Power Grid Operation in a Market Environment E-Book

• Herausgeber: John Wiley & Sons
• Kategorie: Wissenschaft und neue Technologien
• Serie: IEEE Press Series on Power Engineering
• Sprache: Englisch

Seitenzahl: 482

Veröffentlichungsjahr: 2016

Beschreibung

Covers the latest practices, challenges and theoretical advancements in the domain of balancing economic efficiency and operation risk mitigation 

This book examines both system operation and market operation perspectives, focusing on the interaction between the two. It incorporates up-to-date field experiences, presents challenges, and summarizes the latest theoretic advancements to address those challenges. The book is divided into four parts. The first part deals with the fundamentals of integrated system and market operations, including market power mitigation, market efficiency evaluation, and the implications of operation practices in energy markets. The second part discusses developing technologies to strengthen the use of the grid in energy markets. System volatility and economic impact introduced by the intermittency of wind and solar generation are also addressed. The third part focuses on stochastic applications, exploring new approaches of handling uncertainty in Security Constrained Unit Commitment (SCUC) as well as the reserves needed for power system operation. The fourth part provides ongoing efforts of utilizing transmission facilities to improve market efficiency, via transmission topology control, transmission switching, transmission outage scheduling, and advanced transmission technologies. Besides the state-of-the-art review and discussion on the domain of balancing economic efficiency and operation risk mitigation, this book:

• Describes a new approach for mass market demand response management, and introduces new criteria to improve system performance with large scale variable generation additions
• Reviews mathematic models and solution methods of SCUC to help address challenges posed by increased operational uncertainties with high-penetration of renewable resources
• Presents a planning framework to account for the value of operational flexibility in transmission planning and to provide market mechanism for risk sharing

Power Grid Operations in a Market Environment: Economic Efficiency and Risk Mitigation is a timely reference for power engineers and researchers, electricity market traders and analysts, and market designers.

Leseprobe

IEEE Press

445 Hoes Lane

Piscataway, NJ 08854

IEEE Press Editorial Board

Tariq Samad, Editor in Chief

George W. Arnold

Xiaoou Li

Ray Perez

Giancarlo Fortino

Vladimir Lumelsky

Linda Shafer

Dmitry Goldgof

Pui-In Mak

Zidong Wang

Ekram Hossain

Jeffrey Nanzer

MengChu Zhou

Kenneth Moore, Director of IEEE Book and Information Services (BIS)

Technical Reviewer

Xiao-Ping Zhang, University of Birmingham

POWER GRID OPERATION IN A MARKET ENVIRONMENT

Economic Efficiency and Risk Mitigation

Edited by

HONG CHEN

Copyright © 2017 by The Institute of Electrical and Electronics Engineers, Inc. All rights reserved.

Published by John Wiley & Sons, Inc., Hoboken, New Jersey. Published simultaneously in Canada.

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Library of Congress Cataloging-in-Publication Data is available.

