of successfully navigating the ASTM D4054 process (CAAFI, n.d..). The pre-screening process evolved from research conducted under the National Jet Fuel

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Combustion Program and the European Union’s JETSCREEN program. It utilizes advanced analytical techniques such as nuclear magnetic resonance, two-­dimensional gas chromatography, and mid-IR absorption to characterize a candidate fuels composition and properties with very small volumes of fuel. This allows the candidate producer to refine their conversion process while working at a laboratory bench scale.

14.5

Drop-In Alternative Jet Fuel Specification: ASTM D7566

14.5.1

Overview and Structure During the initial deliberations at ASTM Subcommittee D02.J over how best to introduce specification criteria for alternative jet fuels, it became apparent that a stand-alone specification, separate and distinct from the petroleum-derived (or conventional) jet fuel specification D1655 was necessary. This decision was driven by the need to incorporate more stringent criteria for these new fuels that were lacking any demonstrable service experience and by the concern from petroleum producers of this more stringent criteria being applied to their mature, well-understood fuels. However, it was also recognized that these new fuels needed to fit within the existing jet fuel supply and operational infrastructure to be economically viable, but this existing infrastructure was based on the D1655 conventional jet fuel specification. The solution agreed upon by the subcommittee was to issue a new, stand-alone specification (D7566), but include a provision in that specification to allow “re-designation” of D7566 jet fuel batches to D1655 fuel. This would serve both objectives; more stringent criteria for production, and seamless integration into the existing infrastructure including meeting existing certification requirements (see Figure 14.2). It was also apparent that the initial conversion processes under consideration would all result in hydrocarbon products that were compositional subsets of a typical conventional jet fuel. For example, the Fischer–Tropsch process (Annex A1 of D7566) results in a pure paraffinic fuel, lacking the 8% to 20% aromatic concentration found in conventional jet fuel. Consequently, blending with conventional jet fuel was necessary to create a jet fuel composition that was within the experience base of conventional jet fuel. To accommodate the need for blending, a two-step approach was implemented where first the alternative jet fuel must meet criteria specified in an annex unique to that fuel, then after blending with conventional jet to below a prescribed limit, the finished jet fuel is again tested to criteria specified in the main body of the specification (see Figure 14.4). Each annex contains two tables that list property requirements for the alternative jet fuel. The first table specifies primarily physical properties such as density, freezing point, distillation, and thermal stability. In many cases, the same properties are specified in both D7566 for the blended jet fuel, or in D1655 for conventional jet fuel, but differences from D1655 or D7566 either reflect fundamental differences between the annex blend component and Jet A, such as a different density requirement, or are more restrictive properties necessary to control the annex blend component within data generated during the D4054 evaluation process, such as thermal stability.

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Figure 14.4  D7566 specification structure (note: does not reflect current version of the specification which now includes seven annexes).

The second table specifies other detailed requirements for the annex blend component, focusing on composition with criteria for bulk hydrocarbon composition and trace materials. These properties are intended to support management of change events such as the start of production, significant changes to the process, or as necessary to support continued production of a consistent, high-quality product. However, currently all of the annexes except Annex A1 require measurement of these properties for each batch of alternative fuel blend component. It is hoped that as more experience is gained with fuel produced to the other annexes, the testing requirements for the second tables will be moved from each batch to a management of change frequency.

14.5.2

Annex Overviews Starting with the initial version of D7566 that was issued in 2009, new annexes have been periodically approved resulting in the current total of seven. Each annex is the product of the rigorous testing program conducted in accordance with D4054 as described above, and includes a qualitative description of the conversion process, feedstock, and composition of the resulting alternative fuel. In addition, each annex includes property requirements that the alternative fuel must meet when tested in accordance with the specified ASTM test method.



A1: Fischer–Tropsch Hydroprocessed Synthesized Paraffinic Kerosene This annex provides criteria for synthesized paraffinic kerosene (SPK) produced by the Fischer–Tropsch (FT) process. The FT-SPK process specifies a carbon monoxide

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and hydrogen synthesis gas as the feedstock. This synthesis gas is produced from the gasification of coal or biomass, or reforming of natural gas. The FT reactor then converts the synthesis gas to a hydrocarbon product. This is followed by typical refinery processing techniques such as hydroprocessing or isomerization to produce a jet fuel blending component primarily composed of iso-paraffins. The subcommittee agreed that any carbon source, including coal, natural gas, or biomass, is an acceptable starting material because the conversion of the starting material to synthesis gas along with the cleanup required for the FT reactor erases any trace of the starting material. Therefore, the properties of the FT product are independent of the starting material. The annex allows blending up to 50% by volume FT SPK with Jet A, subject to property limitations such as density and aromatics concentration on the final blended jet fuel.



A2: Synthesized Paraffinic Kerosene from Hydroprocessed Esters and Fatty Acids This annex provides criteria for SPK from hydroprocessed esters and fatty acids (HEFA). The feedstocks are any mono-, di- and tri-glycerides, free fatty acids and fatty acid esters. Typical tri-glyceride feedstocks are soybean, algae, or other plant oils. The HEFA conversion process consists of a catalytic deoxygenation step followed by hydroprocessing. Similar to FT, HEFA consists of primarily iso-paraffins and exhibits similar properties, and may be blended up to 50% by volume with Jet A due to similar property limitations.



A3: Synthesized Iso-paraffıns (SIP) from Hydroprocessed Fermented Sugars Unlike the first two annexes, the alternative jet fuel blending component specified in this annex is a single hydrocarbon compound called farnesane. Farnesane is an iso-paraffin with 15 carbon atoms, representing the high end of the jet fuel molecular weight range. Sugars are fermented using a genetically engineered microorganism to produce the base hydrocarbon product. This is followed by hydroprocessing to produce the farnesane iso-paraffin final product. Conventional jet fuel is comprised of a broad distribution of hydrocarbons containing from 8 to 16 carbon atoms that supports combustion across the wide range of operating conditions that gas turbine engines must operate in. Consequently, SIP is limited to a 10% blend concentration to avoid overloading the blended jet fuel with compounds in one slice of the compositional distribution.



A4: Synthesized Kerosene with Aromatics Derived by Alkylation of Light Aromatics from Nonpetroleum Sources The conversion process described in this annex is an adaptation of the FT-SPK process specified in Annex A1 that produces a similar alternative jet fuel blend component, but with aromatics. The conversion process adds a benzene-rich stream to the FT reactor which then converts the benzene to other aromatics in the jet fuel molecular weight range along with the production of the FT-SPK. The result is FT-SPK plus 15

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to 20% aromatics and is called FT-SPK/A. The feedstocks, property limitations, and blending limits are all similar to Annex A1.



A5: Alcohol-to-Jet Synthetic Paraffinic Kerosene (ATJ-SPK) The conversion process described in this annex starts from an alcohol chemical feedstock. The alcohol is dehydrated into alkenes, followed by oligomerization where the alkenes are combined into higher molecular weight unsaturated oligomers. Unsaturated oligomers that have molecular weights within the jet fuel range are separated and further processed in the third major step, hydrogenation, to produce the final ATJSPK jet fuel for blending purposes. Alcohol-to-Jet synthetic paraffinic kerosene may currently be blended with conventional jet fuel at a 50% concentration.



A6: Synthesized Kerosene from Hydrothermal Conversion of Fatty Acid Esters and Fatty Acids The Annex A6 conversion process is referred to as catalytic hydrothermolysis jet (CHJ). The CHJ process combines hydrothermal conversion and hydrotreating to convert the same feedstock that HEFA uses to produce a fully formulated alternative jet fuel (including aromatics) that is compositionally within the range of conventional jet fuel. There are not any property limitations that necessitate blending of CHJ with conventional jet fuel, but a maximum 50% blending limit was specified to allow the accumulation of service experience prior to permitting its use unblended.



A7: Synthesized Paraffinic Kerosene from Hydroprocessed Hydrocarbons, Esters, and Fatty Acids (HC-HEFA) The conversion process specified in this annex utilizes the same HEFA conversion process as described in Annex A2, but relies on a feedstock comprised of hydrocarbons in addition to free fatty acids and fatty acid esters. This unique feedstock is derived from the Botryococcus braunii algae which produces an oil containing a high percentage of unsaturated hydrocarbons known as botryococcenes, instead of triglycerides or fatty acids that other species of algae produce. This annex was the first to be approved under the D4054 Fast Track Annex described above. The fast track annex reduces the amount of testing for evaluation and approval of new alternative jet fuel blending component, provided the compositional and performance criteria are met. The blend ratio of HC-HEFA with conventional jet fuel is therefore limited to 10% maximum.

14.6

Certification of Non-Drop-In Aviation Fuels

14.6.1

Potential Future Aviation Fuels The recent increased focus on climate change and the associated interest in reducing carbon emissions from aircraft has generated several concepts for use of carbon-free fuels such as hydrogen or ammonia to fuel either combustion engines or fuel cells

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(Summary of Key Messages Delivered at the Technical Workshop “Hydrogen-­ Powered Aviation Research and Innovation”, 2021). Hydrogen’s appeal as an aviation fuel is derived from its superior specific energy (per unit mass) relative to liquid kerosene jet fuel. However, this is offset by hydrogen’s inferior energy density (per unit volume). This results is a fourfold increase in volume of hydrogen to obtain an equivalent amount of energy as jet fuel. In addition, hydrogen must either be cooled to −253°C to store as a liquid, or pressurized to avoid escaping the atmosphere, or both, to carry on an aircraft. Also, unless “green hydrogen” is used, the carbon emissions from extracting hydrogen from natural gas offset any benefit from zero emissions engine combustion. Ammonia, which is simply a chemical means to carry hydrogen, has also been proposed for use on aircraft, but the hydrogen must be separated from the nitrogen prior to fueling a combustion engine or fuel cell. Ammonia is also toxic, so special handling accommodations are required (Ammonia Could Fuel the Future of Sustainable Flight, 2021). The accommodation of either hydrogen or ammonia as an aviation fuel would require new aircraft and engine designs and major aviation fuel supply infrastructure modifications requiring significant resources and time.

14.6.2

Aircraft and Engine Design and Certification Redesign of an aircraft and engine to operate with a new, non-drop-in fuel such as hydrogen or ammonia is a significant undertaking. For example, hydrogen would require the fuel tanks to be relocated from the wings to fuselage due to its low energy density, and the tanks would need to cryogenically cooled and pressurized, adding significant complexity to the design. While the storage of ammonia on an aircraft may not be as challenging, new fuel system components would need to be designed to heat and chemically convert the ammonia to hydrogen. Fuel cells may be feasible for small aircraft, but this would require a completely new aircraft design for this entirely new means of propulsion. After the design is completed, it must then be certified with the national aviation authority, such as the FAA in the United States. The certification process typically takes several additional years after the aircraft design is completed. Finally, when the new aircraft is ready for production, and if a fuel supply infrastructure is in place, it will take many years for these new design aircraft to have any notable penetration into the current population of jet fueled aircraft.

14.6.3

Aviation Fuel Supply Infrastructure The aviation fuel supply infrastructure that has evolved over the last eighty years has done a commendable job of delivering a safe and reliable product to airports all over the world. Coordination and collaboration between standards development organizations such as ASTM International, aircraft and engine manufacturers, airlines, the military, petroleum companies, pipeline companies, and many other stakeholders involved in the production, transport, handling and use of jet fuel is a necessary aspect of this delivery system due to the absence of aviation authority oversight of the jet fuel

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supply chain upstream of the airport. The introduction of a new, non-drop-in aviation fuel would require the establishment of a separate and distinct supply chain from production to delivery to the airplane. Adding to this challenge are the safety concerns and special handling requirements of fuels such as hydrogen or ammonia. In addition, because the utility and versatility of aircraft is enabled by a common fuel available across large geographic areas, or even globally in the case of jet fuel, the introduction of a new fuel in only selected regions would greatly limit the utility, and therefore value of a new aircraft.

14.7 Conclusion The FAA in collaboration with the aviation fuel community has established a relatively structured approach to facilitating the use of safe, well-vetted alternative jet fuels, including those produced from renewable materials. These fuels possess essentially identical properties and composition and can therefore seamlessly enter into the existing, well-established jet fuel supply infrastructure without any special handling or accommodations. They can be used on virtually all existing gas-turbine powered aircraft without any modifications or additional approvals from the national aviation authorities. As compared to the challenges associated with introducing a new fuel, such as hydrogen or ammonia, the advancement and support of drop-in jet fuels is clearly the more economically feasible path to reducing aviation’s carbon emissions. This chapter was first published at https://www.caafi.org/focus_areas/docs/Cert_of_ Av_Fuels_MRumizen_Open_Access.pdf under a Creative Commons Attribution licence (http://creativecommons.org/licenses/by/4.0/), which permits unrestricted re-use, distribution and reproduction in all territories, provided proper attribution is given.

References Ammonia Could Fuel the Future of Sustainable Flight (2021) Raytheon Technologies Research Center. Available at: www.rtx.com/News/2020/12/09/ammonia-could-fuel-thefuture-of-sustainable-flight. CAAFI (n.d.) CAAFI Pre-Screening. Available at: https://caafi.org/tools/Prescreening_Guidance.html. Moses, C. A. (2007) Development of the Protocol for Acceptance of Synthetic Fuels Under ASTM D 1655. Available at: Coordinating Research Council, Inc. Technical Report AV-2-04. Moses, C. A., Stavinoha, L. L. and Roets, P. (1997) Qualification of SASOL Semi-Synthetic Jet A-1 as Commercial Jet Fuel. Available at: Southwest Research Institute Technical Report SwRI-8531. Summary of Key Messages Delivered at the Technical Workshop “Hydrogen-Powered Aviation Research and Innovation” (2021). Available at: www.fch.europa.eu/sites/default/files/ 20210526_CA-CH_Workshop_key_messages.pdf.

15 Fuel Composition Influences on Reciprocating Engine Performance Jim Szybist, Scott Sluder, John Farrell, and Robert Wagner

15.1 Introduction The introduction of new fuels into the market is a unique opportunity to take advantage of new fuel compositions to improve the efficiency and emissions of internal combustion reciprocating engines and alternative fuel feedstocks. However, there are numerous challenges that introductions of new fuels face before they can become first legal, then ubiquitous. A major challenge is that this introduction and subsequent adoption requires that the new fuel and engine technologies enter the market with well-planned and executed timing. This precision is needed to ensure that new fuels and new engine technologies are both simultaneously available in sufficient quantities to ensure success in the marketplace. Further, the changes in fuel composition must either be compatible with the legacy fleet, or have controls in place so that misfuelling with the legacy fleet does not occur. Introducing a new renewable fuel into the marketplace that is fit-for-purpose with legacy engine technologies may accelerate the fuel adoption, but it may also reduce the opportunity for improved efficiency and/ or emissions. The magnitude of the fuel production, distribution, and consumption in the US and worldwide is simply massive. In the US alone there are 129 operable refineries (U.S. EIA, 2021) that annually produce 125 billion gallons of gasoline, 56.4 billion gallons of diesel, and 16.9 billion gallons of jet fuel among other smaller-volume products (U.S. EIA, 2021). To put this in perspective, this is equivalent to consuming the volume of the Empire State Building two times every day. These liquid fuels are distributed across the country in over 64,000 miles of shared pipelines for liquid petroleum products (U.S. Department of Transportation, 2021). The gasoline that flows through these pipelines and supports blending with nearly 14 billion gallons of ethanol in the US on an annual basis, resulting in more than 2.9 trillion light-duty vehicle miles traveled (Davis and Boundy, 2021), or nearly 100,000 miles/second. The diesel fuel that flows in these pipeline supports more than 3.1 billion ton-miles of freight movement over the on-highway heavy-duty vehicles, on trains, and on waterways. These refining, fuel distribution, biofuel blending, and fuel consumption activities occur on a daily basis with very few major disruptions. The disruptions that do occur

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typically result in short-term localized fuel shortages and/or modest price increases, such as when refineries need to temporarily shut down due to a hurricane. However, given the logistical and technical interdependencies of this system of systems, changes to the composition of a fuel or introducing a new fuel can have unintended consequences. This chapter reviews four different case studies related to changing fuel composition. In some circumstances, the fuel formulation was changed in seemingly minor ways, and resulted in the unanticipated consequences. In other cases, a fuel change was desired, but an unexpected barrier slowed the introduction of the fuel change. These case studies should be viewed as opportunities to understand the interdependencies that exist and factors that need to be considered when trying to change the fuel in the marketplace.

15.2

Case Study 1: Tetraethyl Lead Removal and Valve Seat Recession In 1921, Thomas Midgely found that tetraethyl lead (TEL) reduced end-gas knock in spark-ignition engines (Splitter et al., 2016), and it was subsequently incorporated into market gasoline to improve engine performance and efficiency through a higher octane number (ON). Lead had been known to be toxic for centuries, so there were toxicity concerns about TEL starting prior to its market introduction. In 1925, the surgeon general acted on these concerns and suspended the use of TEL, but within a year, this suspension was changed to a concentration limit (Splitter et al., 2016). The use of TEL in the US continued unhindered for nearly five decades, until Congress passed the Clean Air Act in 1970, which included the first national tail-pipe emissions standards that regulated emissions of carbon monoxide, volatile organic compounds, and nitrogen oxides (NOx). Compliance with the Clean Air Act necessitated aftertreatment catalysts, but the catalysts were quickly poisoned by TEL and the anti-­deposit halogenated additives required with TEL. Thus, it was compliance with criteria pollutant regulations, rather than direct toxicity concerns, that began the decades-long phase-out of TEL. During the decades when TEL use continued nearly unhindered, engine technology became dependent on the lead additive in some additional ways. Specifically, engines of that time had exhaust valves seated directly on the cylinder head, which was made of cast iron or soft steel. Without the use of TEL, the valve’s placement could lead to an accelerated wear phenomenon known as valve seat recession. Hutcheson (2000) describes this wear process as micro-welds forming between the valve and seat, which are subsequently broken apart and oxidized to form hard-wear particles. These particles embed into the valve seat and cause abrasive wear, or valve seat recession, leading to early engine failure. Tetraethyl lead disrupts this process by introducing a layer of a dissimilar metal and preventing the initial micro-welds. The full extent to which valve seat recession was ever a widespread problem in practical applications is debatable. Thomas (1995) reviewed the existing literature and found valve seat recession is primarily found in laboratory studies under severe

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conditions. Relatively small reductions in the severity of operating conditions resulted in large changes in the extent of valve seat recession, with a drop in vehicle speed from 70 mph to 60 mph reducing valve seat recession by two-thirds (Weaver, 1986). Multiple large studies of in-use valve seat recession conducted by the US Army and US Postal Service found the laboratory findings of valve seat recession were overstated for real engine duty cycles, and that overall, the maintenance costs on average were higher for vehicles using leaded fuels (Thomas, 1995; Weaver, 1986). The higher maintenance costs associated with TEL are attributed to accelerated wear of the spark plugs, fuel filter, exhaust system (Wintringham et al., 1972), and through-engine rusting (Weaver, 1986). In order to be compatible with unleaded gasoline, US manufacturers began incorporating hardened valve seat inserts in the early to mid-1970s, coinciding with the introduction of unleaded gasoline in the US in 1974. As a result, valve seat recession was only a concern for legacy vehicles, and leaded gasoline was virtually phased out by 1986. By this time, the primary purpose of TEL in gasoline was to prevent valve seat recession, as refinery technologies had advanced to where it wasn’t necessary for ON improvements. It took another decade, until 1996, for leaded gasoline to be completely banned. The lead phase-out was much slower in Europe, where unleaded fuel wasn’t introduced until 1989 and not banned until 2000. Because leaded gasoline was widely available in Europe well after it was banned in the US, European cars continued to be produced without hardened valve seats, prolonging the need for leaded gasoline by a decade or more. In July 2021, Algeria became the last country in the world to fully ban the use of TEL in gasoline (Domonoske, 2021), 100 years after it was initially discovered to reduce knock and more than 45 years after its phase-out began in the US. The worldwide usage of TEL could have been phased out much more quickly, preventing decades of toxic lead exposure, had it not been for the concerns over valve seat recession and not preemptively adopting an existing hardened valve seat technology sooner.