ISBN: 978-1-118-98454-3

CONTENTS

FOREWORD

PREFACE

ACKNOWLEDGMENT

CONTRIBUTORS

PART

I

INTEGRATED SYSTEM AND MARKET OPERATION

CHAPTER

1

BALANCE ECONOMIC EFFICIENCY AND OPERATION RISK MITIGATION

1.1 POWER SYSTEM OPERATION RISK MITIGATION: THE PHYSICS

1.2 INTEGRATED SYSTEM AND MARKET OPERATION: THE BASICS

1.3 ECONOMIC EFFICIENCY EVALUATION AND IMPROVEMENT: THE ECONOMICS

1.4 FINAL REMARKS

APPENDIX 1.A NOMENCLATURE

APPENDIX 1.B ELECTRICITY MARKET MODEL

REFERENCES

DISCLAIMER

CHAPTER

2

MITIGATE MARKET POWER TO IMPROVE MARKET EFFICIENCY

2.1 INTRODUCTION

2.2 PRICE FORMATION IN ELECTRICITY MARKETS

2.3 PRICE AND OFFER CAPS

2.4 ABILITY AND INCENTIVE TO EXERCISE MARKET POWER

2.5 MARKET POWER MITIGATION APPROACHES

2.6 CONCLUSION

ACKNOWLEDGMENTS

NOTES

REFERENCES

PART

II

UNDER SMART GRID ERA

CHAPTER

3

MASS MARKET DEMAND RESPONSE MANAGEMENT FOR THE SMART GRID

3.1 OVERVIEW

3.2 INTRODUCTION

3.3 DISTRIBUTED COMPUTING-BASED DEMAND RESPONSE MANAGEMENT APPROACH

3.4 THE COLORPOWER ARCHITECTURE AND CONTROL ALGORITHMS

3.5 INTEGRATION WITH THE WHOLESALE ENERGY MARKET

3.6 EQUALIZING MARKET POWER BETWEEN SUPPLY AND DEMAND

3.7 GENERALIZATION BEYOND DEMAND RESPONSE

3.8 A NUMERICAL EXAMPLE

3.9 CONCLUDING REMARKS

APPENDIX 3.A NOMENCLATURE

REFERENCES

CHAPTER

4

IMPROVE SYSTEM PERFORMANCE WITH LARGE-SCALE VARIABLE GENERATION ADDITION

4.1 REVIEW OF REGULATION AND ANCILLARY SERVICES

4.2 DAY-AHEAD REGULATION FORECAST AT CAISO

4.3 RAMPING AND UNCERTAINTIES EVALUATION AT CAISO

4.4 QUANTIFYING THE REGULATION SERVICE REQUIREMENTS AT ERCOT

4.5 CONCLUSIONS

APPENDIX 4.A NOMENCLATURE

NOTES

REFERENCES

PART

III

STOCHASTIC APPLICATIONS

CHAPTER

5

SECURITY-CONSTRAINED UNIT COMMITMENT WITH UNCERTAINTIES

5.1 INTRODUCTION

5.2 SCUC

5.3 UNCERTAINTIES IN EMERGING POWER SYSTEMS

5.4 MANAGING THE RESOURCE UNCERTAINTY IN SCUC

5.5 ILLUSTRATIVE RESULTS

5.6 CONCLUSIONS

APPENDIX 5.A NOMENCLATURE

ACKNOWLEDGMENTS

REFERENCES

CHAPTER

6

DAY-AHEAD SCHEDULING: RESERVE DETERMINATION AND VALUATION

6.1 THE NEED OF RESERVES FOR POWER SYSTEM OPERATION

6.2 RESERVE DETERMINATION VIA STOCHASTIC PROGRAMMING

6.3 RESERVE DETERMINATION VIA ADAPTIVE ROBUST OPTIMIZATION

6.4 STOCHASTIC PROGRAMMING VS. ADAPTIVE ROBUST OPTIMIZATION

6.5 RESERVE VALUATION

6.6 SUMMARY, CONCLUDING REMARKS, AND RESEARCH NEEDS

APPENDIX 6.A NOMENCLATURE

REFERENCES

PART

IV

HARNESS TRANSMISSION FLEXIBILITY

CHAPTER

7

IMPROVED MARKET EFFICIENCY VIA TRANSMISSION SWITCHING AND OUTAGE EVALUATION IN SYSTEM OPERATIONS

7.1 BACKGROUND

7.2 BASIC DISPATCH MODEL FOR MARKET CLEARING

7.3 ECONOMIC EVALUATION OF TRANSMISSION OUTAGE

7.4 OPTIMAL TRANSMISSION SWITCHING

7.5 SELECTION OF CANDIDATE TRANSMISSION LINES FOR SWITCHING AND IMPLEMENTATION OF OTS

7.6 TEST CASES

7.7 FINAL REMARKS

APPENDIX 7.A NOMENCLATURE

REFERENCES

CHAPTER

8

TOWARD VALUING FLEXIBILITY IN TRANSMISSION PLANNING

8.1 INTRODUCTION

8.2 SCALE ECONOMIES OF TRANSMISSION TECHNOLOGIES

8.3 DISCONNECT OF CURRENT POWER SYSTEM OPERATIONAL, PLANNING, AND MARKET MECHANISMS

8.4 IMPACT OF OPERATIONAL AND MARKET PRACTICES ON INVESTMENT PLANNING

8.5 INFORMATION AND RISK SHARING IN THE FACE OF UNCERTAINTIES

8.6 CHALLENGES IN DESIGNING FINANCIAL RIGHTS FOR FLEXIBILITY

8.7 CONCLUSIONS

APPENDIX 8.A NOMENCLATURE

APPENDIX 8.B MATHEMATICAL MODELS USED FOR CASE STUDIES

APPENDIX 8.C INVESTMENT COST

REFERENCES

INDEX

IEEE Press Series on Power Engineering

EULA

List of Tables

Chapter 5

Table 5.1

Table 5.2

Table 5.3

Table 5.4

Table 5.5

Table 5.6

Table 5.7

Table 5.8

Table 5.9

Table 5.10

Table 5.11

Table 5.12

Table 5.13

Table 5.14

Table 5.15

Table 5.16

Chapter 6

Table 6.1

Table 6.2

Table 6.3

Table 6.4

Table 6.5

Table 6.6

Table 6.7

Table 6.8

Table 6.9

Table 6.10

Table 6.11

Table 6.12

Table 6.13

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Chapter 7

Table 7.1

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Table 7.3

Table 7.4

Table 7.5

Table 7.6

Table 7.7

Table 7.8

Table 7.9

Table 7.10

Table 7.11

Table 7.12

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Chapter 8

Table 8.1

Table 8.2

Table 8.C.1

Guide

Cover

Table of Contents

Preface

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FOREWORD

SINCE THE INTRODUCTION of deregulated energy markets, the debate on reliability versus efficiency has continued. As many of the chapter contributors in this edited book, Power Grid Operationin a Market Environment: Economic Efficiency and Risk Mitigation, referenced, grid reliability continues to be a priority throughout established markets and regulated grid operations. While the reliability of power systems clearly remains the highest priority, the need for these operations to achieve an overall efficient use of resources must also remain a priority. This book's contributing authors tackle that aspect by addressing the existing efficiency challenges and introduce innovative approaches to continue to improve efficiency while maintaining reliability.

The book is a comprehensive technical handling of many of the challenges that deregulated grid operations face and must continue to improve upon. The book does not attempt to provide all of the technical possibilities, but instead identifies some key issues and offers some innovative approaches to the primary challenges that face grid operators.

The book contributors have worked for several years from a collaboration of one of the IEEE Power Energy Society teams focused on this topic. The book will be valuable as both an academic reference as well as a reference work for market system design. Each of the chapters takes an in-depth look at a particular aspect of efficient market design.

Chen and Liu present an excellent overview of system operation and market design in Chapter 1 including the stages of mature market design to include multi-settlement markets, capacity markets, and risk-based and dynamic markets. These authors also address the first efficiency aspect—efficiency effects of reliable grid operations.

In Chapter 2, Baldick tackles another aspect of efficiency in market power and market mitigation—in general, those inefficiencies caused by imperfect markets and competition. This chapter discusses some of the short-term and long-term inefficiencies and provides a nice tie-in to the effects of demand response (DR) on market power, serving as an introduction to the next chapter. In Chapter 3, Papalexopoulos discusses the impact of demand response resources on current market operations, and looks at a more efficient approach to handling the deployment of demand response resources. This chapter describes some of the current inefficiencies in DR deployment and the necessity of a new distributed approach to address the increase of these resources in grid operations.

A natural follow-on to the demand response discussion is the proliferation of intermittent resources and their impact to efficient market and grid operations. Makarov, Etingov, and Du tackle the increase of renewable resources and their effect on system performance. These authors offer several solutions for grid operators to incorporate the uncertainty of these renewable resources into the efficient dispatch for grid operations. This sets up a good introduction for the next chapter where Wu and Shahidehpour discuss unit commitment challenges in Chapter 5. Unit commitment continues to be a challenging algorithmic problem in organized markets, particularly when you look at the impact of demand response, renewables, and the optimization of energy and reserve commitment. This chapter presents several potential technical approaches to solve these challenges.

In Chapter 6, Jiang, Conejo, and Wang take the handoff and focus on the particular challenge of reserve requirements and how reserve commitments are valued in market operations. The approach in this chapter is unique as it is presented as a tutorial on reserve commitment with several approaches to adding additional efficiency to the determination and deployment of reserves.

The final two chapters take a different direction while completing the circle in addressing the various aspects of efficient operations. In chapter 7, Cheung and Wu tackle market efficiency affected by transmission outages and transmission-switching opportunities. The authors discuss the current approach which assumes a fixed network topology, and explore several methods to improve efficient operations through more dynamic approaches to both transmission outage scheduling and transmission switching. These approaches include the recognition of potential affects to forward market operations. The chapter provides a good transition to the final chapter where Tee and Ilić present a planning framework to account for the value of operational flexibility in transmission planning.

Overall, the book presents a holistic look at the various operations, markets, and transmission planning challenges to improving efficient operations. The potential solutions and approaches detailed in this book will be a good foundation to future improvements and debates on improving grid and market efficiency.

Michael BrysonVice President of OperationsPJM InterconnectionPhiladelphia, USA

PREFACE

ELECTRICITY MARKETS HAVE BEEN successfully implemented in many parts of the world, and are reshaping power grid operations philosophically and practically. Economic efficiency has become one of the important objectives of grid operation and planning, along with the fundamental responsibilities of operation risk mitigation. Market and system operators are facing challenges to define and achieve the equilibrium of economic efficiency and risk mitigation.

This edited book, Power Grid Operation in a Market Environment: Economic Efficiency and Risk Mitigation, covers both system operation and market operation perspective, especially focusing on the interaction between the two. It reveals the challenges and best practices of the industry, and also presents the latest researches on this topic, which helps us to better prepare for the challenges and new trends in the industry.

The overview of integrated system and market operation is provided in Chapter 1, discussing the integrated operation philosophy, current market design, practices and challenges, as well as PJM's (a RTO/ISO in United States, in charge of 13 states and DC area's bulk power system operation and planning, and operating the largest wholesale electricity market in the world) experience on evaluating and improving economic efficiency. Often and conveniently, economic efficiency is based on bid and offer prices, assuming competitive markets. However, the practical electricity markets are not fully competitive. Systematic methods are needed to mitigate market power to improve market efficiency, which is discussed in Chapter 2.

With demand participation in the market mechanism and smart grid technologies, system demand becomes more elastic, which significantly improves economic efficiency and also helps with operation risk mitigation. Chapter 3 describes a new approach for the mass market demand response management, which is an essential component of the smart grid infrastructure. On the supply side, more and more renewable resources are being integrated to the system, which inevitably introduces high system volatility, sometimes, can cause high frequency excursion, as well as reduced inertia response impacting transient stability, especially for small systems. Therefore, more flexible resources are needed for system operation to improve system performance. Chapter 4 introduces new criteria to improve system performance with large-scale variable generation addition.

Operational uncertainties are challenging to manage, and significantly impact economic efficiency, especially with the increased uncertainties brought by high penetration of renewable resources. Stochastic applications can help to address the challenges. Mathematic models and solution methods of Security-Constrained Unit Commitment (SCUC) are discussed in detail in Chapter 5, considering various system uncertainties. Reserves are essential to system operation to hedge operation risks caused by uncertainties. Current deterministic methods use fixed reserve requirements determined offline based on historical data and/or procedure, and may not reflect the changing system reliability needs. Most times deterministic methods have higher level of conservativeness than required by the actual conditions, which therefore impacts economic efficiency. Chapter 6 presents a stochastic method to determine and value reserves.

On the network topology side, today's market and system operation mainly assumes fixed network topology. Emerging technologies can improve and utilize flexible transmission control to improve economic efficiency. Chapter 7 describes the methods to improve economic efficiency through topology control, that is, transmission switching and outage scheduling. In parallel, Chapter 8 presents a planning framework to account for the value of operational flexibility in transmission planning and to provide market mechanism for the risk sharing.

In summary, balancing economic efficiency and operation risk mitigation has been an ongoing challenge for the power grid operations in a market environment. It is being addressed from all aspects: from overall market design and system performance to solution methodologies; from supply and demand to networks. All of these contribute toward finding an equilibrium of economic efficiency and risk mitigation for power systems.

The book is a result of more than 5 years' efforts on IEEE Power Energy Society (PES) Task Force “Equilibrium of Electricity Market Efficiency and Power System Operation Risk.” It features the most current insight of integrated operation and state-of-the-art development, with field experience and evidence of considerable market savings by tracking equilibrium in operation. It will provide invaluable and timely reference for power engineers, electricity market traders and analysts, market designers and researchers, as well as graduate students, to understand the integrated electricity market and power system operation, reveal new requirements of vendor products, and stimulate new research and development initiatives, especially on modeling and computational techniques in system operation and market analysis. Its unique angle of views to the electricity market and power system operation will be a good compensation to the current literature.