15.3

Case Study 2: Introduction of Methyl Tertiary-Butyl Ether (MTBE) Methyl tertiary-butyl ether (MTBE) represents a cautionary tale for how changes to our fuel supply can bring about unintended consequences. First introduced in 1979 in response to the need for high-octane gasoline blend components commensurate with the phase-out of TEL, MTBE received a further boost of support from the Clean Air Act of 1990, which mandated the presence of oxygenates in reformulated gasoline (RFG) to reduce air pollutants. With the engine and emission control technologies in use at that time, oxygenated gasoline resulted in lower carbon monoxide emissions, which was important for addressing air-quality concerns in areas that exceeded federal air-quality standards. However, by the late 1990s, significant concerns were being voiced due to MTBE’s health impacts related primarily to groundwater contamination, and by the early 2000s states started banning its use as a fuel additive.

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The final death knell for MTBE was signed with the Energy Policy Act of 2005 (EPAct, 2005), which failed to include a provision shielding MTBE manufacturers from liability from water contamination lawsuits. EPAct 2005 also removed the oxygenate requirement in RFG and created a renewable fuel standard, which effectively defined ethanol as the sole oxygenate in US gasoline for the subsequent two decades. As a result, MTBE use ceased in the US in 2005, though its use continues in other countries.

15.3.1

Early Use and History of MTBE The phase-out of TEL created significant challenges for refiners and fuel providers – TEL was a cheap and effective octane enhancer, and its elimination created a need for alternatives to cost-effectively elevate the octane number (ON) of the base gasoline fuel to meet market gasoline requirements. There were numerous other options – notably ethanol and other refinery streams such as alkylate and reformate – but MTBE was particularly attractive due to its effectiveness at elevating ON, low sulfur concentration, and relatively low vapor pressure (especially vs. ethanol), which provided valuable refining flexibility. Moreover, MTBE production was economically attractive, as it could be readily produced in refineries from low-value iso-butylene streams and methanol, and could be shipped through existing pipelines, unlike ethanol. Methyl tertiary-butyl ether was first used at low levels in US gasoline in 1979 (MTBE, Oxygenates, and Motor Gasoline, 2000), and its use increased throughout the 1980s. The US Environmental Protection Agency (EPA) approved the blending of MTBE up to 11% by volume in 1981 and extended this limit to 15% in 1988 (U.S. EIA, 2000). The summer volatility (Reid vapor pressure, or RVP) restrictions in 1989 and 1992 provided additional incentives to favor MTBE vs. ethanol. These restrictions were enacted to reduce evaporative fuel tank emissions from gasoline, which contributed to poor air quality. Its bright future seemed secured in November 1990 when amendments to the Clean Air Act were adopted, one of which required the use of oxygenated gasoline in areas with elevated air pollution. The Winter Oxyfuel Program, implemented in 1992, required that gasoline contain 2.7% oxygen by weight (equivalent to 15% MTBE by volume) during the cold months in cities with elevated carbon monoxide. Methyl tertiary-butyl ether use ramped up from 83,000 barrels per day (BPD) in 1990 to 269,000 BPD in 1997. The introduction of RFG regulations in 1995 (Phase 1) and 1999 (Phase 2) (U.S. EPA, 1999) required reductions in automotive emissions of volatile organic compounds during the summer and toxic air pollutants and nitrogen oxides during the entire year. Although only mandated in the nine areas of the US with the worst ozone problems, many other areas voluntarily joined the federal RFG program (U.S. EIA, 2000). Reformulated gasoline was required to contain 2.1% oxygen by weight (11.7% by volume MTBE) (U.S. EIA, 2000). With the exception of the Midwest, which preferentially blended ethanol, refiners largely relied on MTBE to produce RFG.

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Environmental and Health Concerns As with most fuel components, there are numerous routes for human exposure to MTBE. These include evaporative emissions during refueling or subsequently from the vehicle’s fuel tank, unburned fuel from the exhaust during cold start, and storage tank and pipeline releases. Potential health concerns from MTBE exposure first came to light after introduction of MTBE to gasoline in Alaska in the winter of 1992 and were related to reports of nausea, coughing, and burning of the nose, throat, and eyes. Although no conclusive causal link was established (Ahmed, 2001), the Centers for Disease Control and Prevention (CDC) and a number of other health institutions initiated a series of studies to investigate. Their results indicated that at high exposure levels, MTBE causes a number of acute symptoms and is a potential human carcinogen (U.S. EPA, 1997; Mehlman, 2002). The most significant concerns regarding MTBE, and the accelerant for its ultimate demise, originated from groundwater contamination, primarily from leaking underground storage tanks and (to a lesser extent) from spills. Methyl tertiary-­ butyl ether is more water soluble (26  g/l) than most other gasoline components, biodegrades slowly, and adsorbs weakly to soil (Eweis et al., 1997; Tawabini, 2015), and consequently is readily transported to aquifers and municipal drinking wells and reservoirs. Once in drinking water, it imparts a disagreeable taste and can be detected at very low levels (~15 μg/l (U.S. EPA, 1995)). Although MTBE can be reduced to very low concentrations with simple treatments, effective in situ treatment methods were never identified. Several high-profile incidents in Maryland and California linked groundwater contamination of hundreds of residential wells to leaks from gasoline stations, bolstering public resistance and opposition to the fuel additive and resulting in costly remediation efforts by oil companies (U.S. Department of Justice, 2005).

15.3.3 Regulations Regulatory action was swift, at least on the legislative timescale. In March 1999, California announced a ban of MTBE by the end of 2002, citing a “significant risk” to California’s environment (The Associated Press, 1999). In June 1999, a specially convened EPA panel called for a substantial reduction in the use of MTBE, and in March 2000, EPA Administrator Carol Browner petitioned Congress to amend the 1990 Clean Air Act to significantly reduce or eliminate the use of MTBE in gasoline. The US Senate Environment and Public Works Committee voted in September 2000 in favor of a bill to phase out MTBE use over a four-year period while simultaneously boosting ethanol use. By 2004, Congress was contemplating legislation that would mandate ethanol use and drop liability protection for MTBE producers in groundwater contamination lawsuits. Although none of these congressional efforts resulted in binding legislation, the writing was on the wall: In 2002, BP and ExxonMobil both announced plans to switch from MTBE to ethanol within a year, and a growing number of states began

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to ban MTBE’s use as a fuel additive, reaching 25 states by 2007 (U.S. EPA, 2007). The final domino came in 2005, when the US Senate passed US energy law reforms that failed to grant companies the legal protections they sought from groundwater contamination. Moreover, they eliminated the oxygenate requirement of RFG and established the renewable fuel standard, which mandated significant increases in ethanol use. Although still legal to sell in much of the US, the business case for MTBE was problematic, and its use as a US motor fuel additive ceased. However, it is still produced in the US and sent overseas, primarily to Mexico, Chile, and Venezuela (U.S. EIA, 2018).

15.3.4

Lessons Learned It is fair to say that it was difficult to predict the magnitude of the problem that MTBE groundwater contamination would present when it was introduced. Although leaking gas tanks had been a source of soil and water contamination for decades, the high mobility of MTBE into groundwater reservoirs, its relatively slow environmental degradation, and its very low human detection levels conspired to elevate concerns over its release into a de jure national ban on its use in fuels. Modern underground storage tank regulations have been significantly impacted by the nation’s MTBE experience, and underground fuel leaks are fortunately increasingly rare with each service station underground storage tank’s replacement or retirement. Moreover, modern fuel dispenser and vehicle technologies dramatically reduce evaporative emissions, providing significant direct and indirect human health benefits. Efforts to identify new fuels have also taken these lessons to heart, with air and groundwater release impacts a major consideration applied to potential future fuels.

15.4

Case Study 3: Ethanol Blending in Gasoline

15.4.1

E10 Introduction Blending of up to 10% ethanol by volume into gasoline, known as E10, has been allowed in the US since 1978. This practice was first introduced as a reaction to gasoline shortages in the US market in the 1970s. In 1978, Gas Plus Inc. applied for a waiver under the Clean Air Act section 22(f)(4) to allow blending of 10% ethanol into gasoline (U.S. EPA, 1978). The applicants provided only limited data on the effects ethanol blending might have on emissions performance but included previously published data from 10% methanol and tertiary butyl alcohol blending studies. Environmental Protection Agency was allowed a 180-day review period under the Clean Air Act to either approve or deny the waiver, but they failed to approve or decline the waiver during the statutory period. Therefore, the waiver was granted by operation of the statute rather than by an EPA rule-making process. Environmental Protection Agency later clarified that blends of up to 10% were allowed as part of the original waiver and specified that the level was based on volumetric blending (U.S. EPA, 1979).

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The legalization of E10 did not incorporate significant study of the effects that these blends might have on vehicles or the installed fuel distribution infrastructure. Anecdotal reports of clogged vehicle fuel filters were common, likely a result of the difference in solvency of the ethanol blended fuels causing fuel tank deposits to become entrained in the fuel flow and redeposited in the fuel filter. Replacing the fuel filter generally resolved this issue but caused some backlash among consumers. There are no data to firmly establish the impacts, if any, on emissions compliance for E10 use in vehicles of the day. E10 remained a niche fuel that was predominantly available in the Midwest for several years, allowing time for automobile manufacturers to design products to accommodate both this fuel before it became widely available nationwide. As a result, emissions regulations advanced from their infancy in the 1970s and through the 1980s and 1990s with E10 as a legal fuel. Automakers responded to these regulations and marketplace demands by introducing new technologies such as port fuel injection, electronic closed-loop air/fuel ratio control, and other improvements. These technologies were introduced and matured in response to the range of fuel chemistries available in the marketplace, including both MTBE and E10. This timing meant that most technologies needed to meet more stringent emissions controls were compliant with E10 use from the outset. In the early 2000s, when MTBE lost its legal protections because it was found to be leaking from fuel storage tanks and contaminating groundwater, many states responded by enacting bans on the use of MTBE in gasoline to protect their drinking water supplies. With the bans on MTBE, ethanol emerged as a replacement to meet oxygen and ON requirements. This situation caused a rapid increase in the demand for ethanol that was further exacerbated by the biofuel requirements of the Energy Independence and Security Act of 2007. These two drivers resulted in enormous growth in ethanol demand and saturation of the US gasoline market with E10. By this time, however, vehicles and the fueling infrastructure had largely been constructed to accommodate E10 blends, so no large-scale technical problems arose.

15.4.2

E15 Introduction Increasing the amount of ethanol blended in gasoline beyond E10 was undertaken as a means of reducing the import of petroleum from international sources. This introduction began with the passage of the Energy Independence and Security Act (EISA) of 2007. EISA aimed to reduce US imports of petroleum through increased use of ethanol and other biofuels. The act set volumetric targets for ethanol utilization in the gasoline fuel marketplace as a means of spurring domestic biofuel production, with a target use of 36 billion gallons of renewable fuel use by the year 2022. A limit of 15 billion gallons per year of starch-based ethanol was included to incentivize deployment of cellulosic ethanol production technology. Annual gasoline consumption at that time was just under 140 billion gallons (Davis and Boundy, 2021). At a maximum ethanol blend level of 10%, the maximum uptake of ethanol into gasoline was approximately 14 billion gallons. This limitation became known as the “blend wall.” The blend wall blocked further increases in ethanol consumption needed to meet the targets specified

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by EISA and resulted in the need to enable higher ethanol blend levels in gasoline. In 2009, Growth Energy and several ethanol producers submitted a waiver request to EPA to allow the use of gasoline containing up to 15% ethanol (U.S. EPA, 2011). The US Department of Energy had begun investigating the use of both 15% and 20% ethanol (E15 and E20, respectively) prior to the passage of EISA, and so these studies provided results for both blends. Most studies that began after the waiver request was submitted focused only on E15. Since no other waiver requests were submitted, the only blend level that EPA could consider approving was 15%. Overcoming the blend wall posed challenges. Gasoline-powered cars and trucks had been designed to operate safely, reliably, and in compliance with emissions regulations using gasoline with up to 10% ethanol content. Increasing the allowable ethanol content in gasoline meant that cars and trucks already on the road, often called “legacy” vehicles, might encounter maintenance issues, unsafe conditions, and/or potentially exceed allowable emissions levels when using higher-level blends. The fueling infrastructure might also experience leaks or other maintenance issues from the use of higher ethanol blend levels. Unlike in previous fuel introductions, multiple organizations engaged to examine the potential issues that commercial mid-level ethanol blends could pose. Some organizations conducting studies favored introducing higher ethanol blend levels, while others opposed. Potential issues associated with increasing ethanol blend level were generally associated with either materials compatibility or regulatory requirements. The potential materials compatibility issues were of concern for the wetted parts of the fuel system: pumps, tanks, fuel injectors for vehicles, and dispensers and tanks for the refueling infrastructure. The integrity of pipes, connections, and seals was also a common concern. Materials compatibility concerns spawned a number of studies. Organizations concerned with the fuel distribution infrastructure conducted tests of gasoline dispensers, finding that failures were likely, although there wasn’t a discernable trend for new or used equipment. The report highlighted nonmetallic parts, notably gaskets and seals, as being involved in the failures (Boyce and Chapin, 2010). Studies were also conducted on materials commonly used in constructing underground fuel storage tanks and piping (Kass et al., 2011, 2012b, 2012a). These studies also found that metallic structures were not strongly affected by the increase in ethanol content. Tanks using resins in their construction showed mixed results, with isophthalic resins (more commonly used prior to 1990) providing the worst performance. Automakers and petroleum companies conducted several collaborative studies aimed at identifying potential issues with fuel system components such as fuel pumps and tank level sending units (Coordinating Research Council, 2013). Fuel pump tests demonstrated that some pump designs could accommodate the increase in ethanol content without problem, whereas others experienced performance deviations, including seizure of the pump. The most significant regulatory issue was that of emissions control durability. There was concern that some vehicles would experience hotter exhaust temperatures at wide-open throttle when operating with more ethanol in the gasoline (Knoll et al., 2010). Such conditions could lead to premature aging of the emissions control system, which might in turn cause the vehicle to produce excessive NOx, CO, and/or

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unburned hydrocarbon emissions. An 86-vehicle catalyst durability study showed that when driven for their full useful life mileage using 15% and 20% ethanol blends, vehicles were no more likely to produce excessive emissions than those operated using an ethanol-free fuel (West et al., 2012). Studies were also conducted to examine the impact that higher ethanol blends could have on engine components (Shoffner et al., 2010), small non-road engines (Hilbert, 2011; Knoll et al., 2009; Miers and Blough, 2013), certification procedures involving non-methane organic gas emissions measurement (Sluder and West, 2012), fuel economy certification (Sluder et al., 2014), and other topics. One technical and regulatory issue that emerged was that increasing oxygenate levels in gasoline used by legacy vehicles could lead to erroneous malfunction indicator lamp (MIL) illumination. This issue grows more likely as oxygenate concentration increases but was noted to occur for some vehicles using E10 (Sluder et al., 2012). Changing the emissions and fuel economy certification fuel from an ethanol-free fuel to an E10 formulation also proved to be a problem that as of this writing has not been completely resolved (Sluder et al., 2014). EPA issued decisions in 2010 and 2011 that partially approved the E15 waiver request. E15 use was disallowed in non-road engines and vehicles older than model year 2001 but was allowed in vehicles model year 2001 and newer (Sluder et al., 2012; U.S. EPA, 2011). Automakers responded to the potential introduction of E15 into the marketplace by including this blend in the design envelope of new cars and trucks. Exposure of legacy vehicles to E15 was limited because the fuel took several years to enter the market in substantial volume. This delay allowed time for automakers to produce vehicles that were compatible with E15 and for these new vehicles to replace legacy vehicles in the fleet. Although the number of refueling stations offering E15 is growing as a result of pump replacement programs funded by the US Department of Agriculture and the ethanol industry, E15 sales volume remains low. The low sales volume of E15 can be attributed to EISA and Renewable Fuel Standard (RFS) volume requirements being tied to the amount of cellulosic ethanol produced in the US. Without existing production, the RFS doesn’t require additional volumes of ethanol to be used. Without an additional volume requirement, ethanol producers face headwinds in obtaining commercial financing for the construction of new cellulosic ethanol plants. This circular problem has been exacerbated by the need for an extension of a 1 PSI vapor pressure allowance for E15 to be able to meet regulatory requirements for use during the summer months. Congress included this allowance for E10 in the 1990 Clean Air Act Amendments. Many retailers are reticent to adopt a fuel blend that can only be sold during some months of the year, further limiting E15 market penetration.

15.5

Case Study 4: Introduction of Ultra Low-Sulfur Diesel (ULSD) Ultra-low-sulfur diesel (ULSD) was introduced to the marketplace on June 1, 2006 (U.S. EPA, 2011), enabling new emissions control technologies for diesel vehicles to reduce nitrogen oxides (NOx) and particulate matter emissions. These reductions

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were anticipated to be a requirement for diesels in the US Environmental Protection Agency’s (EPA’s) upcoming Tier 2 emissions standards. Additionally, reducing sulfur in diesel fuel had an immediate effect of reducing sulfur dioxide levels in ambient air. Prior to ULSD being introduced, the Diesel Emission Control–Sulfur Effects (DECSE) program was launched as a joint government/industry program to rapidly provide data on sulfur’s effects on emerging diesel emissions control technologies. These data were needed to provide a technical basis for EPA to engage in a rule-­ making aimed at reducing diesel sulfur content (U.S. EPA, 2005). The program ­investigated sulfur levels from 350 parts per million (PPM) down to 3  PPM using a designed fuel set, and aging studies were conducted on particulate filters, NOx traps, lean-NOx catalysts, and diesel oxidation catalysts. These studies documented improved performance as the fuel sulfur level decreased. A closely related vehicle study was also commissioned by the US (Clark et al., 2000; West and Sluder, 2000), which addressed a data gap in the DECSE program by showing that the new emissions control technologies could provide a path toward light-duty diesel vehicle compliance with Tier 2 emissions regulations if EPA ruled to reduce diesel sulfur content. These studies provided a wealth of data on the impacts of fuel sulfur on emission controls. Because the diesel fuel standard already included a lubricity specification, there were relatively few concerns about the impact that sulfur removal would have on the engine itself, and few, if any, studies were conducted in this area. Consumption of lubricating oils also emerged as a related concern. Lubricating oils contained relatively high amounts of molybdenum disulfide to enhance lubrication, and sulfur in the resulting exhaust stream from engine oil consumption was sufficiently high to pose harm to the new emissions control technologies, even when fuel sulfur content was reduced. This situation led to the need to formulate engine oils for diesel engines that contained less molybdenum disulfide but still provided robust long-term protection against wear in the engine. There were no large studies published on the potential impacts of sulfur removal on the fueling infrastructure. Concerns later emerged that diesel underground storage tanks were experiencing high levels of corrosion not observed prior to 2007, when ULSD became ubiquitous (Clean Diesel Fuel Alliance, 2012; Sluder and West, 2000; Sowards and Mansfield, 2014). The Coordinating Research Council (CRC), a nonprofit research organization, undertook a study to investigate this phenomenon, finding some statistical evidence that ULSD did result in more corrosion than diesel with higher sulfur levels. However, there were unforeseen issues and a number of interactions that prevented full understanding of the root causes of the increased corrosion (U.S. EPA, 2016). As of the time of this writing, the causes of increased corrosion in diesel storage tanks have not been completely resolved.