ACKNOWLEDGMENT

I GIVE MY HEARTFELT THANKS to all the contributors for their enthusiasm and timely inputs. Without them, this book would never become a reality. I also appreciate all the reviewers for their constructive comments and suggestions, and all the Task Force members for their active participation and discussion. Besides, I'm thankful for the help and patience from the staff of the IEEE Press and Wiley, specially, Dr. Mohamed E. El-Hawary, Editors Mary Hatcher and Brady A. Chin. I'm most grateful for the support my employer, PJM, has been giving me all these years. Last but not least, I am indebted to my family for their encouragement during the book development. My daughters, Sophia and Alice, truly understand my passion and commitment to power and energy society.

Hong Chen Philadelphia, USA

CONTRIBUTORS

Ross Baldick

(F'07) received B.Sc. degree in mathematics and physics and B.E. degree in electrical engineering from the University of Sydney, Sydney, New South Wales, Australia, and M.S. and Ph.D. degrees in electrical engineering and computer sciences from the University of California, Berkeley, CA, USA, in 1988 and 1990, respectively. From 1991 to 1992, he was a Postdoctoral Fellow with the Lawrence Berkeley Laboratory, Berkeley, CA, USA. In 1992 and 1993, he was an Assistant Professor with Worcester Polytechnic Institute, Worcester, MA, USA. He is currently a Professor with the Department of Electrical and Computer Engineering, the University of Texas at Austin, Austin, TX, USA. His research involves optimization, economic theory, and statistical analysis applied to electric power systems, particularly in the context of increased renewables and transmission. Dr. Baldick is a Fellow of the IEEE and the recipient of the 2015 IEEE PES Outstanding Power Engineering Educator Award.

Hong Chen

(SM'07) received her bachelor's (1992) and master's (1995) degrees, both in electrical engineering, from Southeast University, China, and her Ph.D. (2002) degree from University of Waterloo, Canada. From 1995 to 1998, she was with Nanjing Automation Research Institute (NARI), China, where she was engaged in the R&D of EMS power system applications. From 2003 to 2007, she was with ISO New England, as a principal analyst working on energy and ancillary service market design, development, and related analysis. She joined PJM Interconnection in 2007, as a senior consultant working on market and system operation. Dr. Chen is the chair of IEEE PES Power System Operation, Planning and Economics committee, and editor of

IEEE Transactions on Power Systems

,

IEEE Transactions on Smart Grid

, and

IEEE Power Engineering Letters

.

Kwok W. Cheung

received his Ph.D. from Rensselaer Polytechnic Institute, Troy, NY, USA, his M.S. from the University of Texas at Arlington, Arlington, TX, USA, and B.S. from National Cheng Kung University, Taiwan, all in Electrical Engineering. Dr. Cheung has over 26 years of experience in the electric power industry. He held various technical lead and project management positions responsible for the design and implementation of a few leading energy and transmission markets worldwide. He is currently a Principal Software Architect at GE Grid Solutions (formerly Alstom Grid). Cheung has authored and co-authored over 90 technical papers published in international journals and conference proceedings and two book chapters. He is a co-holder of six US patents on power system applications. Cheung is a registered professional engineer of the State of Washington, a certified Project Management Professional of PMI and a Distinguished Lecturer of the IEEE Power & Energy Society. Dr. Cheung is a Fellow of the IEEE.

Antonio J. Conejo,

professor at the Ohio State University, Columbus, OH, USA, received B.S. from Universidad P. Comillas, Madrid, Spain, M.S. from MIT, Cambridge, MA, USA, and Ph.D. from the Royal Institute of Technology, Stockholm, Sweden. He has published over 165 papers in SCI journals and is the author or co-author of books published by Springer, John Wiley, McGraw-Hill, and CRC. He has been the principal investigator of many research projects financed by public agencies and the power industry and has supervised 19 Ph.D. theses. He is an IEEE Fellow.

Pengwei Du

received his B.S.E.E. and M.S. from Southeast University, Nanjing, China, in 1997 and 2000, respectively, and his Ph.D. degree in electric power engineering from Rensselaer Polytechnic Institute, Troy, NY, USA in 2006. Dr. Du is a senior engineer with the Electric Reliability Council of Texas. Prior to this, he was a senior research engineer with Pacific Northwest National Laboratory (PNNL) from 2008 to 2013.

Pavel V. Etingov

(M'05) was born in 1976 in Irkutsk, Russia. He graduated with honors from Irkutsk State Technical University, specializing in electrical engineering, in 1997. He was a fellow at the Swiss Federal Institute of Technology in 2000–2001. Etingov received his Ph.D. degree in 2003 from the Energy Systems Institute of the Russian Academy of Sciences, Irkutsk, Russia. He is currently a senior research engineer at Pacific Northwest National Laboratory (PNNL), Richland, WA, USA. He is a member of the IEEE Power & Energy Society (PES), CIGRE, WECC Joint Synchronized Information Subcommittee (JSIS), WECC Modeling and Validation Work Group (MVWG), and North American SynchroPhasor Initiative (NASPI) research analysis task team. His research interests include stability analysis of electric power systems, power system operation, modeling and control, phasor measurement units (PMUs) application, wind and solar power generation, application of artificial intelligence to power systems, and software development.

Marija D. Ilić

received her Doctor of Science Degree in Systems Science at Washington University in St. Louis, MO, USA in 1980. She is currently a Professor of Electrical and Computer Engineering and Engineering at Carnegie Mellon University, Pittsburgh, PA, USA, and an Affiliate Professor in the Engineering and Public Policy Department. She is the Director of the Electric Energy Systems Group (EESG) at Carnegie Mellon. She was an Assistant Professor at Cornell University, Ithaca, NY, USA, and tenured Associate Professor at the University of Illinois at Urbana–Champaign, IL, USA. She was then a Senior Research Scientist in the Department of Electrical Engineering and Computer Science, Massachusetts Institute of Technology, Cambridge, MA, USA from 1987 to 2002. She has over 30 years of experience in teaching and research in the area of electrical power system modeling and control. Her main interest is in the systems aspects of operations, planning, and economics of the electric power industry. She has co-authored and co-edited a number of books in her field of interest. Her most recent book is

Engineering IT-Enabled Sustainable Electricity Services: The Tale of Two Low-Cost Green Azores Islands

. Professor Ilić is an IEEE Fellow.

Ruiwei Jiang

received B.S. degree in Industrial Engineering from the Tsinghua University, Beijing, China, in 2009, and Ph.D. degree in Industrial and Systems Engineering from the University of Florida, Gainesville, FL, USA, in 2013. Presently, he is an Assistant Professor with the Department of Industrial and Operations Engineering at the University of Michigan, Ann Arbor, MI, USA. His research interests include power system planning and operations, renewable energy management, and water distribution operations and system analysis.

Jianwei Liu

(SM'07) received his bachelor's (1992) and master's (1997) from Southeast University, Nanjing, China, and Ph.D. (2004) from University of Waterloo, Waterloo, Ontario, Canada, all in electrical engineering. He also holds an MBA degree (2009) from Pennsylvania State University, USA. From 1992 to 1999, he worked in the Chinese power industry as EMS engineer and energy project manager, including the first IPP in China. From 2004 to 2007, Dr. Liu was a lead EMS specialist at ISO New England, USA. In September 2007, he joined PJM Interconnection, working on operation support and infrastructure project integration. He is now a Senior Lead Engineer leading the implementation of more than 9000 MW new generation resources and hundreds of bulk transmission upgrade projects. Dr. Liu is an active volunteer in IEEE PES and SA activities, as Utility Forum chair and task force chair. His research interests include sustainable energy system development, distributed generation and energy storage, and network security monitoring and control.

Dr. Yuri V. Makarov

received his M.Sc. degree in Computers and Ph.D. in Electrical Engineering from St. Petersburg State Technical University, Russia. He was an Associate Professor at the University, conducted research at the University of Newcastle, University of Sydney, Australia, and Howard University, Washington, DC, USA. After that, he worked for Southern Company, Alabama, and occupied a position at the California Independent System Operator, California. Currently he is appointed as a Chief Scientist of Power Systems at the Pacific Northwest National Laboratory.

Alex D. Papalexopoulos

(M'80–SM'85–F'01) received the Electrical and Engineering Diploma from the National Technical University of Athens, Greece, and M.S. and Ph.D. degrees in Electrical Engineering from the Georgia Institute of Technology, Atlanta, GA, USA. He is president and founder of ECCO International, a specialized energy consulting company which provides consulting and software services on electricity market design and system operations and planning within and outside the United States to a wide range of clients such as regulators, governments, ISOs/TSOs, utilities, and other market participants. He has designed some of the most complex energy markets in the world including North and South America, Western and Eastern Europe and Asia. Prior to forming ECCO International, he was a Director of the Electric Industry Restructuring Group at the Pacific Gas and Electric Company in San Francisco, California. He has made substantial contributions in the areas of network grid optimization and pricing, energy market design and competitive bidding, and implementation of EMS applications and real-time control functions. He has published numerous scientific papers in IEEE and other journals. Dr. Papalexopoulos is a Fellow of IEEE, the 1992 recipient of PG&E's Wall of Fame Award, and the 1996 recipient of IEEE's PES Prize Paper Award. He is the 2016 recipient of an honorary doctorate from the School of Electrical and Computer Engineering of the University of Patras, Greece. He is also President, CEO, and Chairman of the Board of ColorPower, a startup clean tech company focused on research, development, and commercialization of demand-side management technologies.

Mohammad Shahidehpour

is the Bodine Chair Professor in the Electrical and Computer Engineering (ECE) Department and Director of Robert W. Galvin Center for Electricity Innovation at Illinois Institute of Technology (IIT), Chicago, IL, USA. He is the 2009 recipient of the honorary doctorate from the Polytechnic University of Bucharest and a Research Professor at King Abdulaziz University (Jeddah), North China Electric Power University (Beijing), and the Sharif University of Technology (Tehran). Dr. Shahidehpour was a member of the United Nations Commission on Microgrid Studies and an IEEE Fellow for his contributions to optimal generation unit commitment algorithms in electric power systems.

Chin Yen Tee

is a Ph.D. candidate in the Department of Engineering and Public Policy at Carnegie Mellon University, PA, USA. She received her BA in Engineering and Economics from Smith College, Massachusetts in 2011. Her research interests include business models, regulation, and market design for the future electricity grid.

Dr. Jianhui Wang

is the Section Manager for Advanced Power Grid Modeling at Argonne National Laboratory. He is the Secretary of the IEEE Power & Energy Society (PES) Power System Operations Committee. He has authored/co-authored more than 150 journal and conference publications. He is an editor of

Journal of Energy Engineering

and

Applied Energy

. He received the IEEE Chicago Section 2012 Outstanding Young Engineer Award and is an Affiliate Professor at Auburn University and an Adjunct Professor at University of Notre Dame. He has also held visiting positions in Europe, Australia, and Hong Kong including a VELUX Visiting Professorship at the Technical University of Denmark (DTU). Dr. Wang is the Editor-in-Chief of the

IEEE Transactions on Smart Grid

and an IEEE PES Distinguished Lecturer. He is the recipient of the IEEE PES Power System Operation Committee Prize Paper Award in 2015.