15.6 Conclusion The preceding discussion has highlighted several diverse challenges and unintended consequences that have accompanied changes to motor fuels during the past several

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decades, underlining the complexity of the fuel production, delivery, and use system. While fuel changes have been commonplace over the past century, fuel composition has become much more tightly controlled over the past several decades, driven by increased sensitivity to fuel properties of highly engineered engines and emission control technologies that must meet exceedingly strict performance and pollutant mitigation requirements. The earlier fuel change examples highlighted here – TEL removal and MTBE introduction – proceeded (in hindsight) without a detailed understanding of the full range of system impacts that needed to be considered. Lessons learned from these experiences informed subsequent proposed fuel changes, which has decreased the number and severity of unintended consequences, though albeit while significantly extending the time and increasing the cost of new fuel introduction. While this discussion has focused on technical factors, it is also important to acknowledge that the most successful fuel changes have been accompanied by active participation from and cooperation between the diverse set of stakeholders, including fuel producers, distributors, retailers, vehicle manufacturers and equipment suppliers, standards organizations, regulatory agencies, and others. Additionally, the role of well-crafted policy cannot be understated – while many changes to fuels have been proposed, those that have ultimately been most successful were driven by clear benefits (e.g., to human health) and have maximized flexibility by leveraging market dynamics. In summary, it is critical to address the myriad of details, both technical and nontechnical, surrounding renewable fuel utilization holistically. Many of the details pertain to technical aspects of how the fuel production can result in a formulation that may enhance or detract from the performance of the energy conversion device for which it is intended. It is also important to address the technical aspects of regulatory guidance and standardization throughout the value chain to avoid the presence of problematic contaminants or limit variability of fuel properties to acceptable levels. Finally, addressing the concerns of stakeholders, including consumers, assures that a renewable fuel formulation can be introduced and achieve growth in the marketplace without falling victim to unforeseen problems.

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Coordinating Research Council. (2013). Durability of Fuel Pumps and Fuel Level Sends in Neat and Aggressive E15. Coordinating Research Council, Inc. Davis, S., & Boundy, R. G. (2021). Transportation Energy Data Book: Edition 39. Oak Ridge National Lab. Domonoske, C. (2021, August 30). The World Has Finally Stopped Using Leaded Gasoline. Algeria Used The Last Stockpile. NPR All Things Considered. Eweis, J. B., Chang, D. P. Y., Schroeder, E. D., Scow, K. M., Morton, R. L., & Caballero, R. C. (1997). Meeting the Challenge of MTBE Biodegradation. Air and Waste Management Association. Hilbert, D. (2011). High Ethanol Fuel Endurance: A Study of the Effects of Running Gasoline with 15% Ethanol Concentration in Current Production Outboard Four-Stroke Engines and Conventional Two-Stroke Outboard Marine Engines. National Renewable Energy Lab. Hutcheson, R. C. (2000). Valve Seat Recession-An Independent Review of Existing Data. SAE Technical PApers, 2000-01-2015. Independent Statistics & Analysis, U.S. Weekly Petroleum Product Supplied. (December 15, 2021). U.S. Energy Information Administrations. Kass, M. D., Theiss, T. J., Janke, C. J., Pawel, S. J., & Lewis, S. A. (2011). Intermediate ethanol blends infrastructure materials compatibility study: Elastomers, metals, and sealants. ORNL/ TM-2010/326, Oak Ridge National Laboratory. Kass, M. D., Theiss, T. J., Janke, C. J., & Pawel, S. J. (2012a). Analysis of underground storage tank system materials to increased leak potential associated with E15 fuel. ORNL/ TM-2012/182, July. Kass, M. D., Theiss, T., Janke, C., & Pawel, S. (2012b). Compatibility study for plastic, elastomeric, and metallic fueling infrastructure materials exposed to aggressive formulations of ethanol-blended gasoline. ORNL/TM-2012/88. Knoll, K., West, B., Clark, W., Graves, R., Orban, J., Przesmitzki, S., & Theiss, T. (2009). Effects of Intermediate Ethanol Blends on Legacy Vehicles and Small non-road Engines, Report 1-Updated. National Renewable Energy Lab, Golden. Knoll, K., West, B., Huff, S., Thomas, J., Orban, J., & Cooper, C. (2010). Effects of Mid-level Ethanol Blends on Conventional Vehicle Emissions. National Renewable Energy Lab. Mehlman, M. A. (2002). Carcinogenicity of methyl‐tertiary butyl ether in gasoline. Annals of the New York Academy of Sciences, 982(1), 149–159. Miers, S. A., & Blough, J. R. (2013). Evaluating the Impact of E15 on Snowmobile Engine Durability and Vehicle Driveability: September 22, 2010–August 15, 2013. National Renewable Energy Lab. Shoffner, B. A., Johnson, R. D., Heimrich, M. J., & Lochte, M. D. (2010). Powertrain component inspection from mid-level blends vehicle aging study. ORNL/TM-2011/65, Prepared by Southwest Research Institute for Oak Ridge National Laboratory. Sluder, C. S., & West, B. H. (2000). Catalyzed diesel particulate filter performance in a lightduty vehicle. SAE Transactions, 2528–2538. Sluder, C. S., & West, B. H. (2012). NMOG emissions characterizations and estimation for vehicles using ethanol-blended fuels. SAE International Journal of Fuels and Lubricants, 5(2), 721–32.

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Sluder, C. S., West, B. H., Butler, A. D., Mitcham, A. L., & Ruona, W. J. (2014). Determination of the R factor for fuel economy calculations using ethanol-blended fuels over two test cycles. SAE International Journal of Fuels and Lubricants, 7(2), 551–562. Sluder, C. S., West, B. H., & Knoll, K. E. (2012). Investigating malfunction indicator light illumination due to increased oxygenate use in gasoline. SAE International Journal of Fuels and Lubricants, 5(3), 1360–1371. Sowards, J. W., & Mansfield, E. (2014). Corrosion of copper and steel alloys in a simulated underground storage-tank sump environment containing acid-producing bacteria. Corrosion Science, 87, 460–471. Splitter, D., Pawlowski, A., & Wagner, R. (2016). A historical analysis of the co-evolution of gasoline octane number and spark-ignition engines. Frontiers in Mechanical Engineering, 1, 16. Tawabini, B. S. (2015). Removal of methyl tertiary butyl ether (MTBE) from contaminated water using UV-assisted nano composite materials. Desalination and Water Treatment, 55(2), 549–554. The Associated Press. (1999, March 26). National News Briefs; California Governor Bans Use of Gasoline Additive. The New York Times. Thomas, V. M. (1995). The elimination of lead in gasoline. Annual Review of Energy and the Environment, 20(1), 301–324. U.S. Department of Justice. (2005). Oil Companies Pay EPA To Settle Santa Monica MTBE Cleanup Costs. U.S. Department of Transportation. (2021). Annual Report Mileage for Hazardous Liquid or Carbon Dioxide Systems. Pipeline and Hazardous Materials Safety Administration. U.S. EIA. (2000). MTBE, Oxygenates, and Motor Gasoline. U.S. EIA. (2018). The United States continues to export MTBE, mainly to Mexico, Chile, and Venezuela. U.S. EIA. (2021). Independent Statistics & Analysis, Frequently Asked Questions. U.S. EPA. (1978). Gasohol Waiver Application. U.S. EPA. (1979). Fuels and fuel additives: Gasohol; marketability. Federal Register 44(68). U.S. EPA. (1995). Health and Environmental Research Online (HERO), https://hero.epa .gov/. U.S. EPA. (1997). Drinking Water Advisory: Consumer Acceptability Advice and Health Effects Analysis on Methyl Tertiary-Butyl Ether (MtBE). U.S. EPA. (1999). Phase II Reformulated Gasoline: The Next Step Toward Cleaner Air. U.S. EPA. (2005). Final rulemaking changes to motor vehicle diesel fuel credits. Federal Register 70(135). U.S. EPA. (2007). State Actions Banning MTBE (Statewide). U.S. EPA. (2011). Partial grant of clean air act waiver application submitted by growth energy to increase the allowable ethanol content of gasoline to 15 percent; decision of the administrator. Federal Register 76(17). U.S. EPA. (2016). Investigation of Corrosion-Influencing Factors in Underground Storage Tanks with Diesel Service.

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Weaver, C. S. (1986). The Effects of Low-Load and Unleaded Fuels Gasoline Engines, www .osti.gov/biblio/5635342. West, B. H., & Sluder, C. S. (2000). NOx Adsorber Performance in a Light-Duty Diesel Vehicle. SAE Technical Paper, 2000-01-2912. West, B. H., Sluder, S., Knoll, K., Orban, J., & Feng, J. (2012). Intermediate Ethanol Blends Catalyst Durability Program. Oak Ridge National Lab. Wintringham, J. S., Felt, A. E., Brown, W. J., & Adams, W. E. (1972). Car Maintenance Expense in Owner Service with Leaded and Nonleaded Gasolines. SAE Technical Paper, 720499.

16 Near-Zero- and Zero-Carbon Fuels in Industrial Gas Turbines Jeffrey Goldmeer

16.1 Introduction Gas turbines are able to utilize a wide variety of fuels, including fuels with lowor zero-carbon content. This includes hydrogen (H2), ammonia (NH3), synthetic and renewable natural gas, as well as a range of biofuels. These are sometimes referred to as zero-carbon, net-zero-carbon, or near-zero-carbon fuels. (The specific details of the fuel and its associated carbon footprint define which label is appropriate.) A subset of these fuels have been used to produce power from gas turbines for decades. This chapter will review experience and practical challenges in the use of these fuels in gas turbines for power generation applications.

16.2

Key Characteristics of Power Generation Fuels When using an alternative fuel, including zero- and near-zero-carbon fuels for gas turbine power generation applications, certain characteristics become important to ensure that the plant configuration is capable of both operating safely and delivering reliable power. Table 1 highlights a number of these parameters. The upper and lower flammability limits are important as they help to define ignition conditions (how much fuel is required), but they also define risks of creating and maintaining a flammable mixture should a fuel leak occur. Examining these fuels one can see that the lower flammability limit for ammonia is near the upper flammability limit for methane. Hence, ammonia isn’t flammable in concentrations that would be flammable for most hydrocarbons, which might lead to issues igniting the fuel in existing gas turbine combustion systems. Flame speed is a surrogate for fuel reactivity. Hydrogen is ~10 times more reactive than methane and alcohol-based fuels, which could lead to other challenges, namely flame holding and flashback. Ammonia on the other hand has ~20% of the reactivity of methane. This has the potential to create additional challenges in igniting this fuel in existing gas turbine combustion systems. The volumetric heating value of these fuels is important as well. Most gas turbines today operate on natural gas and have some range of flexibility in the fuels that they can utilize. From Table 16.1 it can be seen that the volumetric lower heating value

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Table 16.1  Key characteristics of net-zero- and zero-carbon fuels Characteristics Formula Lower flammability limit Upper flammability limit Flame speed Lower heating value

Units

Methane

Hydrogen

Ammonia

Methanol

Ethanol

%

CH4 4.4

H2 4

NH3 15

CH3OH 6

C2H5OH 3

%

17

75

28

36

19

cm/s MJ/Nm3 BTU/scf BTU/lb kJ/kg

~30–40 35.8 912 21,515 50,044

~200–300 10.8 275 51,593 120,005

~6–7 14.1 360 8,001 18,610

~20–40 30.1 767 9,066 21.087

~20–40 56.9 1,450 11,917 27.718

Note: LHV data for methanol and ethanol assumes they are in liquid phase. LHV data for all other fuels assume gaseous state.

(LHV) for hydrogen and ammonia is significantly lower of the heating value for methane. Therefore, matching the same input energy with hydrogen would require roughly two to three times the flow rate (depending on the fuel), which could impact the fuel system in power plants. Similar issues occur with alcohol-based biofuels. Light distillate fuel oil has a volumetric energy density of ~129,000  BTU per gallon in comparison to that of methanol and ethanol at ~57,250 and 76,300, respectively. This is in part due to the presence of oxygen in these fuels; hence they are sometimes known as oxygenates. Therefore, the use of these fuels may also require increased flow rates (relative to light distillate fuel oils) and may impact fuel accessory system configurations. Additional details on these fuels and their properties are provided in previous chapters. This is important information to have as it helps to define potential changes to operate a gas turbine on zero- and near-zero-carbon fuels.

16.3

Commercial Experience Many zero- and low-carbon fuels have been used in gas turbines for power generation applications for decades (Ansaldo Energia, 2021; Goldmeer and Catillaz, 2021; Hamilton et al., 2018; Mitsubishi Power, 2021; Siemens Gas & Power GmbH & Co, 2020; Solar Turbines, 2021a and 2021b). Some of these were situations with opportunity fuels (i.e., waste or by-product gases) that contained some percentage of hydrogen. At other power plants, these fuels were intentionally produced to transform a fuel feedstock into one that could be utilized with a gas turbine. This section provides an overview of the commercial experience on these fuels.

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Table 16.2  Gas turbine OEM operating experience on hydrogen and similar low heating value fuels Gas turbine OEM

Hours (millions)

Ansaldo GE Mitsubishi Siemens Solar

0.7 8.3 3.5 2.5 2

Figure 16.1  GE Gas Power hydrogen fuel experience (reproduced from Goldmeer and Catillaz, 2021).

16.3.1 Hydrogen Industrial and utility-scale power plants have more than 30 years of experience operating on hydrogen and similar low heating value fuels. The major gas turbine original equipment manufacturers (OEM), Ansaldo Energia (Ansaldo Energia, 2021) General Electric (Goldmeer and Catillaz, 2021), Mitsubishi Power (Hamilton et al., 2018; Mitsubishi Power, 2021; Komori et al., 2007), Siemens (Siemens Gas & Power GmbH & Co, 2020), and Solar Turbines (2021a, 2021b) have approximately 17 million operating hours on these fuels. Table 16.2 highlights the experience for each of the major gas turbine OEMs. Figure 16.1 highlights some projects with GE gas turbines utilizing fuels that contained hydrogen; Mitsubishi (Hamilton et al., 2018) and Siemens (Siemens Gas & Power GmbH & Co, 2020) have published similar information. Additional information on Mitsubishi’s experience may be found in Chapter 17. However, only a very few of these projects included operation on 100% H2; most have operated on blends of hydrogen and other fuels. Some of these turbines have been used in applications, where the hydrogen is part of a larger fuel mix that might be a waste or by-product of an industrial process, for example, coke oven gas (COG) or blast furnace gas in steel production. Most of these applications have used gas turbines configured with diffusion combustion systems, as they typically allow

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higher concentrations of hydrogen relative to (lean) premixed combustion systems. (These combustion systems and their hydrogen capabilities are described later in this chapter.) The next sections will explore experience with hydrogen fuels, including blending hydrogen with natural gas and the use of industrial by-products (that contain hydrogen) as gas turbine fuels.

16.3.2

Blending Hydrogen Fuel with Natural Gas There have been a number of projects that have or will soon be operating on blends of hydrogen and natural gas. In the past, some of these projects utilized hydrogen that was a waste gas from a chemical or industrial process and was used in an onsite gas turbine to displace some amount of natural gas, thereby reducing the plant’s fuel costs. In the future with new focus on reducing carbon emissions from power plants, the hydrogen may come from sources with lower carbon intensity (i.e., reforming of natural gas with carbon capture and sequestration, or the electrolysis of water). Regardless of the actual source, if the hydrogen is supplied to the power plant separately from natural gas it will have to be blended with the natural gas upstream of the gas turbine. When developing a fuel blending system, one must consider a number of factors including operating pressures and temperatures. The blending system must be capable of injecting the hydrogen into the natural gas stream which will be at a higher pressure than the gas turbine’s operating pressure. The fuel must be at a higher pressure than the gas turbine combustor to have a positive pressure gradient allowing the fuel to flow into the turbine, taking into account any pressure losses in the fuel system. Depending on potential variations in the composition of the hydrogen (i.e., it may be 100% hydrogen, or some other mixture with hydrogen), the blending system must be capable of controlling the rate at which this fuel is blended into the natural gas. Check valves may be required to prevent any back flow. The blending system may also be required to have shut-off or isolation valves that could be triggered in situations with large excursions in composition, temperature, or pressure in the hydrogen stream that could lead to operational or safety issues. The control system for a fuel blending system could be a separate system that is integrated with the power plant’s digital control system or it could be integrated directly with the gas turbine control system. Figure 16.2 highlights one potential implementation of a blending system control concept. Blending of fuels, including hydrogen, has been done commercially for many years. One example of hydrogen fuel blending in commercial operation was at The Dow Chemical Company’s Plaquemine, LA site. Four GE 7FA gas turbines were operated on a blend of hydrogen and natural gas (Goldmeer and Rozas, 2013). The gas turbines at this site provide internal power for the plant and have the capability to provide power to the local grid. Figure 16.3 shows blending skids that were installed to blend a hydrogen fuel mixture and natural gas; there was a separate blending skid for each gas turbine. First operation on blended fuel took place in May 2010. Another example of fuel blending is at the Gibraltar-San Roque refinery, which is owned by Compañia Española de Petróleos (CEPSA), one of Spain’s leading

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Figure 16.2  Fuel blending system control concept (Image courtesy: GE Gas Power).

Figure 16.3  Hydrogen fuel blending system (Image courtesy: GE Gas Power).

petrochemical companies. At this site, a refinery gas containing hydrogen and other hydrocarbons was blended into a GE 6B (~44 MW) gas turbine instead of being flared or otherwise being burned off. The use of waste gas decreased the need to purchase natural gas resulting in a ~7% heat rate improvement (Business Wire, 2015). With the growing interest in reducing carbon emissions, there is a parallel interest in blending hydrogen into natural gas for both new and existing power plants for both aeroderivative and heavy-duty gas turbines. This includes a number of demonstration/ pilot projects. A few examples are highlighted below and in Figure 16.4:

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Figure 16.4  Gas turbine power plants with planned hydrogen fuel blending. (A) Long Ridge Energy Terminal, (B) NYPA Brentwood Power Plant, (C) Cricket Valley Energy Center, (D) Smurfit Kappa Co-generation Plant (Images A–C courtesy GE Gas Power; Figure D reproduced from Yilmaz, 2020).

•  Long Ridge Energy Terminal (Ohio, USA) announced plans to operate a new GE 7HA.02 gas turbine on a blend of hydrogen and natural gas by the end of 2021. This power plant is expected to enter commercial operation in 2021. The gas turbine is capable of operating on blends between 15% and 20% hydrogen by volume (Patel, 2020). •  New York Power Authority announced a hydrogen project on a GE LM6000 aeroderivative gas turbine at the Brentwood Power Station (New York, USA). NYPA intends demonstrate the blending of green hydrogen and natural gas in the existing LM6000 at site by the end of 2021 (NY State Governor’s Office, 2021). This power plant was commissioned in 2001 to increase local power generation capacity for Long Island and New York City. •  Siemens Energy, Duke Energy, and Clemson University (South Carolina, USA) announced plans for a pilot project, H2-Orange, which will study the use of hydrogen for power in an existing Siemens SGT-400. This gas turbine, which is owned and operated by Duke Energy, is a part of a combined heat and power plant located at Clemson University. The plan is to generate green hydrogen using a Siemens Silyzer electrolyzer and blend (co-fire) the hydrogen with natural gas starting in 2021 (Clemson News, 2020). •  A consortium of companies and research institutions, including Engie, DLR, and Siemens, announced plans to demonstrate decarbonizing a combined heat and power plant (Saillat-sur-Vienne, France). The HyFlexPower project plans to operate a Siemens SGT-400 at this site on blends of green hydrogen and natural gas in 2022 (Yilmaz, 2020). Figure 16.5 highlights the project concept.

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Figure 16.5  Siemens HyFlexPower project concept (reproduced from Yilmaz, 2020).

•  Advanced Power announced a hydrogen blending project for their Cricket Valley Energy Center (Dover, NY). This is part of a memorandum of understanding signed with GE Gas Power. This MOU is expected to advance a hydrogen blending demonstration project on one of the 7F.05 gas turbines at site planned for 2022 (Burke, 2021). •  Intermountain Power Plant (Utah, USA) announced that it awarded a contract for two Mitsubishi Power M501JAC power trains (gas turbines + generators + steam turbines). The gas turbines will be delivered with capability to operate on a 30% hydrogen blend in 2025 (anticipated commercial operation date). The long-term plan is to transition the plant to operation on 100% hydrogen by 2045 (Clarion Energy Content Directors, 2020). More information is available in Chapter 17. •  EnergyAustralia announced their intention to begin blending hydrogen into a new GE 9F.05 gas turbine at the Tallawarra B plant (Walton, 2021) starting in 2025.

16.3.3

Industrial Fuels The use of fuels from industrial processes to power gas turbines has been ongoing for more than 30 years (Komori et al., 2007; Goldmeer and Catillaz, 2021; DiCampli, 2013). These applications can be grouped into two categories: (1) fuels that contain hydrogen that are intentionally produced for power generation and (2) process waste or by-product streams that contain hydrogen that are utilized for power generation.

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Figure 16.6  Integrated gasification combined cycle (IGCC) plant schematic (Image courtesy: GE Gas Power).

Fuels that contain hydrogen that are intentionally produced for power generation applications include synthesis gas (syngas) which is typically produced by gasifying coal or refinery residue. Refinery residue is a highly viscous oil that remains after distilling crude oils and is therefore a by-product of refining operations. It is also known as resid, fuel oil #6, or bunker fuel oil. Combining gasification and a combined cycle power plant creates an integrated system for generating power from fuels like coal and refinery residue; Figure 16.6 shows a conceptual diagram of an integrated gasification combined cycle (IGCC) power plant. The first demonstration of an IGCC plant at commercial scale was the Cool Water Project which used a GE 7E gas turbine to produce 96 MWe and ran from 1984 through 1989 (NETL, 2021). The first full commercial IGCC plant in the US was the Wabash project, which entered commercial operation in 1996 (NETL, 2021). Figure 16.7 shows both plants. Many other IGCC plants have entered into commercial operation in the US, Europe, and in Asia over the past 20 years using both E-class and F-class gas turbines. The composition of the syngas created in these IGCC plants can vary based on the gasification technology used, the gasification feedstock, etc. The result is that there isn’t a typical syngas composition, nor a typical hydrogen concentration. This is highlighted in Table 16.3 which shows syngas compositions from a variety of IGCC projects. Given the industry experience with hydrogen in syngas, the gas turbine OEMs developed an understanding of system level impact which will be detailed in the next section. The other half of this industrial fuels category are those that may come from processes in steel production, refining, chemical or petrochemical industry. Some of these gases also contain hydrogen, with concentrations ranging from a few percent to nearly 100%. One example of such a project was the Samsung General Chemical plant in Korea in which a gas turbine (GE Frame 6B) operated on a fuel with hydrogen concentrations that ranged from 85% to ~95% hydrogen by volume (Moliere and Hugonnet, 2004).

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Table 16.3  Syngas compositions from a variety of power projects (Todd, 2000). Gas compositions are all volume percent IGCC plant name

H2

CO

CH4

CO2

N2 + Air

H 2O

Schwarze Pumpe Exxon Singapore El Dorado Motiva Delaware Tampa PSI Sierra Pacific ILVA

61.9 44.5 35.4 32.0 27.0 24.8 14.5 8.6

26.2 35.4 45 49.5 35.6 39.5 23.6 26.2

6.9 0.5 0.0 0.1 0.1 1.5 1.3 8.2

2.8 17.9 17.1 15.8 12.6 9.3 5.6 14.0

1.8 1.4 2.1 2.2 6.8 2.3 49.3 42.5

0.0 0.1 0.4 0.4 16.7 22.7 5.7 0.0

Figure 16.7  Cool Water IGCC plant (A) and Wabash IGCC plant (B) (Images courtesy: GE Gas Power).

In the specific case of steel production, the process includes multiple steps, some of which create by-product gases with hydrogen. These include coke oven gas (COG) which is the by-product of the pyrolysis of coal (in a reduced oxygen environment) to create coke. The coke is then fed into a blast furnace and burned to create heat to melt iron ore; the by-product of this process is called blast furnace gas BFG. These gases contain varying levels of hydrogen and other constituents. Table 16.4 highlights typical composition of multiple steel mill by-product gases which could be used as power generation fuels. As reference, the LHV of methane is ~911 BTU/scf (~8560 kcal/ Nm3). Most of these steel mill gases have heating values less than 30% of methane, with a few even less than 20%, but they still have enough energy to be used as gas turbine fuels. Figure 16.8 shows a conceptual diagram of a steel plant integrated with an onsite power plant as well as the flow of gases. Figure 16.9 shows two steel mills that have integrated heavy-duty gas turbine power plants. The use of steel mill gases is not confined to heavy-duty gas turbines; some aeroderivative gas turbines have operated on COG fuels (Dicampli et al., 2012).

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Table 16.4  Typical composition of steel production by-product gases (Hall et al., 2011). Compositions are all volume percent

Gas

H2 (%)

Blast furnace gas (BFG) Coke oven gas (COG) BFG + COG blend Linz-Donawitz ­Furnace Gas (LDG) Finex Corex

LHV BTU/scf (kcal/Nm3)

CO (%)

CH4 (%)

CO2 (%)

N2 (%)

H2O (%)

2

23

0

20

55

0

80 (747)

55

10

25

5

4

0

428 (4019)

6 0

24 65

1.6 5

17 10

49 20

1.7 0

112 (1050) 255 (2394)

15 23

29 30

2 0.2

44 6

9 0.8

0 40

151 (1421) 162 (1518)

Figure 16.8  Schematic of a steel plant with onsite power production using by-product gases (Image courtesy: GE Gas Power).

16.3.4

100% Hydrogen In 2009, Enel operated a GE-10 gas turbine on 100% hydrogen at the Fusina Power Plant in Italy (Enel, 2009). This power plant utilized hydrogen from an adjacent petrochemical facility with the addition of a new, dedicated, hydrogen pipeline approximately 2.5 km long (Brunetti et al., 2010). Even though the power plant was connected directly to a petrochemical plant, there were limits on hydrogen supply. At maximum load, the gas turbine operated on a ~90% (by volume) blend of H2 and natural gas; this level of hydrogen was equivalent to ~75% of the thermal input to the plant. The plant also operated on 100% hydrogen at 35% of base load.

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Figure 16.9  (A) Steel mill plant in Italy with three GE 9E gas turbines fired on BFG/COG blends since 1996; (B) Steel mill site in China with two GE 9E gas turbines fired on COREX gas, operational since 2007 (reproduced from Jones and Goldmeer, 2012; Jones, Goldmeer and Monetti, 2011).

This gas turbine utilized a diffusion combustion system with diluent injection to mitigate NOx emissions. Based on lab experiments prior to the field demonstration, it was determined that steam injection could reduce NOx emissions to less than 100 parts per million (Cocchi et al., 2008) for steam/fuel mass ratios greater than 2. As expected, operating on blends of hydrogen and natural gas increased NOx emissions when operating without a diluent. When a diluent (e.g., steam) was added, NOx emissions were dramatically reduced (Power Engineering International, 2010; Baker Hughes, 2019). In 2020, Kawasaki announced that it operated a gas turbine configured with a dry low NOx (i.e., lean premix) combustion system on 100% hydrogen (Modern Power Systems, 2020). The turbine was part of a co-generation plant that produces 1.1 MW of electricity. The combustion system used in this gas turbine is described as applying a micro-mix technology. This micro-mix type of combustion system utilizes a series of small-scale injectors coupled with jet in cross flow mixing (Goldmeer, 2020).

16.3.5 Ammonia For many countries, the future energy transition to net-zero-carbon emissions could require importation of zero-carbon fuels, such as hydrogen. However, transporting hydrogen over long distances would likely require condensing to a liquid, which requires substantial energy investment to reach the required cryogenic temperature conditions (−253°C, −423°F). An alternative being assessed is the use of ammonia (NH3) as a hydrogen carrier since its boiling temperature is −33°C (−28°F). To date, there are no gas turbines in commercial operation with 100% ammonia or ammonia fuel blends. Mitsubishi Power announced they plan to have a commercial 40 MW gas turbine capable of operating on 100% ammonia in or around 2025 (Patel, 2021). IHI Corporation and Tohoku University tested ammonia on a 2 MW IM270 gas turbine (Ito et al., 2018; Shintaro et al., 2020). In this test, ammonia (20% by volume) was blended with natural gas. NOx emissions without after treatment increased from ~100 ppm to ~290 ppm. This was reduced to less than 10 ppm with the use of a

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selective catalytic reduction (SCR) system. They also reported that the output of the turbine increased by ~3% in part due to the increase fuel flow rate.

16.3.6 Biofuels This category includes a variety of fuels that can be divided into two main groups: liquids and gases. Liquid biofuels include alcohols as well as biodiesels produced from the oils of various seeds including corn, palm, soy, and rapeseed. There have been multiple biofuels demonstration projects as well as a small number of gas turbines in commercial operation on biofuels. Biodiesel has been used on some GE LM2500+ gas turbines in marine applications (DiCampli, 2013). Multiple demonstration projects for stationary power generation applications have been run using biodiesel; this includes a GE LM6000 in New York (DiCampli, 2013) as well as GE 6B and 7E gas turbines (Campbell et al., 2008; Moliere et al., 2007). Siemens demonstrated the use of 100% biodiesel (B100) on a SGT6-3000E with water injection. During commissioning of this unit on biodiesel it was reported that emissions targets were achieved by a slight derate of the engine relative to performance on distillate (Nag and Shoemaker, 2010). During these demonstrations the turbines were run at a variety of operating conditions, from start-up to full power on a range of biodiesel mixtures from B20 (20% biodiesel blended with distillate fuel oil) up to pure biodiesel (B100). Gas turbines have also operated on ethanol, both as demonstrations and in commercial operation. In 2008, a series of tests using a bio-ethanol were performed on a GE 6B gas turbine in India (Moliere et al., 2009). An interesting result of the 6B demonstration test was a slight increase in carbon dioxide emissions; since ethanol’s LHV is less than the LHV for natural gas, the gas turbine consumed more fuel to maintain the same output. This increase in fuel flow increased carbon dioxide emissions. There are also units that have used ethanol in commercial operation, including two LM6000 units in Brazil (Figure 16.10) (DiCampli, 2013; Power Technology, 2010), and a third operating on ethanol at a power plant on Réunion Island since 2019 (Albioma, 2019). The units in Brazil were converted to operate on both natural gas and ethanol. Methanol has also been considered as a potential gas turbine fuel for decades. In 1974, a 12-hour methanol fuel test was performed on a FT4C gas turbine at a power station in Florida (von KleinSmid et al., 1981). The unit was not able to reach rated output due to limits as methanol’s heating value is ~45% less (on a volumetric basis) than the heating value for light distillate fuel oil. In 1980, a test was run on a FT4C Twin Pak for more than 500 hours. The previous fuel system issues were addressed and the test results noted that “overall performance and efficiency is better than distillate or natural gas operations” (see Table 16.5 for additional information). Decades later, a methanol demonstration was performed on a 50 MW Pratt & Whitney FT4C gas turbine; this unit was located in Eilat, Israel (Day, 2016). Like the 1981 test, the liquid fuel system at this power plant was adjusted for the increased fuel rate required for methanol. Results of this demonstration reported similar heat rate relative to fuel oil.

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Table 16.5  Fuel performance comparison (Weir et al., 1981) Heat rate (BTU/kWh) Output (MW)

Methanol (dry)

Distillate (dry)

Natural gas (dry)

20 22 24 26

12,100 11,750 11,600 11,450

12,300 12,000 11.750 11,550

12,300 12,000 11,750 11,550

Figure 16.10  Two GE LM6000 gas turbines operating on ethanol in Brazil (Image courtesy: GE Gas Power).

There have been other smaller scale biofuel demonstrations as well. For example, in 2011 a small quantity of a biogas (>95% methane) produced from an anerobic digestor facility was blended with pipeline natural gas and used as fuel in a GE 9FB gas turbine at the E.ON Öresundsverket power plant in Sweden (Cornu and Svensson, 2012). Test results indicated no impact on combustion or emissions.

16.4

Practical Concerns When Utilizing Zero- and Near-Zero-Carbon Fuels The flexible nature of gas turbines lends themselves to being upgraded and adapted to operation on a wide range of gas and liquid fuels. This includes upgrading the gas turbine and power plant systems to operate on alternative fuels, including those with

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Figure 16.11  Power plant systems potentially impacted by the use of zero- or net-zero carbon fuels (reproduced from Goldmeer and Catillaz, 2021).

lower or zero-carbon content. However, some of these fuels may create challenges for reliable, robust power plant operations. This may impact plant systems beyond the gas turbine, as highlighted in Figure 16.11. Table 16.6 highlights some of the challenges relative to different power plant systems. The remainder of this section will provide additional details on these challenges along with appropriate mitigations.

16.4.1

Fuel Systems Most of the thousands of gas turbines operating globally today operate on natural gas or similar fuels (i.e., LNG). Some have dual fuel capability, meaning that they can switch to operation on diesel (light distillate) fuel. Others may be configured to operate on heavy liquid fuels (i.e., crude or heavy fuel oil). Each of these fuels requires a specific configuration of the accessory system that controls and meters flow; the same is true when operating on fuels that help to reduce the carbon footprint of power plant. This is especially important when looking to switch a gas turbine to operation on a zero- or net-zero fuel such as hydrogen or a range of biofuels, or even ammonia. When dealing with liquid fuels, the fuel accessory system is specifically customized to a given fuel type, and these may need to change when changing from one liquid fuel to another. For examine, switching from diesel (light distillate) to an alcohol-based biofuel may require changes to the system even though both are liquid fuels; diesel’s LHV is ~129,000  BTU/gallon versus methanol at ~57,250  BTU/gallon. Given the large reduction in volumetric energy content, fuel piping and fuel valves may have to change to allow larger fuel flow rates, depending on current configuration. A similar

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Table 16.6  Potential gas turbine power plants challenges due to the use of near-zero- and zero-carbon fuels Fuel

Accessory system

Gas turbine

Balance of plant (BOP)

Hydrogen

Degradation of seals Embrittlement of certain steels Larger fuel flow rates due to lower fuel LHV

Flame holding Flashback Increased NOx emissions

Biofuels (biodiesel)

Degradation of seals

Alkali-based hot gas path corrosion

Increase emissions ­treatment system needs Hazardous gas detection Gas turbine enclosure ventilation Start-up1 Long-term fuel stability Potential presence of fuel contaminants (i.e., Na, K)

Biofuels (alcohols)

Degradation of seals Larger fuel flow rates due to lower fuel LHV

Potential changes to combustor operability May require new fuel nozzles to match larger fuel flow rates No change anticipated2

Synthetic natural gas Renewable natural gas Ammonia

No change anticipated2 Degradation of seals Fuel toxicity

Ignition Combustor operability3

Increased NOx emissions Fuel toxicity

Notes: 1. Due to hydrogen’s increased flammability, failed starts may require additional purging or other ­procedure changes. 2. Assuming >90% methane with other components similar to pipeline quality natural gas. The presence of other compounds could impact fuel accessories, combustion, and/or plant BOP. 3. Ammonia’s lower reactivity might impact gas turbine operations, including ramp rate and turndown.

resizing activity may be required if switching from natural has to be a blend of natural gas and hydrogen (depending on the specific blend ratio) or to 100% hydrogen. In an existing power plant, executing this type of fuel switch may require an outage to remove the existing fuel system and replace with the new elements. Some liquid fuels, like methanol, have lower lubricity than light distillates. This can be an issue as some fuel systems are configured with pumps that use the inherent lubricity of the fuel to keep the system lubricated. Without this “natural” lubricity, an additive is required to maintain pump function. This additive can be injected into the fuel system, as shown in Figure 16.12, upstream of any fuel pumps that require this fuel characteristic. Some fuels, including some biofuels, may contain compounds that interact with coatings on hot gas path parts, potentially impacting part durability. When present in sufficient quantities, they may contribute to hot corrosion, and depending on the concentration in the fuel their presence may cause or potentially accelerate damage to parts. One such category are alkali metals (e.g., sodium and potassium). Most OEMs

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Figure 16.12  Methanol test fuel system. (Adapted from Weir et al., (1981)).

Figure 16.13  High-level schematic of a fuel treatment system for removing salts from liquid fuels.

limit these contaminants to very low levels; GE’s limit ranges from less than 0.2 ppm to less than 1 ppm depending on the type of gas turbine (GE Aviation, 2014; GE Gas Power, 2012). Siemens’ limit for some of their gas turbines is 0.5  ppm (Nag and Shoemaker, 2010). These salts can be removed from many fuels using commercially available water wash systems. Typically called fuel oil treatment plants, these commercially available systems mix the fuel with water and then spin the mixture to separate the liquids based their specific densities (see Figure 16.13). Since the salts are water soluble, they stay with the water. However, this system does not work with fuels whose specific densities are near unity, meaning that if water is mixed with the fuel the two fluids cannot be separated using centrifuge systems. In addition, this type of treatment system cannot be used with alcohols as they are water soluble. Therefore, if alkali salts are present in alcohol-based fuels, the contamination must be treated at the point of production.

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Figure 16.14  Example of field failure due to hydrogen embrittlement (reproduced from Goldmeer and Catillaz, 2021).

One final note on liquid fuel systems. Unlike true light distillates, due to the biological origin of biofuels they can suffer from additional issues. First, they have a limited shelf life, on the order of a few months. Guidance from the US Department of Energy’s National Renewable Energy Lab is that pure biodiesel (B100) should not be stored for more than four months, unless it has been treated to increase stability (Alleman et al., 2016). This may be partially resolved by adding fuel stabilizers that have the potential to increase shelf life especially the shelf life of diesel and biodiesel blends (Christensen and McCormick, 2014). A second issue is microbial contamination. If there is water contamination of the fuel, it is possible to have biological growth due to the presence of bacteria, fungus, and/or microorganisms. This issue can be mitigated using an appropriate biocide. There are also fuel system specific challenges when dealing with zero- and near-­ zero-carbon gaseous fuels. In addition to the potential need to increase piping size to deal with the additional fuel flow required, these gases have characteristics that prohibit the use of some standard gasket and sealing materials. A study by Pacific Northwest National Labs showed that some polymers when exposed to hydrogen see reduction in certain key physical characteristics and may also see some degree of physical degradation (Simmons et al., 2017). Similarly, not all elastomers are well suited for use with ammonia. Before using either of these fuels, a fuel system audit should be completed to ensure that any noncompatible seal, gasket materials, and any other components that may have these materials (i.e., valve seats) are replaced. One specific challenge for hydrogen is embrittlement. Due to its small size, hydrogen is able to diffuse into solid some materials, including some steel alloys. In this process, hydrogen diffuses to the grain boundaries in the alloys and interacts with the carbon forming microscopic methane bubbles (AMPP, 2021). This results in a disruption in the microscopic structures that might lead to degradation of material strength properties. Figures 16.14 and 16.15 show examples of embrittlement-based fatigue. A recommended solution to resolving this potential issue is the use of stainless steel alloys that offer increased embrittlement resistance. Sandia National Labs has noted that type 316 and 316L stainless steels are more compatible with hydrogen than

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Figure 16.15  Crack induced by hydrogen embrittlement (reproduced from Goldmeer and Catillaz, 2021).

other grades of stainless (Marchi, 2005). Detailed guidance is also available in codes and standard documents (ASME, 2020).