Jun Wu

joined Alstom Grid in 2008. She is currently a senior power system engineer at GE Grid Solutions (formerly Alstom Grid). Before joining Alstom, she worked as a power system engineer in the PSASP (Power System Analysis Software Package) group at China Electric Power Research Institute (CEPRI) from 1996 to 2002. She received her B.S. from South China University of Technology, Guangzhou, China in 1990 and M.S. from CEPRI in 1996. In 2007, she studied at California State University, East Bay, CA, USA for her MBA. Jun's interests include power system analysis, market applications, and optimization. Jun is a Senior Member of the IEEE.

Lei Wu

received B.S. degree in electrical engineering and M.S. degree in systems engineering from Xi'an Jiaotong University, Xi'an, China, in 2001 and 2004, respectively, and the Ph.D. degree in electrical engineering from the Illinois Institute of Technology, Chicago, IL, USA, in 2008. He was a Senior Research Associate at the Robert W. Galvin Center for Electricity Innovation at Illinois Institute of Technology from 2008 to 2010. Presently, he is an Associate Professor in the Electrical and Computer Engineering Department at Clarkson University, Potsdam, NY, USA. His research interests include power systems optimization and economics. He received the NSF Faculty Early Career Development (CAREER) Award in 2013, and IBM Smarter Planet Faculty Innovation Award in 2012. He is an IEEE Senior Member. He is an Editor of the

IEEE Transactions on Sustainable Energy

and the

IEEE Transactions on Power Systems.

PART IINTEGRATED SYSTEM AND MARKET OPERATION

CHAPTER 1BALANCE ECONOMIC EFFICIENCY AND OPERATION RISK MITIGATION

Hong Chen and Jianwei Liu

SYSTEM OPERATION AND MARKET operation are tightly coupled. Electricity market operation is built upon secure system operation, trying to use market signals to address system operation needs and achieve economic efficiency. By responding to market price signals, market participants help with system operation. Therefore, the integrated system and market operation can be viewed as an engineering control system with dynamics and stability issues.

The integrated operation has a multifaceted nature. The ultimate goal is to reach the equilibrium of economic efficiency and operation risk mitigation. Finding and approximating equilibrium is an emerging frontline topic in the electricity market business.

This chapter reviews the state-of-the-art wholesale market structures and products, with the focus on their interactive impacts on daily system operations. Current challenges in approximating the equilibrium at independent system operator (ISO)/regional transmission operator (RTO) are also discussed.

Heuristic engineering efforts to approximate and achieve electricity market equilibrium at ISO/RTO have gained extensive attention from both market participants and regulatory agencies. Pennsylvania–New Jersey–Maryland (PJM)'s experience on evaluating and improving economic efficiency is discussed as a successful industrial practice in this domain. The practice of perfect dispatch (PD) at PJM has effectively measured economic efficiency in the PJM wholesale electricity market and has successfully provided guidance to system operators through daily operation. The PD practice has demonstrated over $1 billion in production cost saving in the past 8 years, a good example of the huge potential in the research domain of this book.

1.1 POWER SYSTEM OPERATION RISK MITIGATION: THE PHYSICS

1.1.1 An Overview of Power System

The major components of power system are generation resources, demand resources, or load, connected by transmission facilities and distribution facilities. Power system is considered as the largest machine (or control system) in the world [1].

Generation resources can be divided based on fuel types, such as nuclear, hydro, coal, oil, natural gas, diesel, wind, and solar. For demand, normally they are not very controllable to system operation. With smart grid technologies, some are now more responsive to system conditions, called demand response. Transmission facilities include transmission lines, transformers, capacitors, reactors, phase shifters, and FACTs devices, such as static var compensator (SVC) and TCSC. Transmission facilities normally connect to the higher voltage levels, for example, 1000, 765, 500, 345, 230, 138, and 115 kV for bulk power transfer. Distribution facilities normally operate under lower voltage levels (e.g., below 115 kV). Distribution facilities bring electricity down to end customers.

Power system operation is guided by the basic circuit theory: Ohm's law and Kirchhoff's laws:

All the injections into a node are summed to be zero.

The distribution of the flow is based on the resistances and reactances of the branches.

All facilities have physical limitations. As a control system, power system also has its dynamic characteristics and limitations.

Power systems are normally interconnected to reduce total generation requirement, reduce total production cost, and enhance reliability. For example, in North America, there are four major interconnections: the Eastern Interconnection, the Western Interconnection, the Electric Reliability Council of Texas (ERCOT) Interconnection, and the Hydro-Quebec Interconnection [2]. In Europe, there is the synchronous grid of Continental Europe, known as European Network for Transmission System Operators for Electricity (ENTSO-E) [3]. It is the largest synchronous grid in the world.

Frequency and voltage are the two most important parameters of an interconnected power system. They have to be maintained at normal values for stable system and safety of the equipment. For example, 60 Hz frequency is operated in North America and 50 Hz system is dominant in Europe, Asia, and other parts of the world.

1.1.2 System Operation Risk Mitigation

1.1.2.1 Keep Power Balance

Electricity demand is constantly changing in the system, every hour, every minute, and every second. It is significantly impacted by weather conditions and pattern of human activities. Due to limited energy storage devices, generation has to be balanced with demand at all times, which is a moving target.

If the total generation in the system is not balanced with the total system demand, system frequency changes. Over- and under-generation can impact system frequency, causing time error. If generation is higher than demand, frequency becomes higher; if generation is less than demand, frequency becomes lower.

For interconnected power systems, the interchanges with neighboring systems are also important components in keeping power balance. Some of the transactions can be scheduled ahead of time based on the specified rules. Therefore, power balance equation can be expressed by equation (1.1):

(1.1)

where total loss is the energy lost in the system equipment and net interchange is the net flow out of the interconnected system.

All generation resources have their physical limitations, such as time to start, minimum run time, minimum down time, minimum and maximum output, ramp rate, turnaround time, and mill points. To balance generation with demand and maintain system frequency, some generation (normally slow-start generation) has to be scheduled way ahead of time based on forecasted load. As the time is close to real time, more generation (normally fast start) is committed to balance demand. Every 5 min, generation is moved up or down to follow the load. For certain types of generating units which can move up and down within 4 s, called as regulation units, their output can be adjusted based on automatic generation control (AGC), which is often referred as secondary frequency control. The governor control of generators is often called as primary frequency control. In summary, generation is staged to balance with load and maintain system frequency.

Demand forecast, often called as load forecast, is important to schedule and dispatch generation. When scheduling generation 1 day to 1 week ahead, load is normally forecasted hourly for 24 or 168 h ahead of time. Many factors can impact load, therefore, they are factored into load forecast. The main impacting factors are temperature, humidity, wind speed, cloud covering, special social events, such as holidays or weekends. When dispatching generation in real time, very short term load forecast is used to forecast load every 5 min for 1–3 h ahead.

In North America, area control error (ACE) is used to identify the imbalance between generation and load (including interchange). Balance is measured by the frequency of the system. ACE is measured based on equation (1.2):

(1.2)

where NIA represents the actual net interchange, NIS represents the scheduled net interchange, B represents the frequency bias constant, which is an estimate of system frequency response, FA represents the actual frequency, and FS represents the scheduled frequency. IME represents the interchange metering error [4].

There are variabilities and uncertainties in both generation and load. Tripped generators and sudden load increases cause the frequency to spike low while sudden large load decreases cause the frequency to spike high. To mitigate the associated power imbalance, reserves are needed in the system to control normal frequency deviation and to survive large disturbances. Reserves are the flexible unused available real power response capacity hold to ensure continuous match between generation and load during normal conditions and effective response to sudden system changes, such as loss of generation and sudden load changes. They are critical to maintain system reliability.

Reserves are secured across multiple timescales to respond to different events. The terminologies and rules vary in different systems, but they all share some fundamental characteristics. In general, some reserve types are for nonevent continuous needs; and others are for contingency events (e.g., loss of generator or facility tripping) or longer timescale events (e.g., load ramps and forecast errors). They are further categorized based on response time, online/offline status, and physical capabilities.

In North America, according to North America Electric Reliability Corporation (NERC), operating reserves are defined as “that capability above firm system demand required to provide for regulation, load forecast error, equipment forced and scheduled outages and local area protection. It consists of spinning and non-spinning reserve” [2]. Reserves are often categorized as 30 min supplemental reserve, 10 min non-spinning reserve, 10 min spinning reserve, regulating reserve, and so on. Often, regulating reserves are procured in both upward and downward directions to respond to normal load changes. They are the reserves responsive to AGC command and only carried in regulating units. Contingency reserves are used for the loss of supply, for example, generation losses. Spinning or synchronized reserves are unused synchronized capacity and interruptible load which is automatically controlled and can be available within a set period of time. Non-spinning or non-synchronized reserves are real power capability not currently connected to the system but can be available within a specified time period, which may vary in different systems.

In Europe, reserves are generally defined in three categories: primary, secondary, and tertiary control [3]. Primary control is activated within 30 s to respond to frequency deviation. Secondary control must be operational within 15 min to respond to contingency event and consists of both AGC units and fast start units. Tertiary control has a slower response to restore primary and secondary control units back to the reserve state.

The reserve requirements are also set differently in different systems. Common practices are based on the largest contingency of the system. NERC BAL-002 standard requirement is to maintain at least enough contingency reserve to cover the most severe single contingency [2]. Each region/system has different operation practices. For example, in New York system, 10-min spinning reserve requirement is set as one-half of the largest single contingency [5], while PJM's synchronized reserve requirement is set as the largest single contingency [6]. For regulating reserve, NERC does not impose explicit requirement, just to maintain sufficient regulating reserves to meet NERC Control Performance Standards (CPS1,CPS2, and BAAL) [2]. In Europe, primary control reserves are required based on members' share of network use for energy production. Secondary control reserves are required in proportion to the maximum of yearly load in the region. Tertiary control reserve requirements are set by the individual countries [7].

With increasing penetration level of intermittent renewable resources, the reserve requirements are being reevaluated and adjusted to account for increased variability. For example, in ERCOT, forecasted wind output is factored in setting the regulating and contingency reserve requirements [8].

Interchange uncertainty poses another challenge to maintain power balance. It is volatile, hard to forecast, and significantly impacted by the market dynamics. Efforts have been started to forecast interchange in some systems, for example, PJM system.

1.1.2.2 Maintain Network Security

Network (transmission and distribution) has limited capability to transfer power from generation to load due to facility thermal, stability, and/or voltage limits. Power transfer can be restricted to any of these limits, or combination. Network security constraints are nonlinear, especially stability limits and voltage limits. Security-constrained optimal power flow (OPF) is a fundamental tool to ensure a secure operation.

1.1.2.2.1 Facility Thermal Limitation

Network facilities, such as transmission lines, transformers, have thermal ratings limiting the amount of current or apparent power that can be carried. Exceeding the thermal limits of transmission lines can cause the conductors to sag and stretch due to overheating, which could further result in faults or fires. Most equipment can be safely overloaded in certain degree. The key is how great the overload is and how long it does last. Typically, thermal ratings are set to allow specified overload for a specified period of time.