16.4.2

Fuel Systems: Fuel Classifications and Site Implications Fuel leaks have the potential to be especially dangerous situations if they generate a flammable mixture with air and if near electrical equipment with the potential to ignite the flammable mixture. Due to this risk, there are codes and standards applied to fuel systems to limit these risks. The National Fire Protection Association (NFPA) issues the National Electric Code (NEC) as well as other documents that provide a convention that segregates chemicals into classes, divisions, and groups based on certain characteristics (NFPA, 2021; Saini and Emma, 2007). NEC Article 500 provides the following definitions (NFPA, 2020): - Class 1 locations are those in which flammable gases or flammable liquid-produced vapors “are or may be present in the air in sufficient quantities to produce explosive or ignitable mixtures” - Class 2 locations where combustible dust could be present. - Class 3 locations have easily ignitable fibers or materials that can give off small bits of fiber that can float and transport a smoldering reaction or a small flame. Gas turbine power plants will include Class 1 locations due to the presence of variety of fuels. Class 1 also has groups that are defined by a set of parameters linked to the combustibility of the fuels, including the maximum experimental safe gap (MESG) which defines the smallest gap which prevents ignition of a flammable gas

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Table 16.7  National Electric Code Class, Division, and Group classifications relevant for hydrogen Classes

Class 1 divisions

Class 1 groups

1. Locations that could contain flammable gases or flammable liquid-­produced vapors. 2. Locations that could contain combustible dust. 3. Locations with easily ignitable fibers or materials that can give off small bits of fiber (flyers) that can float and transport a smoldering reaction or a small flame. 1. Locations in which ignitable concentrations of flammable gases or flammable liquid-produced vapors can exist under normal circumstances, or situations in which breakdown or faulty equipment or process might release ignitable concentrations of fuel 2. Locations in which flammable gases or flammable liquid-produced vapors will be normally confined within closed containers or closed spaces A. Acetylene B. Hydrogen (MESG ≤ 0.45 mm) C. Ethylene (MESG > 0.45 mm and ≤0.75 mm) D. Methane (natural gas), butane, propane, and fuel oil (MESG > 0.75 mm)

Table 16.8  NFPA and NEC Class 1 zone group classifications Group

Fuels

MESG criteria (mm)

IIA

Methane, propane, ammonia, and gasoline (roughly equivalent to NEC Class 1, Group D) Acetaldehyde and ethylene (roughly equivalent to NEC Class 1, Group C) Acetylene and hydrogen (roughly equivalent to NEC Class 1, Groups A and B)

Greater than 0.9

IIB IIC

Greater than 0.5 and less than 0.9 Less than 0.5

mixture under a specific set of controlled parameters. Table 16.7 summarizes these, as well as the divisions and groups within Class 1. There is also a definition of a combustible material zone based on fuel and the associated risks. In this classification system, Group II zones are defined as atmospheres that could contain a specific fuel as a flammable gas or vapor from a flammable liquid with a set MESG. Table 16.8 shows the fuel categories within Group II. In actual gas turbine operation, we regularly see fuels that are a combination of gases. Figure 16.16 shows the changes in MESG as a function of percent hydrogen in a fuel blend using the method outlined in Appendix B of NFPA (2021). From the chart it can be seen that Group IIA (MESG > 0.9 mm) allows fuels with up to ~25% (by volume) hydrogen. Research by Askar et al. (2016) showed that adding small amounts of hydrogen to natural gas reduces the MESG, but not enough to change classification, allowing these blends to stay within Group IIA. Increasing the hydrogen content beyond ~25% shifts the fuel to Group IIB. Blends with more than ~73.8% (by volume) hydrogen shift to Group IIC (MESG < 0.5 mm).

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Figure 16.16  Classification of hydrogen/natural gas fuel blends.

Once a fuel classification (based on the concentration of hydrogen to be used) is defined for a particular project, this may impact hazardous area classifications and classification of electrical systems needed for the existing and/or new fuel accessory hardware. For example, if working with hydrogen blends less than 25% (by volume), electrical equipment would only have to be rated for Group IIA environments, which are similar to natural gas. However, a 50% (by volume) blend would require equipment rated for Group IIB applications. To prevent the ignition of flammable vapors that might be present in the event of a fuel leak, the codes listed above define allowable mitigations that can be grouped into a few categories: avoid sparks, contain any potential explosion, limiting spark energies, and excluding flammable gases and vapors from ignition sources. Typical measures to satisfy these mitigation concepts include but are not limited to the use of explosion proof equipment, purging and pressurizing equipment systems, and the installation of combustible gas detection systems. The actual requirements may vary from project to project, and there could be additional local regulations and requirements. Before adding hydrogen to an existing or new power plant, the project should undergo a rigorous safety review. An example hazardous analysis for a hydrogen fueling station can be found in NREL’s Hydrogen Technologies Safety Guide (Rivkin et al., 2015). These NFPA and NEC codes also define zones of exclusion in which potential electrical discharges are not allowed to prevent ignition of vapors in case of a fuel leak. For hydrogen trailers, other gaseous hydrogen tanks, or other potential leak points outdoors and above grade when handling compressed flammable gases, this hazardous area is a 15 foot bubble in all directions. As an example, if adding the capability to operate a gas turbine on a blend of hydrogen and natural gas for a power project, one must consider these requirements when determining where to place fuel blending system and any hydrogen supply system. As previously stated, before adding hydrogen to an existing or new power plant, the project should undergo a rigorous safety review.

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Fuel Toxicity An issue particular to ammonia is fuel toxicity. It is classified at acutely toxic and can rapidly interact with available moisture in the skin, eyes, mouth, respiratory tract, and particularly mucous surfaces leading to chemical burns. The US National Institute for Occupational Safety and Health (NIOSH, 2019) defines the immediately dangerous to life or health (IDLH) limit for ammonia at 300 ppm, which is equivalent to 0.03%. Therefore, the use of ammonia as a gas turbine fuel will likely require changes to fuel accessory systems to mitigate this human health risk. One potential requirement when performing fuel system maintenance might be to purge with an inert gas (i.e., nitrogen) to ensure that there is no ammonia in the fuel lines. Other changes could include the installation of gas sensors targeted and detecting ammonia leaks.

16.4.4 Combustion The ability of gas turbine to operate safely and reliably on fuels that contain different constituents, that is, ammonia or hydrogen, requires a combustion system that can deal with the specific nature of these fuels. Challenges could include start-up, operational stability (i.e., combustion dynamics), emissions, hardware durability, etc. These challenges might require updated procedures, updated control software, and potentially new combustion hardware. For example, fuels that have a lower flammability limit that is higher than methane’s might cause ignition challenges. As shown in Table 16.1, ammonia’s lower limit is ~3.5 times higher than methane’s, which means that a higher concentration of fuel must be present for the gas turbine to be started. (It also has a lower flame speed, which has other implications for start-up.) The potential challenge in igniting an ammonia/air mixture creates additional risk if a failed (or false) start occurs since unburned ammonia will be present at a higher concentration in the combustor, and the nominal procedure in these situations is typically to purge the gas turbine before attempting a restart. This pushes the fuel (ammonia) out of the turbine and typically up and out of the exhaust stack. This process may have to change if using fuels with known toxicity issues. An additional challenge is that zero- and near-zero-carbon fuels may have flame speeds different from that of methane. Since flame speed is a surrogate for fuel reactivity, fuels with lower flame speeds may be harder to ignite (i.e., ammonia). This might require changes to the current ignition system. Fuels like hydrogen that have much higher flame speeds and increased reactivities may pose other challenges. Since flames try to propagate upstream into the unburned fuel at a velocity defined by the flame speed, using fuels with higher flame speeds increases the risk that the flame could propagate upstream into the premixer. If the flame enters the premixer, is not able to stabilize, and then is pushed back into the main combustion zone, this is known as flashback. Flame holding occurs when the flame is able to anchor itself and stays within the premixer. Both situations can lead to combustion hardware distress and even fuel nozzle damage. Figure 16.17 illustrates an example of damage caused by a flame holding event on a fuel nozzle.

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Figure 16.17  Gas turbine fuel nozzle damage from a flame holding event (reproduced from Goldmeer and Catillaz, 2021).

Therefore, having the correct combustion system for a given fuel is critical. Not all combustion systems are configured to operate with hydrogen and some combustion systems have hydrogen limits defined by the OEM. Therefore, when considering the concentration of hydrogen to use in a given situation, one must take the gas turbine and the hydrogen capability of the combustion system into account. The good news is that most gas turbine OEMs have two combustion system configurations available on most models: diffusion and (lean) premix. Although (lean) premixed systems have lower limits on hydrogen capability, diffusion combustion systems tend to have much higher capability. Most gas turbines operating today are configured with (lean) premix combustion systems that operate with aerodynamically stabilized flames in the lean region of the chart (equivalence ratio less than one) shown in Figure 16.18. In this regime, flame temperature is reduced, which lowers NOx emissions. These combustion systems are typically known as dry-low emissions or dry-low NOx. They are typically limited in the amount of hydrogen than can be utilized due to risks of flashback and flame holding. Some newer premix combustion systems have taken a different approach to fuel injection and can handle increased levels of hydrogen (Goldmeer, 2020). Diffusion combustion systems are able to operate with higher concentrations of hydrogen due to their configuration and operating regime. These systems operate at or near-stoichiometric conditions, which enables stable operation on a variety of fuels. The trade-off is that operating at a near unity equivalence ratio leads to very high flame temperatures and as a result higher (gas turbine) NOx emission. These combustion systems typically use a diluent such as water, steam, or nitrogen injected into the combustor to reduce NOx emissions. An advantage to having different combustion systems is the ability to upgrade the gas turbine as the needs of the power plant evolve. A power plant configured with a premix combustion system today could be upgraded to a diffusion combustor to allow operation on fuels with increased levels of hydrogen. Power plants configured with current premix combustion systems have the capability to be upgraded to newer combustion systems in the future. The major gas turbine OEMs already offer this type of service to allow power plant owners and operators to upgrade existing units to

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Figure 16.18  Diffusion versus premixed combustion (reproduced from Goldmeer and Catillaz, 2021).

improve performance. The ability to upgrade combustion systems will be important as the various gas turbine OEMs develop and release combustion systems capable of operating on higher levels of hydrogen. As fuels like hydrogen become more available and affordable, gas turbines could be upgraded to operate on these fuels and reduce their carbon emissions.

16.4.5

Balance of Plant: HRSG, SCR, and NOx Emissions The addition of hydrogen may potentially impact the heat recovery steam generator (HRSG) found in combined cycle plants. For example, conventional duct burners or supplemental burners (located in the HRSG) may not be configured for operation on fuels with hydrogen and may need to be upgraded to be capable of operating with hydrogen in a safe and/or reliable manner. There are concerns that in the event of loss of flame in the combustor that a flammable mixture could enter the HRSG and potentially ignite. This was studied with initial findings reported by Hawksworth (2016). There are also potential concerns when operating on hydrogen/natural gas blends if there are contaminants in the natural gas. As noted by Davis et al. (1993) and Decoussemaeker (2014), if there is sulfur in the natural gas and if the temperature in the HRSG drops below the dew point of the gas, there is a potential to form and condense sulfuric acid which can corrode metals in the system. In addition to corrosion, sulfur-based compounds can leave deposits on cold surfaces leading to reduced heat transfer rates (Fabricus et al., 2020). This can typically be resolved by configuring the HRSG to maintain temperatures above the exhaust gas dew point. An additional concern raised by some is the increased level of moisture that would be present from the combustion of a high hydrogen fuel and potential impact on the HRSG (if present). Since hydrogen produces water vapor as a combustion product, the level of moisture in the combustor exhaust increases with increasing concentrations of hydrogen in the fuel.

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The good news is that are already examples of gas turbines operating with a higher exhaust gas moisture concentration, some above the level that would be present from combusting hydrogen. These are units that operate on distillate fuel oil and use water injection to maintain NOx levels within regulatory limits, which are typically about 42 parts per million. For these units, depending on how much water is required to meet NOx emissions, the water content in the gas turbine exhaust could be as much as ~30 to 40% larger than moisture content when operating on natural gas. In comparison, the water content for a 50/50 (by volume) blend of natural gas and hydrogen might be 10 to 15% larger than the natural gas baseline. Thus, there are already HRSG systems in operation that may have experienced the same or higher gas turbine exhaust moisture content that may be encountered when operating on hydrogen fuels. One impact not often considered in switching fuels in an existing power plant are emissions, including nitric oxides (NOx). Some zero- or near-zero-carbon fuels burn at a higher temperature or carry a significant amount of nitrogen which has the potential to increase NOx emissions from the power plant. Most power plants have an operation permit (aka air permit) approved by local, state, or provincial regulatory agencies that limit how much of any criteria pollutant can be emitted. Therefore, when considering switching fuels, understanding the impact to emissions is critical as regulatory agencies typically do not allow for increased emissions. In addition, if a change to an air permit is requested to allow higher NOx emissions, regulators could request that the power plant comply with new regulations that went into effect after the air permit was issued. Therefore, plant operators typically want to stay within compliance for their existing emission limits. There are a number of options today for dealing with increased NOx emissions, depending on the type and status of a power plant. For power plants that are in development, one could choose to size a NOx treatment system to reduce the maximum potential levels from the gas turbine to acceptable or regulated limits. These systems are sometimes called de-NOx systems or selective SCR systems. For existing power plants that already have NOx emissions aftertreatment systems, there are steps that could be taken to reduce NOx emissions. For power plants with ammonia-based emissions after treatment systems, the ammonia injection rate could be increased to enhance the NOx to N2 reaction. It might also be possible to replace the existing catalyst with a newer catalyst that has a higher efficiency (conversion rate). If these steps are not sufficient, the gas turbine could also be derated. In the future, the gas turbine OEMs may provide combustion technology that is capable of burning these fuels without impacting NOx emissions (relative to today’s natural gas emission requirements). However, there are limits as some fuels have large amount of intrinsic nitrogen. For example, ammonia is 83% nitrogen by mass. Using currently available gas turbine combustion systems, this nitrogen is converted to NOx at very high rates (see Figure 16.19). This has the effect of increasing NOx emissions by more than a factor of 100. NOx aftertreatment systems already installed on power plants are likely not configured to deal with the very large increase in the absolute amount of NOx being produced. That being said, there are a number of institutions engaged in research to develop new combustor configurations that produce lower NOx emissions when

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Figure 16.19  Impact of ammonia blends on premix combustor NOx emissions (­Courtesy: GE Gas Power).

operating on ammonia (Shintaro et al., 2020; Valera-Medina et al., 2020; Hussein et al., 2019).

16.4.6

Balance of Plant: Safety Switching to zero- or near-zero-carbon fuels can impact power plant systems beyond the gas turbine. One key element to consider are fuel changes that could impact plant safety systems. For example, hydrogen is more flammable than methane; hydrogen’s upper explosion limit is ~75% compared to methane at ~15%. Therefore, hydrogen leaks could create increased safety risks requiring changes to plant procedures, safety/ exclusions zones, etc. Hydrogen’s expanded flammability limit has the potential to allow for flammable mixtures to be present for much higher concentrations of fuel. This creates a need to increase the ventilation flow around the combustor in the gas turbine enclosure. By increasing the ventilation flow, this reduces a potential risk of having a flammable mixture. If there are fuel leaks, it becomes important to detect these as soon as possible. Typical hazardous gas detection systems in power plants are targeted at hydrocarbon fuels. Increased levels of hydrogen can reduce the sensitivity of these instruments requiring new systems capable of detecting the presence of hydrogen. In addition, hydrogen flames have lower luminosity than hydrocarbon flames and are therefore hard to detect visually as shown in Figure 16.20. This requires flame detection systems specifically configured for hydrogen flames. Therefore, the use of hydrogen may require the installation of sensors and instrumentation specifically configured for fuels containing hydrogen. Another key consideration is the impact of fuel on power plant personnel if exposed either during routine maintenance or if a fuel leak were to occur. For example, ammonia that contains zero carbon is highly toxic. The United States National Institute for Occupational Safety and Health (NIOSH) has set the permissible exposure limit to ammonia at 25  ppm based on an eight hour weighted average. An exposure of

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Figure 16.20  Comparison of natural gas and hydrogen flames (reproduced from Goldmeer and Catillaz, 2021).

300 ppm of ammonia is categorized as an IDLH1 (Pocket Guide to Chemical Hazards, NIOSH). However, ammonia has a low odor threshold (20 ppm), so most people will smell ammonia at concentrations less than critical thresholds. The use of ammonia or other fuels that could have serious and potentially lethal impact on power plant personnel requires different safety protocols and plant configurations. For example, fuel systems may be required to have an inert purge (i.e., nitrogen) and/or block and bleed systems to ensure that during maintenance all fuel lines are drained of any fuel. Regardless of the fuel, before formalizing any plan introduce a zero- or near-­­zerocarbon fuel into a new or existing gas turbine, a full audit of plant systems should be performed with support of the OEM with a goal of developing a plan for safe operation.

References Albioma (2019) Albioma, Reunion Island, Saint-Pierre Power Plant. www.albioma.com/en/site/ reunion-island/saint-pierre/ Alleman, T., McCormick, R., Christensen, E., Fioroni, G., Moriarty, K., and Yanowitz, J. (2016) Biodiesel Handling and Use Guide (Fifth Edition), US Department of Energy, DOE/ GO-102016-4875. Ansaldo Energia (2021) Ansaldo Energia solutions for hydrogen combustion: fast-forward to a hydrogen fueled future. www.ansaldoenergia.com/PublishingImages/Idrogeno/Ansaldo Energia Solutions For Hydrogen Combustion.pdf Askar, E., Schröder, V., Schűtz, S., and Seemann, A. (2016) “Power-to-gas: Safety characteristics of hydrogen/natural gas mixtures,” Chemical Engineering Transactions, 48, 397–402. ASME (2020) “Hydrogen Piping and Pipelines” B31.21-2019. AMPP (Association for Materials Protection and Performance) (2021), Hydrogen embrittlement. https://nace.org/resources/what-is-corrosion/forms-of-corrosion - embrittlement Baker Hughes (2019) “BHGE Roadmap to the future of power generation,” 2019 Renewable Power to Clean Fuels Symposium, Portland. www.renewableh2.org/wp-content/ uploads/2019/05/09-Egidio-Pucci-BHGE-Slides.pdf

1

IDLH limits are defined as concentrations that pose an immediate threat to life or that would cause irreversible or delayed health effects or that would interfere with an individual’s ability to escape from a dangerous environment.

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Balestri, M. Sigali, S., Cocchi, S., and Provenazle, M. (2008) “Low-NOx hydrogen fueled GT features and environmental performances,” Power-Gen Europe, 2008. Brunetti, I., Rossi, N., Sigali, S., Sonato, G., Cocchi, S., and Modi, R. (2010) “ENEL’s Fusina zero emission combined cycle: experiencing hydrogen combustion,” Power-Gen Europe, 2010. http://b-dig.iie.org.mx/BibDig2/P11-0252/Track 2/Session 5/brunetti_iarno.pdf Burke, J. (2021), “GE announces another hydrogen demonstration project” Diesel & Gas Turbine Worldwide, www.dieselgasturbine.com/news/ge-announces-another-hydrogendemonstration-project/8013622.article. Business Wire (2015), “GE’s Fuel Flex Technology Helps CEPSA Enable Spain’s Oil Refinery to Meet Strict European Emissions Standards.” www.businesswire.com/news/ home/20150518005257/en/GE%E2%80%99s-Fuel-Flex-Technology-Helps-CEPSA-­ Enable-Spain%E2%80%99s-Oil-Refinery-to-Meet-Strict-European-Emissions-Standards Campbell, A., Goldmeer, J., Healy, T., Washam, R., Moliere, M., Citeno, J. (2008) “Heavy Duty Gas Turbines Fuel Flexibility,” TurboExpo 2008, GT2008–51368, Berlin, Germany. Christensen, E., and McCormick, R. (2014) “Long-term storage stability of biodiesel and biodiesel blends,” Fuel Processing Technology, 128, 339–348. Clarion Energy Content Directors (2020) “MHPS wins CCGT award for Utah coal-gas-­ hydrogen long-term transition project,” Power Engineering, www.power-eng.com/gas/ mhps-wins-ccgt-award-for-utah-coal-gas-hydrogen-long-term-transition-project/#gref. Clemson News (2020), “Siemens Energy teams up with Duke Energy, Clemson University to study hydrogen use.” https://news.clemson.edu/siemens-energy-teams-up-with-duke-energyclemson-university-to-study-hydrogen-use/ Cocchi, A., Provenzale, M., Cinti, V., Carrai, L., Sigali, S., Cappetti, D. (2008) “Experimental characterization of a hydrogen fuelled combustor with reduced NOx emissions for a 10 MW class gas turbine,” ASME TurboExpo 2008, GT2008-51271. Cornu, L., and Svensson, A. (2011) “Performance improvements in GE’s 9FB gas turbine: Field testing at E.ON’s Oresundsverket CHP plant,” PowerGen Europe 2012, Cologne, Germany. Day, W. (2016) “Methanol fuel in commercial operation on land and sea,”in Bruno DeBiasi (ed), Gas Turbine World, pp. 16–21. Pequot Publishing. Davis, J., Steffen, M., and Thompson, A. (1993) “Large Combined Cycle HRSG Units Impact of Operating Considerations,” TurboExpo 1993, 93-GT-229. Decoussemaeker, P., Bauver, W. P., Gabrielli, F., Rigoni, L., Cinquegrani, L., Epis, G., and Donghi, M. E. (2014) “Review of HRSG Capabilities for Flexible Operation,” 7th International Gas Turbine Conference, Paper #14, Brussels, Belgium. Dicampli, J., Madrigal, L., Pastecki, P., and Schornick, J. (2012) “Aeroderivative power generation with coke oven gas,” Proceedings of the ASME 2012 International Mechanical Engineering Congress & Exhibition, IMECE2012-89601. DiCampli, J. (2013) “Aeroderivative Gas Turbine Fuel Flexibility,” Power Engineering, www .power-eng.com/coal/aeroderivative-gas-turbine-fuel-flexibility/. Enel (2009), “ENEL: First hydrogen-fuelled power now on line Venice.” Power, www.powermag .com/enel-inaugurates-worlds-first-hydrogen-fueled-power-plant/#:~:text=Italy%27s%20 Enel%20on%20Monday%20inaugurated,electricity%20as%20well%20as%20heat. Fabricus, A., Malloy, J., Taylor, M., Jackson, P., and Moelling, D. (2020) “HRSG Fleet Integrity Management: Lessons Learned from the Field,” Proceedings of the ASME 2020 Power Conference, POWER2020-16890. GE Aviation (2014) Liquid fuel requirements for GE Aero Derivative Gas Turbines, MID-TD-0000-2. GE Gas Power (2012) Heavy Duty Gas Turbine Liquid Fuel Specifications, GE41047(p).

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Goldmeer, J., and Catillaz, J. (2021) Hydrogen as a fuel for gas turbines, GE Gas Power, GEA34805. Goldmeer, J., and Rozas, T. (2013) “Burning a mixture of H2 and natural gas,” Turbomachinery International, 24. www.turbomachinerymag.com/view/burning-a-mixture-of-h2and-natural-gas Goldmeer, J. (2020) “Hydrogen combustion – solving the challenge of lean premix combustion with highly reactive fuels,” Turbomachinery International, 2–5. www.turbomachinery mag.com/view/solving-the-challenge-of-lean-hydrogen-premix-combustion-with-highlyreactive-fuels Hall, J., Thatcher, R., Koshevers, S., Thomas L., and Jones, R. (2011) “Development and field validation of a large-frame gas turbine power train for steel mill gases,” ASME TurboExpo, GT2011-45923. Hamilton, R., Minervino, O., and KV, N. (2018) Next Generation Fuel Firing Combustion Technology for Gas Turbines,” Electrify Europe. Hawksworth, S. (2016) “Safe Operation of Combined Cycle Gas Turbine and Gas Engine Systems using Hydrogen Rich Fuels,” EVI-GTI and PIWG Joint Conference on Gas Turbine Instrumentation. Hussein, N., Valera-Medina, A., and Alsaegh, A. (2019) “Ammonia-hydrogen combustion in a swirl burner with reduction of NOx emissions,” Energy Procedia, 158, 2305–2310. Ito, S., Uchida, M., Onishi, S., Fujimori, T., and Kobayashi, H. (2018) “Performance of Ammonia-Natural Gas Co-Fired Turbine for Power Generation,” AiChE Annual Meeting. Jones, R., and Goldmeer, J. (2012) Gas Turbine Fuel Flexibility: An Enabler for New Regional Power Generation, PowerGen Europe, Germany. Jones, R., Goldmeer, J., and Monetti, B. (2011) “Addressing Gas Turbine Fuel Flexibility,” GER4601, GE Gas Power. Komori, T., Shiozaki, S., Yamagami, N., Kitauchi, Y., and Akizuki, W. (2007) “CO2 Emission Reduction Method Through Various Gas Turbine Fuel Applications,” Mitsubishi Heavy Industries, Ltd., Technical Review, vol 44 (1). Marchi, C. (2005) “Technical Reference on Hydrogen Compatibility of Materials – Austenitic Stainless Steels: Type 316 (Code 2013)” Sandia National Laboratories. Mitsubishi Power (2021) Meet JAC. www.changeinpower.com/our-solutions/decarbonizingpower/advanced-class-gas-turbines/ Modern Power Systems (2020) “Japan claims world first: DLN gas turbine combustors verified on 100% hydrogen. www.modernpowersystems.com/features/featurejapan-claims-worldfirst-dln-gas-turbine-combustors-verified-on-100-hydrogen-8185077/ Moliere, M., and Hugonnet, N. (2004) Hydrogen-Fueled Gas Turbines: Experience and Prospects, Power-Gen Asia. Moliere, M., Panarotto, E., Aboujaib, M., Bisseaud, J. M., Campbell, A., Citeno, J., Maire, P. A., and Ducrest, L. (2007) “Gas Turbines in Alternative Fuel Applications, Biodiesel Field Test,” ASME TurboExpo, GT2007-27212, Montreal, Canada. Moliere, M., Vierling, M., Aboujaib, M., Patil, P., Eranki, A., Campbell, A., Trivedi, R., Nainani, A., Roy, S., and Pandey, N. (2009) “Gas Turbines in Alternative Fuel Applications: Bio-Ethanol Field Test,” ASME TurboExpo, GT2009-59047, Orlando, FL. Nag, P., and Shoemaker, F. (2010) “Fuel Flexibility of Siemens’ Gas Turbines,” 30th Energy Buyer’s Conference, Miami, FL. NETL (National Energy Technology Laboratory) (2021) IGCC Project Examples. https://netl .doe.gov/research/coal/energy-systems/gasification/gasifipedia/project-examples NFPA (2020) “NFPA 70, National Electric Code,” National Fire Protection Association.

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NFPA (2021) “NFPA 497 – Recommended Practice for the Classification of Flammable Liquids, Gases, or Vapors and of Hazardous (Classified) Locations for Electrical Installations in Chemical Process Areas,” National Fire Protection Association. NIOSH (2019) Pocket Guide to Hazardous Chemicals. NY State Governor’s Office (2020) “Governor Cuomo Announces New York Will Explore Potential Role of Green Hydrogen as Part of Comprehensive Decarbonization Strategy.” www.nyserda.ny.gov/About/Newsroom/2021-Announcements/2021-07-08-Governor-Cuomo-Announces-New-York-Will-Explore-Potential-Role-of-Green-Hydrogen Patel, S. (2020) “GE Secures First HA-Class Hydrogen Gas Power Deal: Long Ridge Energy Terminal,” Power. www.powermag.com/ge-secures-first-ha-class-hydrogen-gaspower-deal-long-ridge-energy-terminal/ Patel, S. (2021) “Mitsubishi Power Developing 100% Ammonia-Capable Gas Turbine,” Power. Payrhuber, K., Jones, R., and Scholz, M. (2008) “Gas turbine flexibility with carbon constrained fuels” TurboExpo 2008, GT2008–50556, Berlin, Germany. Power Engineering International (2010) “Fusina: Achieving low NOx from h­ ydrogen combined cycle plant.” www.powerengineeringint.com/world-regions/europe/fusina-achievinglow-nox-from-hydrogen-combined-cycle-power/ Power Technology (2010) “Ethanol Power Plant, Minas Gerais.” www.renewable-technology .com/projects/ethanol-power-plant-minas-gerais/ Rivkin, C., Burgess, R., and Buttner, W., (2015) Hydrogen Technologies Safety Guide, National Renewable Energy Lab, US Department of Energy, NREL/TP-5400-60948. Solar Turbines (2021a) Converting High Hydrogen Fuel To Electricity. www.solarturbines.com/ en_US/about-us/news-and-press-releases/converting-high-hydrogen-fuel-to-electricity.html Solar Turbines (2021b) Power From Hydrogen Gas For Carbon Reduction. www.solarturbines .com/en_US/solutions/carbon-reduction/hydrogen.html Saini, R., and Emma, C. (2007) “Practical guidelines for determining electrical area classification,” Power (online). www.powermag.com/practical-guidelines-for-determining-electricalarea-classification/ Shintaro, I., Masahiro, U., Toshiyuki, S., and Toshiro, F. (2020) “Development of ammonia gas turbine co-generation technology,” IHI Engineering Review, 53(1), 1–6. Siemens Gas and Power GmbH & Co. (2020) Hydrogen power with Siemens gas turbines. Simmons, K., Bhamidipaty, K., Menon, N., Smith, B., Naskar, A., and Veenstra, M. (2017) “Compatibility of Polymeric Materials Used in the Hydrogen Infrastructure,” Pacific Northwest National Laboratory, PNNL-SA-125790. Todd, D. (2000) “Gas turbine improvements enhance IGCC viability,” 2000 Gasification Technologies Conference, San Francisco, CA. Valera-Medina, A., Amer-Hatem, F., Azad, A.K., Dedoussi, I.C., De Joannon, M., Fernandes, R.X., Glarborg, P., Hashemi, H., He, X., Mashruk, S., and McGowan, J. (2021). “Review on ammonia as a potential fuel: from synthesis to economics,” Energy & Fuels, 35(9), 6964–7029. von KleinSmid, W., Schreiber, H., and Klapatch, R. (1981) “Methanol Combustion in a 26-MW Gas Turbine,” ASME Gas Turbine Conference & Products Show, Houston, Texas. Walton, R. (2021) “GE turbine selected for H2, gas-fired Tallawarra plant in Australia,” Power Engineering. Weir A., von KleinSmid, W., and Danko, E. (1981) “Test and Evaluation of Methanol in a Gas Turbine System,” Research Project 988-1, Electric Power Research Institute. Yilmaz, E. (2020) “HyFlexPower – Power-H2-Power Pilot CO2-Free Green Energy with H2 GT,” Flexible Power Generation ETN Webinar Series.

17 Hydrogen Solutions for Net-Zero Power Generation Michael J. Ducker

17.1 Introduction The global push for economy-wide decarbonization is fueling intense interest in the potential of hydrogen as a zero-carbon resource. Long coveted as a fuel of the future, hydrogen already is being used in a variety of applications to cut carbon emissions across the globe. Hydrogen can be used in a wide range of applications, many of which have proved hard to decarbonize via other methods. One key application being advanced at Mitsubishi Power, a solutions brand of Mitsubishi Heavy Industries, is the use of hydrogen in gas turbines to produce electricity. When hydrogen is combined with air and used in a gas turbine to generate electricity, the by-product is water vapor; no carbon emissions are created in the process. And, when green hydrogen – produced from 100% renewable sources – is used to fuel a gas turbine, the result is zero-carbon emissions. Importantly, existing infrastructure often can be used with hydrogen, including the already established natural gas pipeline system as well as some types of natural gas turbine generating stations. Currently, Mitsubishi Power’s largest and most advanced gas turbines make use of a dry low-NOx (DLN) combustion system that allows operation with up to 30% hydrogen in baseline configuration. Going forward, increasing the use of hydrogen as a percentage of a power station’s fuel mix – from a mixture of around 30% hydrogen all the way up to 100% hydrogen as an energy source – requires the need for innovative equipment modifications. And those innovations already can be found in Mitsubishi Power’s newest multi-cluster combustor, which will deliver high-efficiency hydrogen combustion. What’s more, gas turbines running on green hydrogen as a form of long-duration energy storage can offer essential grid support to bolster the intermittent nature of renewables, making this technology integral to the energy transition. The evolution to a clean energy grid will require generating resources that are dispatchable and energy storage resources with long-term, even seasonal, capabilities – such as hydrogen.

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Getting to Green The convergence of decarbonization goals, increasing penetration of renewable energy resources, and the threat of climate-induced changes to the planet all favor the deployment of a clean hydrogen solution, both as a long-duration energy storage medium as well as a low-carbon fuel for hard to decarbonize sectors. The use of stored clean hydrogen will help to compensate for output fluctuations from wind and solar generation. While battery and other storage technologies are effective solutions for a short-term supply/demand adjustment, cost and technical issues remain when adjusting to large-scale supply/demand imbalance due to season and location. Hydrogen’s ability to be stored and transported in large scale solves the need for long-term adjustment – a key reason that countries are now considering the potential for hydrogen as a prime decarbonization solution.

17.2.1

Creating Clean Hydrogen Hydrogen is the most abundant element in the universe. Yet, it does not exist freely in nature and is only produced from other sources of energy, meaning that it is an energy carrier. Due to its versatility, hydrogen has been a global commodity for decades, and a well-established and robust industry exists in the US for its production. Used primarily as an input for oil refining, ammonia production and methanol production, hydrogen has a global demand on the order of 70 million metric tons annually. Four main processes currently are used to produce hydrogen – thermal, electrolytic, solar-driven, and biological. See Chapter 5 for more information about hydrogen and its production. Most hydrogen today is produced by applying energy from natural gas or other hydrocarbon fuels to separate it from other elements. The production of this “gray hydrogen” generates significant carbon emissions. To reduce those atmospheric greenhouse gas emissions, so-called “blue hydrogen” adds carbon capture and storage technology. For a greatly reduced carbon footprint throughout the production value chain, “green hydrogen” can be created using renewable energy sources. For example, electricity that is generated by wind turbines, for instance during the night when demand is low, may be used to drive electrolysis to create hydrogen. Large-scale electrolysis systems have been in use since the 1940s, and according to the Green Hydrogen Coalition (Nelson, 2020), electrolysis cells may readily be stacked and used for commercial green hydrogen production when connected to wind farms, solar plants, or other renewable electricity sources. Electrolyzers interconnect to the grid in much the same way as solar or energy storage systems with AC/DC converters. They operate with a fast response time and can provide flexible load to the grid, including important ancillary services such as voltage support and frequency regulation.

17.2.2

Leveraging Existing Infrastructure Hydrogen pipelines are prevalent today in the Gulf Coast region of the US (Gillette and Kolpa, 2007). Additionally, many studies have estimated that between 5% and

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15% hydrogen by volume can be safely blended into existing natural gas pipelines (Melaina, Antonia and Penev, 2013). Upgrades to the pipeline infrastructure will be needed to transport a greater percentage of hydrogen – up to 100% – without affecting the overall integrity of the natural gas pipeline network. Limitations on the level of hydrogen in the current natural gas pipeline arise for a number of reasons, including hydrogen embrittlement of iron and steel piping, improperly sized compression stations for a high-volume gas like hydrogen, and the integrity of seals and valves against a high diffusivity gas like hydrogen. Further, while power generation stations driven by gas turbines typically can operate with hydrogen concentrations higher than the 15% limit, natural gas is used ubiquitously in many other devices that may not be compatible with hydrogen, like household water heaters and stoves. Today’s DLN gas turbine power plants are being designed with the ability to operate on up to 30%-volume hydrogen blended with natural gas, and additional technology will enable operation on 100% hydrogen by 2030, if not sooner. Hydrogen gas turbines also can operate in combined-cycle applications – where excess heat is put to use to power a steam turbine – to deliver even greater power plant efficiency.

17.2.3

Storing Hydrogen, Stabilizing the Grid To meet increasingly ambitious low-carbon, clean energy targets, significant long-term energy storage as well as dispatchable zero-carbon resources will be critical. The yearly energy trends in Figure 17.1 support this need. Figure 17.1a shows the curtailment of wind and solar power on a monthly basis, or the level that these sources must be reduced to match demand on the grid or limitations on transmission capacity. Throughout the year, significant amounts of renewable energy are available for storage. Similarly, Figure 17.1b shows the surplus and deficit levels of these renewable sources in a 100% renewable scenario in California. Not only do several months show significant surplus that could be stored, but there also are several months in a row with a deficit, revealing the pressing need for long-term energy storage. Fortunately, hydrogen can be readily stored, most commonly in mechanical pressure vessels or geologic formations. One forward-thinking geologic storage scenario involves producing vast quantities of green hydrogen using months of excess wind and solar resources, then storing the hydrogen in impermeable salt caverns – which have been used for hydrogen storage since the 1980s – until it ultimately is put to use in gas turbines to generate reliable, dispatchable energy during months of renewable energy deficits. In this way, stored hydrogen could meet the need for long-duration storage – not easily met by lithium-­ ion batteries, for instance – to reliably support a high renewable system. In a 2020 analytical report (Energy and Environmental Economics, Inc., 2020), consulting firm E3 said that the most promising and realistic opportunity for carbon-­ neutral green hydrogen is as long-duration energy storage for the electricity sector in an increasingly deeply decarbonized western US. In this scenario, green hydrogen could provide valuable firm generation capacity and long-duration energy storage. The relatively low cost of hydrogen storage in geologic formations would allow large amounts of energy to be stored in the form of hydrogen and used for seasonal

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(b) Figure 17.1  Monthly wind and solar curtailments (a) and daily surplus and deficit energy (b) in

California signal the need for more storage options (reproduced from Armond Cohen congressional testimony – “Building America’s Clean Future: Pathways to Decarbonize the Economy”).

Figure 17.2  Example hydrogen facility for power plant supply.

shifting of energy. This would be particularly useful in providing firm zero-carbon electricity during multiday periods with low wind and solar power generation. What’s more, the ability to use hydrogen in existing gas turbine power plants and to transport it in existing natural gas pipelines would be useful in reducing total system costs and easing the coming transition away from carbon-intensive forms of generation. In addition, the study found that locations with underground storage may serve as cost-effective energy “hubs.” These hubs would provide green hydrogen to locations without energy storage. Then, producing green hydrogen using zero-carbon electricity, using centralized geologic hydrogen storage along with a network of hydrogen pipelines, would be more cost-effective than building a decentralized system with hydrogen storage at each end user’s site. An example site for hydrogen production and storage is shown in Figure 17.2.

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17.2.4

A Multi-Pronged Approach A multi-pronged approach that uses renewables to create clean hydrogen, leverages existing natural gas pipeline and power plant infrastructure, and introduces new hydrogen storage capability offers a tremendous opportunity to deliver carbon-free, dispatchable energy in the power industry. And, based on decades of experience creating hydrogen gas turbines, Mitsubishi Power is collaborating with others to deliver just such a comprehensive solution.

17.3

Mitsubishi Power’s Hydrogen History Mitsubishi Power started its gas-turbine business in the 1960s and since has accumulated deep expertise in hydrogen combustion technology with more than 3.5 million hours of high-hydrogen operating experience accumulated over 50 years and more than two dozen facilities. This experience covers a variety of projects – including coal-based integrated gasification combined cycle (IGCC) and cogeneration applications – running on a variety of different fuel types such as syngas, coke oil gas, refinery gas, and blast furnace gas. The progression of Mitsubishi Power combustor technologies is shown in Figure 17.3. Back in the early 1970s, Mitsubishi Power began developing diffusion-flame combustor technology for its hydrogen-burning engines. Driven by a desire to make use of often flared coke oven and blast furnace gases – by-products of the iron and steel manufacturing process – this technology allowed these hydrogen-rich by-product gases to be put to use, significantly cutting fuel costs for industrial plant operators around the globe. The diffusion combustors require the injection of diluents such as water, steam, or nitrogen – a so-called “wet control” method – to reduce NOx emissions while burning up to 100% hydrogen. Still in use decades later, these fuel-flexible gas turbines sacrifice plant efficiency to suppress NOx emissions (Asai et al., 2016). Mitsubishi Power’s research efforts into hydrogen were motivated further by Japan’s desire to reduce its dependence on imported fossil fuels. As climate change concerns have grown, decarbonization goals have accelerated the company’s hydrogen development activities, resulting in Mitsubishi Power’s two next generations of high-efficiency hydrogen combustion systems for its largest and most advanced gas turbines.

17.3.1

First Generation The development of Mitsubishi Power’s first generation of gas turbines sporting high-efficiency pre-mixed combustion systems began in the early 1980s. And its latest G and J Class gas turbines take DLN natural gas combustion technology, shown in Figure 17.4, even further. Fueled with a mixture of up to 30% hydrogen and 70% natural gas by volume, these systems produce similar NOx and 10% less CO2 emissions than those from modern natural gas power plants. For example, Mitsubishi

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Figure 17.3  Progression of combustor technologies and the levels of hydrogen compatible with these technologies.

Figure 17.4  Mitsubishi Power’s pre-mixed DLN combustor can operate on fuel mixtures with up to 30% hydrogen.

Power’s hydrogen-capable enhanced J Class air-cooled gas turbine – the M501JAC – offers combined cycle efficiency greater than 64%, reliability of 99.6%, and output of 435 MW (for 60 Hz applications). Based on deep understanding of hydrogen’s combustion characteristics, Mitsubishi Power’s engineers overcame flashback, thermoacoustic combustion instability, and NOx emission obstacles in the development of the premixed DLN combustor that allows gas turbine operation on a 30% hydrogen fuel mix. The combustor development considered a number of factors – from optimization of the shape and material of the fuel nozzle and the combustor shape and material to the quality of the thermal insulation ceramic coating. Flashback propensity was reduced by designing a high-­ velocity region along the centerline of the swirler nozzle, and instability suppression was achieved through installation of acoustic dampers. In addition, fuel flexibility is

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Figure 17.5  Mitsubishi Power’s multi-cluster combustor technology will allow gas turbine operation on 100% hydrogen (reproduced courtesy of E. Petersen).

one of the most important features for DLN combustors to meet the requirement of the gas turbine market. Mitsubishi Power demonstrated DLN combustor fuel flexibility with natural gas fuels that have a large Wobbe Index variation, a hydrogen–natural gas mixture, and crude oils (Tada et al., 2018). These hydrogen-capable turbines rely on technological advances made over the years, like Mitsubishi Power’s development of multiple-injection combustor technology designed to achieve the dry low-NOx combustion of hydrogen-rich syngas at an IGCC pilot plant (Asai et al., 2015). Test results from the pilot project indicated that an advanced fuel staging comprising a hybrid partial combustion mode improved the combustor’s part load performance when running on syngas fuel that contained approximately 50% carbon monoxide, 20% hydrogen, and 20% nitrogen by volume.

17.3.2

Second Generation To achieve 100% green hydrogen powering, a second-generation combustion system that uses a “multi-cluster” combustor technology derived from Mitsubishi Heavy Industries’ (MHI) heavy launch rocket division is in development. With higher hydrogen concentrations, the risk of flashback rises, as does the potential concentration of NOx. Because the combustor must enable efficient mixing of hydrogen and air as well as provide stable combustion, Mitsubishi Power has developed a solution to disperse the flame. The new distributed lean-burning, multi-cluster combustor technology incorporates multiple upgraded fuel delivery nozzles with smaller sized openings. The system mixes injected air and hydrogen, without using a swirler nozzle, making the mixing possible on a small scale and allowing for low-NOx combustion, as shown in Figure 17.5. Several multi-cluster combustors, each consisting of multiple cluster burners in a can-type cylindrical liner and casing, are radially mounted at an angle to the compressor section casing to provide an advanced DLN combustion solution for hydrogen-rich fuels. These systems achieve similar efficiencies, power outputs, and NOx levels as current DLN technologies with zero-carbon emissions.

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In addition to the changes to the combustion system, minimal modifications to the fuel handling, gas detection, fire protection, and ventilation systems are required, as well as updates to fuel instrumentation and the control system. To evaluate its long-term operational reliability, the multi-cluster combustor has been operating in one of Mitsubishi Power’s H-100 high-efficiency dual-shaft gas turbines at an oxygen-blown IGCC demonstration plant owned by Osaki CoolGen (OCG) Corporation. Delivering 166 MW of gross plant output and a plant efficiency of 42.7% (LHV, net), the H-100 technology successfully demonstrated operation on up to an 80% hydrogen fuel mix. Additionally, Mitsubishi Power is validating the multi-cluster combustion system in its air-cooled JAC gas turbines, with a proprietary technology roadmap toward rapid commercialization no later than 2030.

17.4

Mitsubishi Power’s Standard Packaged Hydrogen Solutions Mitsubishi Power is working to accelerate the path toward 100% carbon-free power generation through its launch of the world’s first standard packages for green hydrogen integration. The packaged solutions are designed to cut through the complexity power generators and grid operators encounter when integrating renewable power, gas turbines, green hydrogen, and other energy storage technologies. Mitsubishi Power’s integrated green hydrogen solution is the Hydaptive™ package. Illustrated in Figure 17.6, the Hydaptive™ package provides renewable energy flexibility by acting as a near-instantaneous power balancing resource that greatly enhances the ability of a simple cycle or combined cycle power plant to ramp output up and down to provide grid balancing services. It integrates a hydrogen and natural gas-fueled gas turbine power plant with electrolysis to produce green hydrogen using 100% renewable power and onsite storage of green hydrogen. Patent-pending TOMONI™ software and controls enable rapid load response by integrating operations of the gas turbines and the electrolysis plants. The package is available for new gas turbine power plants or as a retrofit to existing plants to improve flexibility and extend asset life. Combining the Hydaptive package with access to large-scale off-site hydrogen storage infrastructure will enable large-scale renewable energy storage that shifts variable renewable energy over time, from hours to seasons, and provides reliable and cost-effective carbon-free energy when the grid needs it most. With this package, Mitsubishi Power integrates renewables, energy storage, and gas turbines to work together to create and incorporate green hydrogen – the key to reaching zero-carbon emissions. First, electrolysis plants convert excess renewable energy into hydrogen. Next, storage mediums such as salt caverns, pipelines, or above ground vessels store this “green hydrogen” for hours to seasons, depending on the grid’s needs. Finally, hydrogen-enabled simple cycle or combined cycle gas turbine (CCGT) power plants convert the green hydrogen into centralized dispatchable electricity. The inspiration for the package was Mitsubishi Power’s first 100% green hydrogen gas turbine project, in Utah, announced in 2019. During its early involvement in

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Figure 17.6  Schematic of the Hydaptive package for hydrogen generation.

the project, Mitsubishi Power developed these packaged solutions to enable further balancing of renewable energy and better equip states and utilities to reliably and cost effectively meet their climate goals.

17.5

An Integrated Renewable-Hydrogen Energy Hub A variety of parties have come together in Utah to deliver a multi-pronged effort that encompasses all necessary components to deliver on the promise of hydrogen. The projects bring together green hydrogen production and storage, electric power generation and distribution to support the transition to carbon-free energy. The goal is to develop a fully integrated renewable-hydrogen energy hub in the region, enabling a 100% renewable power grid for the entire western interconnect of the US and also delivering renewable hydrogen for industrial and transport uses.

17.5.1

Intermountain Power Project The effort involves the Intermountain Power Project (IPP) – located in the Great Basin region of western Utah – which for three decades has served as a model of regional energy cooperation, generating and transmitting electricity to a diverse group of municipal utilities and rural electric cooperatives with operations across six US states. Intermountain Power Agency (IPA), a political subdivision of the state of Utah with municipalities as members, is leading the project dubbed “IPP Renewed.” It will replace existing coal-fired units at the IPP site with reliable, blended hydrogen energy to customers, including the Los Angeles Department of Water and Power (LADWP) and municipalities across both California and Utah. Intermountain Power Service Corp. employs the workforce at IPP and Los Angeles Department of Water

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and Power, which is the largest purchaser of electricity from IPP and serves as the operating agent and project manager. The transformational IPP Renewed project includes retiring existing coal-fueled units, installing new electricity generating units from Mitsubishi Power that are capable of operating on natural gas/hydrogen mixtures for 840 MW net generation output, modernizing IPP’s Southern Transmission System linking IPP to Southern California and developing hydrogen production and long-term storage capabilities through the adjacent Clean Energy Storage Project.

17.5.2

LADWP’s Involvement The involvement of LADWP in the project is significant, and not just because it will be a major off-taker of energy produced by the hydrogen-fueled IPP facility. In early 2021, a landmark study by the National Renewable Energy Laboratory (NREL) found that Los Angeles’ goal of reaching a 100% renewable, reliable, and resilient grid can be met as early as 2035. The three-year Los Angeles 100% Renewable Energy Study (LA100) (Cochran et al., 2021) was done by NREL researchers who combined economic, energy, and public health models to produce more than 100  million simulations and identify a series of “pathways” that could lead the utility to 100% renewable energy. Each pathway included anywhere from 73% to 92% of renewable energy generation from solar and wind resources. The study said that achieving this range would be enabled by deploying battery storage technologies and new or upgraded transmission lines that would allow LADWP to reserve and dispatch power to meet high demand periods. To meet the remaining demand, LADWP will need to bring “more nascent forms” of clean energy generation into the mix. The report said that infrastructure to produce and store green hydrogen power – as at the Intermountain Power Project – represents a leading option.

17.5.3

Mitsubishi Power’s Evolving Gas Turbine Technology In March 2020, IPA awarded Mitsubishi Power a contract for two M501JAC power trains, shown in Figure 17.7, as part of the combined cycle power station for the IPP Renewed project. The turbines are commercially guaranteed as capable of using a mix of 30% hydrogen and 70% natural gas fuel at startup. This fuel mixture is projected to reduce carbon emissions by more than 75% compared to the coal-fired technology that is being retired at the site. Work to advance the IPP Renewed project is under way. Permitting and project design activities for the reimagined power plant began in 2019, and the design of key facilities followed. Site preparation and construction is slated to begin in 2022, with new electricity generating units beginning commercial operation in July 2025. Then, between 2025 and 2045, the combined cycle plant’s hydrogen capability will be systematically increased to 100% renewable hydrogen, enabling carbon-free utility-scale power generation.

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Figure 17.7  Mitsubishi Power’s M501JAC gas turbine engine.

Mitsubishi Power will furnish the plant with two 1-on-1 M501JAC power trains with gas turbines, steam turbines, heat recovery steam generators, and auxiliary equipment. In addition to the equipment, Mitsubishi Power will service the plant under a 20-year service agreement. The J Class turbine is a workhorse technology that will offer great reliability and flexibility for the world-class IPP facility. Mitsubishi Power’s installed fleet of J Class gas turbines has accumulated roughly one million hours of operating experience in deployments around the world. Intermountain Power Agency will receive Mitsubishi Power’s newest-generation JAC air-cooled, dry low-NOx combustion system with hydrogen-rich fuel capability.

17.5.4

Advanced Clean Energy Storage Project The Intermountain Power Project, which is located on a 4,614-acre site near Delta, Utah, is an ideal location for siting and scaling up these clean energy technologies. In a joint venture between Mitsubishi Power and Magnum Development, the Advanced Clean Energy Storage project will provide a renewable hydrogen generation and storage facility adjacent to the IPP’s combined cycle station with an initial capacity of 1,000 MW and much greater storage potential going forward. The site is home to substantial existing infrastructure as well as an abundance of space to build the additional facilities that will be required. In particular, the area’s existing infrastructure and resources include ample water, access to two major electricity transmission systems, access to railroad and highway transportation, close proximity to existing interstate pipelines, and a site located directly over a major high-quality geologic salt dome formation. The salt dome, which is already being used for liquid fuel storage in solution-mined caverns, provides opportunities for gridscale real-time and seasonal energy storage. As the world’s largest renewable energy storage project, it will use renewable energy-­powered electrolysis to split water into oxygen and hydrogen. The green hydrogen then will be stored in the naturally occurring salt formation through a series

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Figure 17.8  Salt cavern for hydrogen storage.

of purposefully designed, engineered, and constructed caverns that can store hydrogen for days, weeks, months, or seasons at a time. In fact, geologic caverns have been successfully used to store hydrogen for decades, with three currently in use in the US. This project will use a salt dome with up to 100 individual storage caverns located deep underground; the scale of these geologic features is shown in Figure 17.8. The stored green hydrogen will be available to use as fuel to drive electricity-­ generating turbines from Mitsubishi Power designed to operate on a mixture of natural gas and hydrogen. The project has the capability to store an enormous amount of hydrogen, because each salt cavern is up to 300 feet in diameter and 1,500 feet high – as tall as the Empire State Building. A single cavern can store enough green hydrogen to provide 150 GWh of electricity. That’s as much hydrogen as 60 Saturn V rockets – and a storage capacity equivalent to more than 100 times the entire installed base of lithium-ion batteries in the US. In fact, the lithium-ion batteries needed to produce the same electricity output as the hydrogen in the cavern would require more than 40,000 shipping containers totaling 100 million cubic feet – approximately the size of three Empire State Buildings. Another key element of the renewal project is access to the modernized 2,400 MW-capacity Southern Transmission System. That high-voltage transmission system provides a direct-current link from the IPP site to Southern California and

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Figure 17.9  The Hydaptive™ package integrates a hydrogen powered CCGT plant and green hydrogen production through electrolysis to provide long-duration renewable energy storage and rapid load response grid balancing services.

represents a critical element in the delivery of renewable electricity to the western US power grid. Additionally, power from this site is highly accessible to the rest of the Western Interconnection, given its central location in the region managed by the Western Electricity Coordinating Council. Additional connections to this site will include the TransWest Expression Transmission line, with service to Wyoming and Las Vegas. In 2021, the Advanced Clean Energy Storage project submitted an application for a multi-million dollar loan from the US Department of Energy’s innovative energy loan guarantee program to develop its proposed green hydrogen hub to interconnect green hydrogen production, storage, and distribution in the West. If the project reaches loan closing, debt financing from the DOE would support construction of the green hydrogen hub, which ultimately targets building more than 1,000 MW of electrolysis facilities capable of producing more than 450 metric tons per day of green hydrogen to be stored in the site’s geological salt caverns. Mistubishi’s Hydaptive technology would serve as the core of a next-generation clean energy system, as shown in Figure 17.9.

17.6

Additional Decarbonization Plans via Hydrogen The plans for hydrogen production, storage, and power generation in rural Utah demonstrate technologies essential to a decarbonized future for the power grid. They also will be instrumental in supporting the decarbonization of other sectors with carbon-­ free fuels including the transportation, industrial, and additional hard-to-electrify

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verticals. And the IPP Renewed and Advanced Clean Energy Storage projects are not the only big and ambitious efforts in which Mitsubishi Power is taking a leading role in developing a hydrogen future.

17.6.1

Hydrogen Project in the US Multiple projects under way in the US will use Mitsubishi Power’s Hydaptive™ package to help convert units over time from natural gas to hydrogen, including hydrogen energy storage capability. These projects each include the company’s JAC gas turbine power islands that are initially capable of operating on 30% green hydrogen, with future capability of operating on 100% green hydrogen. A joint development agreement between Mitsubishi Power and Entergy aims to bring decarbonization projects to Entergy’s utility businesses in four US states: Arkansas; Louisiana, including the separate jurisdiction of New Orleans; Mississippi; and Texas. The relationship will foster collaboration on project development and technology solutions toward enabling Entergy to create a cleaner, more sustainable future for stakeholders by limiting carbon emissions from electric power generation. Entergy engaged with Mitsubishi Power because of the company’s demonstrated ability to provide innovative total solutions leveraging multiple technologies to reach decarbonization goals. One of the first collaborative projects is the proposed 1,200 MW Orange County Power Station’s advanced combined cycle project, which will use two of Mitsubishi Power’s M501JAC gas turbines initially operating on a 30% hydrogen/70% natural gas blend. By adopting Mitsubishi Power’s Hydaptive package, the plant plans to integrate electrolyzers for green hydrogen with the gas turbines. In North Dakota, Mitsubishi Power and Bakken Energy formed a strategic partnership to create a clean hydrogen hub. This hub will be composed of facilities that produce, store, transport, and consume blue hydrogen, using natural gas to derive the hydrogen and then capturing and sequestering carbon dioxide. It will be connected by pipeline to other clean hydrogen hubs being developed throughout North America. Mitsubishi Power also signed an agreement to develop hydrogen storage solutions with Texas Brine across the eastern US. This collaboration expands Mitsubishi Power’s capability to store hydrogen safely and cost effectively in salt caverns in strategic locations across North America. The nation’s largest brine producer, Texas Brine and its affiliates have salt positions in New York, Virginia, Texas and Louisiana that will enable access to major load centers in the Northeast, the Mid-Atlantic and the Gulf Coast. The Texas Brine collaboration complements Mitsubishi Power’s growing portfolio of hydrogen-ready gas turbines by positioning large-scale hydrogen storage in close proximity to projects, enabling access to economical utility-scale renewable energy storage.

17.6.2

Hydrogen Projects around the Globe Mitsubishi Power also is playing an active role in a variety of global projects that are advancing hydrogen technology to help meet decarbonization goals outside of

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Michael J. Ducker

Figure 17.10  Hamburg green hydrogen hub ecosystem.

the US. For instance, the companies Shell, Mitsubishi Heavy Industries, Vattenfall and municipal company Wärme Hamburg have signed a letter of intent as they plan to jointly produce and use hydrogen from wind and solar power at the Hamburg-­ Moorburg power plant site, as shown in Figure 17.10. In addition to the construction of a scalable electrolyzer with an initial output of 100 MW, the further development of the site into a so-called “Green Energy Hub” is planned. This includes the exploration of the extent to which the existing infrastructure of the Moorburg location can be used for the production of energy from renewable sources. In this context, concepts for the necessary logistics chains and storage options for hydrogen also will be considered. Subject to a final investment decision and according to the current state of planning, once the site has been cleared, the production of green hydrogen is anticipated around 2025. At that point, the electrolyzer would be one of the largest plants in Europe. The partners intend to apply for funding under the EU program “Important Projects of Common European Interest” (IPCEI). This should take place in the first quarter of 2021 with the submission of a first project outline. From an energy standpoint, the four partner companies view the location as ideal for further use. It is connected to both the national 380,000 V transmission network and the 110,000 V network of the city of Hamburg. In addition, overseas ships can call at the location directly and use the quay and port facilities as an import terminal. The municipal gas network company also intends to expand a hydrogen network in the port within 10 years and already is working on the necessary distribution infrastructure. Numerous potential customers for green hydrogen are located near the site, thus enabling the project to cover the entire hydrogen value chain – from generation

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to storage, transport, and utilization in various sectors. With these prerequisites, the Moorburg location is optimal for the German federal state of the Free and Hanseatic City of Hamburg and Northern Germany and can become a potential starting point for the development of a hydrogen economy. For many years, Moorburg was the site of a gas-fired power plant operated by Hamburgische Electricitäts-Werke, and Vattenfall had been operating a coal-fired power plant there since 2015. Its commercial operation was terminated after the power plant won a bid in the auction for the nationwide coal phase-out in December 2020. A decision by the transmission system operator on the system relevance of the plant was expected in March 2021. The city of Hamburg and Vattenfall are striving to clear areas of the site as soon as possible for the project to produce green hydrogen and the development of a Green Energy Hub. In their efforts to form a consortium, the four companies also can count on support from the city of Hamburg’s government. In their coalition agreement, the governing parties decided to examine and support the feasibility of sector coupling and the establishment of hydrogen production in the city-state. Mitsubishi Power also will support the Carbon-Free Gas Power project for Nuon’s Magnum power plant in Groningen in the Netherlands led by Nuon/Vattenfall, Statoil, and Gasunie. Mitsubishi Power, which manufactures the gas turbine operating at the Nuon/Vattenfall Magnum combined cycle gas turbine (CCGT), has a long history of success developing special fuels, such as synthetic fuels or blast furnace gas, for its gas turbines. Mitsubishi Power will apply this expertise to investigate the technical feasibility of H2 firing. The Carbon-Free Gas Power project aims to convert one of the three 440  MW CCGT power plants to hydrogen by 2023. Nuon/Vattenfall, Statoil, and Gasunie have contracted Mitsubishi Power to jointly investigate the possibility of using hydrogen for generating electricity by Nuon/Vattenfall’s Magnum power plant as the world’s first innovative CCGT project. One CCGT can emit up to 1.3 million tons of CO2 per year, and burning hydrogen will significantly reduce this emission. Within this project, Statoil will focus on producing hydrogen by converting Norwegian natural gas into hydrogen and carbon dioxide. The carbon dioxide will be stored in underground facilities off the Norwegian coast, allowing carbon-neutral production. Gasunie is carrying out research into how the hydrogen can be transported to and stored at the Magnum power station. At another project in the Netherlands, oil major Shell and its Dutch utility partner Eneco, a unit of Mitsubishi, are planning a green hydrogen hub in the port of Rotterdam. The partners are bidding to build the Hollandse Kust (Noord) wind farm in the North Sea. Around 200 MW of the wind farm’s output would be dedicated to operating electrolyzers at a green hydrogen production plant in Rotterdam. The hydrogen then would be used at a nearby Shell oil refinery where it will displace on the order of 200,000 tons of CO2 per year. If the partners’ bid is approved, the wind farm and hydrogen plant could enter service by 2023, with initial production between 50,000 and 60,000  kilograms of hydrogen per day.

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In an additional European hydrogen venture, Eneco signed on with Neptune Energy for a project known as PosHYdon pilot. As designed, the venture would result in one of the world’s first offshore hydrogen projects, integrating three North Sea energy systems: offshore wind, offshore natural gas production, and offshore hydrogen. PosHYdon would install a hydrogen-producing plant on the Neptune-operated Q13a oil platform in the North Sea. Electricity from offshore wind turbines would power the hydrogen plant. As with the Shell venture in Rotterdam, the Neptune plant would use electrolysis to convert seawater first into demineralized water, then into hydrogen. The pilot aims to advance the process and technology involved in integrating ocean-based energy systems and hydrogen production in an offshore environment.

17.7 Summary Hydrogen is the most abundant element in the universe and may be its most versatile from an energy perspective. Rapid technology advancements to combat climate change are making it more feasible than ever before to derive and accelerate the use of clean hydrogen as economies simultaneously decarbonize and expand electrification beyond traditional uses. Equally important is the adoption of public policy goals and incentives to help support this complex yet entirely feasible transition to clean energy sources. The Intermountain Power Project – backed by proven power generation technology, sited at an ideal location for hydrogen production and storage via the Advanced Clean Energy Storage Project, and supported by one of the country’s most progressive municipal utilities – is demonstrating how hydrogen is becoming the energy storage medium of choice to meet today’s pressing environmental and electrification needs. These projects and many others across the globe are enabled by Mitsubishi Power’s latest hydrogen-gas turbine technology as well as its integrated green hydrogen solutions for power balancing and energy storage via its Hydaptive™ package.

References Asai, T., Dodo, S., Karishuku, M., Yagi, N., Akiyama, Y. and Hayashi, A., 2015. Part Load Operation of a Multiple-Injection Dry Low NOx Combustor on Hydrogen-Rich Syngas Fuel in an IGCC Pilot Plant. In Turbo Expo 2015, Montreal, Quebec, Canada. Asai, T., Miura, K., Akiyama, Y., Karishuku, M., Yunoki, K., Dodo, S. and Horii, N. 2016. Development of Fuel-Flexible Gas Turbine Combustor. In Proceedings of the 45th Turbomachinery Symposium. Turbomachinery Laboratories, Texas A&M Engineering Experiment Station. Cochran, J., Denholm, P., Mooney, M. et al. 2021. The Los Angeles 100% Renewable Energy Study (LA100) (No. NREL/TP-6A20-79444). National Renewable Energy Lab.(NREL), Golden, CO (United States). Energy and Environmental Economics, Inc., 2020. Hydrogen Opportunities in a Low-Carbon Future.

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Gillette, J.L. and Kolpa, R.L., 2007. Overview of Interstate Hydrogen Pipeline Systems (No. ANL/EVS/TM/08-2). Argonne National Laboratories, Argonne, IL (United States). Melaina, M.W., Antonia, O. and Penev, M., 2013. Blending hydrogen into natural gas pipeline networks: A review of key issues. Nelson, L. et al. 2020. Green Hydrogen Guidebook. Green Hydrogen Coalition. Tada, K., Inoue, K., Kawakami, T., Saitoh, K. and Tanimura, S., 2018. Expanding Fuel Flexibility in MHPS’Dry Low NOx Combustor. In Turbo Expo 2018, Oslo, Norway.

Index

absorption chilling, 48 adiabatic flame temperature, 155–156, 248, 292–296, 299, 317, 377–380 air separation unit, 232 air toxics, 45 aircraft, 3–33, 37, 468, 487–500 alcohol, 77, 104–105, 224, 385–387, 529 butanol, 83, 104 ethanol, 77, 81–83, 93–94, 104, 106, 115, 404, 443, 506–509, 526 methanol, 81, 83, 115, 228–230, 443, 526–527 to jet fuel, 496–498 algae, 124, 219, 234–236, 333, 497, 498 alkylation, 81, 497 aluminum, 183, 277–281, 284–316, 319–320 ammonia, 245–267 blue, 245 distribution, 252–254 emissions, 464–468 green, 245 grey, 245 Haber–Bosch. See Haber–Bosch production, 142, 248–252 properties, 27, 97, 247–248 slip, 32 storage, 252–254 anaerobic digestion, 108, 196–198, 203–205, 210–211, 527 aromatics, 23, 79, 91–92, 99–101, 474–475, 497–498 ash, 235, 331–332, 338–341, 458 ASTM D1655, 489–492, 495–496 D4054, 489–492, 493–495 D4814, 81 D4815, 81 D7566, 489–492, 495–496 atomization, 17, 24–25, 83–87, 103–105, 414–449 primary, 430–432 secondary, 432–433 autoignition, 26, 56, 59–60, 79, 83–84, 90, 103, 405, 417 automobile, 23, 75–77, 79, 507 aviation. See aircraft

balance of plant, 36, 40, 114, 164, 166, 180, 236, 529, 537, 539 battery, 119–125, 162–163 biochar, 202, 341–342 biofuel, 526–527 biodiesel, 88, 102–104, 118–119 first-generation, 219 second-generation, 219 third-generation, 219 biogas, 195–197, 202–206, 209–212, 527 biomass, 199–202, 209–210, 217–229, 234–238, 329–357 bioreactor, 202–205, 219 bitumen, 49 blending blend wall, 116, 507 blendstock, 81, 93, 101, 112, 116, 228 fuel blending system, 518–521 blowoff. See combustion, static stability boron, 261, 277, 287–288, 293 bottoming cycles, 51 burner duct, 49 floor, 143 wall, 143 carbon dioxide capture, 210, 231, 352 emissions, 29, 45, 120–125, 453 regulations, 36–37 carbon-free fuel, 3, 95, 275–279, 498 carbon monoxide emissions, 452–454 oxidation, 383 regulations, 36–37 carbon number, 23, 98, 224–225 catalyst emissions, 502 fuel cell, 163, 261 fuel synthesis, 197, 230 gasification, 202 metal fuels, 307 catalytic hydrothermolysis jet (CHJ), 498 cetane number, 87–88, 99, 101, 104–105

Index

chemical energy carrier, 175–187, 247, 275–279 chlorofluorocarbons, 247 circular fuels economy, 219–221 metal, 275–279 clean air act, 158, 335, 502, 503 climate change, 119, 354, 415 coal, 42, 47, 50 co-firing, 254, 263 cogeneration, 44, 48, 547 challenges, 49 district energy, 49 combined heat and power. See cogeneration combustion dynamics, 60 engine, 75, 255–258 static stability, 58–60 zone, 9, 77, 85, 398–399, 423–427 combustion instability. See combustion, dynamics combustor annular, 64–66 can, 64–66 dry low NOx. See dry low NOx (DLN) fuel staging, 14–15 multi-cluster, 549–550 non-premixed, 38. See non-premixed combustion premixed, 39. See premixed combustion rich-quench-lean (RQL), 8–14 compression ignition, 77, 82–89, 104–106, 108, 114, 118–119 compressor, 35, 50–52 stall, 16, 31 cooling engine, 14, 18–22 fuel, 249 SOFC, 168 crude oil, 39, 85, 195, 216, 414 cryogenic, 30–32, 116–117, 182, 416, 525 cycle Brayton, 5, 54, 415–417, 442 Diesel, 75–77, 82, 257–258, 415–417, 420, 442 Otto, 75, 77, 415–417 Damköhler number, 58 decarbonization, xi, 120, 198, 320, 452, 544–545, 555–556 demonstration Bakken Energy, 556 biodiesel, 526 Cricket Valley Energy Center, 521 DME, 111 Duke Energy, 520 EnergyAustralia, 521 Engie, 520 Entergy, 556

563

ethanol, 526 Hamburgische Electricitäts-Werke, 558 Hollandse Kust, 558 Intermountain Power, 521–553 Long Ridge Energy Terminal, 520 Los Angeles Department of Water and Power (LADWP), 552 metal fuel, 302 Neptune, 559 New York Power Authority (NYPA), 520 Nuon, 558 Vattenfall, 556–558 diesel fuel, 23, 85–89, 97–114 renewable, 118–122 diffusion flame, 84–85, 439, 469, 536–537 metal fuels, 298–302 digital control system (DCS), 518 diluent, 406, 525, 547 dimethyl ether, 88, 105–114, 225–230, 257 direct air capture, 120, 198, 219–220, 231–234 dispatchable, 544, 546, 548 energy, 545 generation, 550 distillation, 89–90, 98, 216, 248, 442, 445, 492 draft balanced, 141 forced, 141 induced, 141 natural, 141 droplet evaporation. See: evaporation phase Doppler particle anemometry/analysis, 438 Sauter mean diameter, 436–439 spray. See atomization dry low NOx (DLN), 46, 67–70, 536, 545–550 durability compression ignition engines, 108, 118–119 emission control systems, 508 fuel cell, 173, 261 gas turbine, 4, 13, 18–22 efficiency Carnot, 161, 316 combustion, 10, 145, 256, 315, 465 faradaic, 178–180, 185–187 mechanical, 171 power conditioning, 171–172 propulsive, 22 thermal, 56, 94, 97, 105, 112–114, 141, 149–150, 173 thermal-voltage, 172 thermodynamic potential, 179 electricity grid, 43–44, 53, 211, 221, 544, 545 microgrid, 44

564

Index

electrochemical, 161, 165, 175–180, 186–187, 278 electrolysis, 177–180, 183–185, 226, 230, 231–232, 238–239, 250, 284–287, 544, 550 embrittlement, 529, 531–532 emission policy, 47 Europe, 208 US 125, 208 emission trading, 355 emissions See nitrogen oxides, soot, carbon monoxide, unburned hydrocarbons, 3 Energy Independence and Security Act, 354, 507 Energy Policy Act, 504 energy storage. See storage environmental protection agency, 81, 99, 197, 208, 505–510 esters, 102–104, 496–498 ethanol. See alcohol evaporation, 17, 292, 421–427, 439–442 fatty acid, 102–103, 202, 496–498 feedstock, 102, 175, 179, 198, 202–205, 209–212, 234–238, 331–335, 339, 349–353, 445 Fischer–Tropsch, 88, 101, 195, 223, 224, 336, 445, 468 synthetic paraffinic kerosene (FT-SPK), 475, 496, 497 fixed carbon, 332–335, 347–348 flame holding. See combustion, static stability flame propagation, 59, 77–79, 399–401 flame speed, 31, 535 laminar, 398–405, 465 metal, 297–301 turbulent, 58–59, 406–409, 426 flame stretch, 406–409 flammability limit, 405–406, 515, 539 flash point, 23, 87, 98, 104 flashback. See combustion, static stability fouling, 156, 201 freezing point, 24, 492, 495 fuel approval process, 490–491 diesel. See diesel fuel drop-in, 101, 107, 120, 198, 211, 238, 487–500 flexibility, 38, 53, 59, 415, 429, 548 gasoline, 77–84 jet. See jet fuel petroleum-derived, 93, 101, 488–492 refinery, 154 stability, 24, 118, 492, 496, 531 fuel cell, 163, 259–261 alkaline, 163, 261 molten carbonate, 163 phosphoric acid, 163 proton exchange membrane, 163, 167–168, 260–261 solid oxide, 163, 168, 261

fuel characteristics, 430 biomass, 333 diesel, 87 gasoline, 83 jet, 22–27 fuel composition gaseous, 40–42 gasoline, 79–81, 156–157 jet, 23–24 fuel staging, 8, 14–15, 20–22, 52, 67–70 fuel system, 27–29, 493, 528–535 classification, 532–535 storage, 115 switching, 41, 528, 529 fully synthetic jet fuel (FSJF), 469, 475 furan, 94–95, 112 furnace ammonia, 254–255 blast, 523, 547 cracking, 141–144, 154–155 gas turbine, 35–71 aeroderivative, 36, 46, 62–63, 520 aircraft, 3–33, 46 ground power, 46, 56–57, 61–62 gasification, 50, 199–202, 227–229, 335–341, 352, 457–458, 522 green hydrogen coalition, 544 greenhouse gases (GHGs), 124, 350–352 carbon dioxide, 209 methane, 209 reduction, 119, 355, 445 groundwater, 106 contamination, 503–506 Haber–Bosch, 245, 248–252 heat of vaporization, 26, 83, 88, 181, 247 heat recovery steam generator, 49, 537–538 heater, 138–160 cabin, 139 vertical, 139 heating value, 156 higher, 332, 335, 339 lower, 83, 88, 100, 155, 171, 248, 515 volumetric basis, 41 hybrid aircraft, xiii rockets, 289 vehicle, 122–123, 172 hydrogen aircraft, 29–32 blue, 158, 183 emissions, 462–464 green, 158, 183 grey, 158, 183 oxidation, 383 production, 157–158, 178, 183–187

Index

properties, 154–156, 176–178 safety, 182 storage, 182–183 hydroprocessed esters and fatty acids (HEFA), 496–498 hydrothermal carbonization, 346 conversion, 498 liquefaction, 224–225, 234–238 ignition, 15–18 delay, 387–398 mechanism, 292, 388 relight, 8, 16–17, 29 stabilization, 9 industrial fuels blast furnace gas (BFG), 523 coke oven gas (COG), 517, 523–524 injector, 433–436 airblast, 17–18 direct injection, 112–113 ducted fuel injection, 420–421 effervescent, 436 flow-blurring, 436 jet-in-crossflow (JICF), 435 main, 14, 67 pilot, 14, 67, 112, 434 port injection, 112–113 pressure atomizing, 17 simplex, 434 staged, 67 instrumentation, 539, 550 integrated gasification combined cycle (IGCC), 50, 522 iron, 277, 279–284, 285–302 jet fuel alternative, 27–30, 468–474, 487–500 emissions. See emissions jet A/A-1, 489–492 properties, 22–27, 430, 469 knock, 79, 89–91, 502 anti-knock index, 79, 81, 89 superknock, 90 landfill gas, 196–197, 198 lead, 79, 502–503 lean direct injection, 448 NOx emissions, 32 operability, 32 life-cycle assessment (LCA), 349–353, 445 light distillate fuel oil, 79, 516, 528–531 lithium, 115, 119–120, 284, 302, 554 lubricity, 87, 100, 102, 108–109, 529 magnesium, 277, 285–291, 298, 301–303, 317 maximum experimental safe gap (MESG), 532–534

565

metal fuel, 275–320 gaseous combustion, 289–302 history, 288–289 hybrid rockets, 289 production, 281–286 proposed power generating approaches, 279–281 water reaction, 302–318 methanation, 199–200, 202, 207–208 methane production, 207–208 methanol. See alcohol methyl tertiary-butyl ether (MTBE), 503–507 micromixer, 67 molecular weight, 23, 181 municipal solid waste, 198, 331, 333, 335, 341, 347 National Electric Code (NEC), 532–533 National Fire Protection Association (NFPA), 532 National Institute for Occupational Safety and Health (NIOSH), 539 net heat of combustion, 26, 27, 181, 220 nitrogen oxides alternative jet fuel emissions, 469–474 ammonia combustion, 464–468 emissions, 32, 454–458, 461–474 Fenimore, 456–457 formation, 454–458 fuel bound, 457–458 hydrogen combustion, 462 N2O, 455–456 NNH mechanism, 457 prompt, 456–457 reduction, 47 regulations, 36–37 thermal, 454–455 wet control, 42 Zeldovich, 454–455 non-premixed combustion, 67, 82, 289, 422–427, 439, 452, 469, 536–37. See diffusion, flame octane number (ON), 89, 93–96, 248, 502 motor octane number (MON), 79, 83 research octane number (RON), 79, 83 Ohnesorge number, 428–429 operational stability, 58–60 original equipment manufacturers (OEM) Ansaldo, 517 General Electric, 60, 516–524 Mitsubishi Power, 517, 544–560 Siemens, 60, 516–524 Solar Turbines, 60, 517 oxyfuel combustion, 257 ozone, 37, 48, 92–93 particulate matter, 6, 24, 100, 417 petcoke, 42 piloting. See injector

566

Index

pipeline, 50–52, 182, 209, 252–253, 501, 524, 544–545 pollutants. See emissions power-to-gas, 197–198, 207–208, 245 premixed combustion, 52, 388, 398, 423, 439, 452, 476, 536–537 pyrolysis, 199, 224–225, 228, 236–238, 341–352 radiation, 20, 142, 301, 417, 459, 474 reformulated gasoline (RFG), 79–81, 503 renewable fuel standard, 197, 208, 354, 504, 509 Reynolds number, 429 safety. See toxic ammonia, 264–267, 535 fuel cell, 182, 185 hydrogen, 182, 518, 539–540 metal fuels, 277 natural gas, 50–52, 116–117, 209 salt cavern, 183, 545, 554–555 selective catalytic reduction, 32, 47, 111, 259, 526, 538 selective non-catalytic reduction, 465 sensors. See safety shelf life. See fuel stability silicon, 277, 287, 303–304 sludge, 203–204, 213, 329, 331–333, 337–339, 347, 356 soot control, 100, 103–105, 107 formation, 84–85, 112, 458–461 regulations, 36–37 spark ignition, 149 engine, 77–82 specific heat, 25, 27, 443 spray. See atomization stability, 531 steam-methane reforming, 142, 157–159, 248, 337 stoichiometry, 8–15, 83, 88, 303, 371–378 storage ammonia, 252–254, 261–263 battery, 162–164 fuel cell, 259–260 hydrogen, 182–183, 545–547 kerosene, 414 metal, 276, 286 metal fuel, 308 sulfuric acid corrosion, 537

supercritical fuel injection, 442–445 water reactions, 312–314 supply chain, 3, 30–32, 209, 235, 355, 489–490, 500 surface tension, 25, 427–433, 442–445 sustainable aviation fuel. See jet fuel, alternative syngas, 400–401 history, 195–198 integrated gasification combined cycle (IGCC), 50, 522 production, 199–202 synthesized iso-paraffins (SIP), 497 synthesized paraffinic kerosene (SPK) alcohol to jet, 496–498 Fischer–Tropsch. See Fischer–Tropsch hydroprocessed hydrocarbons esters and fatty acids, 498 hydroprocessed esters and fatty acids, 497 technoeconomic analysis, 179–180, 226, 236, 261–263 tetraethyl lead (TEL), 502–503 thermal stability. See fuel Threshold Sooting Index (TSI), 474 torrefaction, 341–347 toxic emissions, 44, 92, 96, 103 fuel, 106, 265, 535 immediate danger to life and health (IDLH), 97, 540 metals, 277, 502 ultra-low-sulfur diesel (ULSD), 101, 509–510 unburned hydrocarbon (UHC), 6–7, 417, 469, 475 regulations, 36–37 vapor pressure, 25–26, 80, 116, 167 viscosity, 24–25, 87, 98–99, 108–109, 248, 313, 429, 492 volatile matter, 332–334, 347–348 water injection, 42–43, 526 Weber number, 429 Wobbe Index, 40–41 zinc, 277, 285, 287–288, 303 zirconium, 288, 297, 303