Due to thermal capabilities, the flow on any facility has to be within its thermal limit. Due to the uncertainty of facility tripping, it could overload other facilities. Therefore, the system has to be operated in a manner that it will stay within its limit under normal system condition and also under the conditions that another facility trips. The historical practice is N–1 contingency criteria, which means that when a facility trips, it will not incur overload on another facility.

In North America, normal continuous rating and emergency ratings (long term and short term) are specified for each facility [9]. Some systems have load dump ratings as well [10, 11]. Ambient temperature can affect facility thermal ratings significantly. Some systems have the thermal ratings corresponding to different temperature sets, such as PJM [10]. Dynamic line ratings are being implemented or investigated in many systems [3, 8]. The severity of thermal limit exceeding often determines corrective actions and time to correct with load shedding [10].

Power flow analysis and contingency analysis are used to determine the flow and contingency flow on the facilities. The actual flow on the facilities often comes from state estimation.

1.1.2.2.2 System Stability Limitation

As a control system, power system is also subject to stability limitations, that is, system should be able to return to the stable state after a disturbance. As shown in Figure 1.1, there are two main stability categories experienced in a power system, namely, angular stability and voltage stability. Each category can be further divided based on how big the disturbance is: small perturbation and large disturbance. According to [12], there is also mid-term/long-term stability which involves large voltage and frequency shift.

Figure 1.1 Power system stability categorization. Adapted from Kundur [12].

Voltage is the key to the overall stability of a power system. Angular stability is related to the angular separation between points in the power system; and voltage stability is related to the magnitude of the system voltages and reactive power reserves. Often, angular and voltage instability go hand in hand.

A power system is composed of many synchronous machines. Angular stability has to be maintained for the synchronization of the grid, to ensure that system torque and power angle remain controllable. The angles change as system conditions change. Interconnected power system loses synchronization when power transfer rises to extremely large magnitudes and power angles reach excessive values. Following a disturbance, transient stability becomes the concern. Power system may become instable for a period of time: angles may reach high magnitudes and rapidly change over a wide range. Synchronous generators are critical to the transient stability analysis. When torque/power angles are too large, and disturbances occur, magnetic bonds of generators may be lost. System becomes angle unstable when system operators lose their ability to control angles and power flows.

Stability analysis is often used to determine stability limits. Many power systems restrict their real power transfers due to transient stability concerns, for example, those are the power systems with long transmission lines and remote generation.

Voltage stability is the ability of a power system to maintain adequate voltage magnitudes so that when the load is increased, the power delivered to that load also increases. In a voltage-stable system, both power and voltage are controllable. Voltage stability is mainly a function of power system load. Excessive loading in the power system leads to deficiencies in reactive power and the system is no longer able to support voltage. A voltage collapse could then occur. The shortage of reactive power drives voltage instability.

When a power system experiences a voltage collapse, system voltages decay to a level from which they are unable to recover. Voltage collapse is a process during which voltage instability leads to loss of voltage in a part of the power system. A system enters a period of voltage instability prior to a voltage collapse. The effects of a voltage collapse are more serious than those of a typical low-voltage scenario. As a consequence of voltage collapse, entire systems may experience blackout. Restoration procedures are then required to restore the power system.

As power systems are pushed to transfer more and more power, the likelihood of voltage collapse occurring becomes greater. Voltage stability is mainly a concern in heavily loaded systems. Voltage stability has been responsible for major network collapse in recent years [13]. Often, system transfer capabilities are limited by steady-state voltage stability limits.

1.1.2.2.3 Voltage Limitation

All equipments are designed to operate at certain rated supply voltages. Large deviation could cause damage to system equipment. High voltages can lead to the breakdown of equipment insulation, cause transformer overexcitation, and adversely affect customer equipments. Low voltages can impact power system equipment and operations in numerous ways.

Voltage control is closely related to the availability of reactive power. The amount of available reactive support often determines power transfer limit. Heavy power transfers are a principal cause of low voltage due to the reactive power losses. Lightly loaded transmission lines are a principal cause of high voltage. Capacitors, reactors, load tap changers (LTCs), and SVCs are the equipment to control system voltage. For example, reactive support from capacitor is often needed to help prevent low-voltage problem. In system operation, reactive reserves need to be maintained and voltage deviations need to be controlled.

Often, reactive transfer interfaces are defined across the transmission paths to prevent voltage criteria violation and voltage collapse. The interface limits are used to limit the total flow over the interfaces. The reactive limits are either pre-contingency active power limits, or post-contingency active power limits. PV curves are often used to determine reactive interface limits.

1.1.2.3 Energy Management System

Energy management system (EMS) is an important tool to assist power system operation. SCADA collects measurements for system components and alarms correspondingly based on measurement. State estimation provides current system status: topology, generation, load, and power flow. State estimation relies increasingly on new technologies, such as phasor measurement units (PMUs). Network applications, such as power flow analysis, contingency analysis, voltage stability analysis, and transient stability analysis, evaluate pre- and post-contingency thermal limits, voltage limits, and stability limits. N–1 contingency rule is commonly applied in practice. Contingency element could be generation or network facilities.

When a facility overloads, directed actions, such as adjusting phase shift regulators (PARs), switching reactive devices in/out of services or adjusting generator reactive output, switching facilities in/out of services, adjusting generation of real power output via re-dispatch, and adjusting imports/exports, can be used pre-contingency to control post-contingency operation. If directed actions do not relieve an actual or simulated post-contingency violation, then emergency procedures may be directed, including dropping or reducing load as required. Thermal and voltage constraints are often controlled cost-effectively on a pre-contingency basis.

EMS is also used to perform outage analysis to evaluate if an outage has reliability impacts. Long-term analysis could be 1–6 months ahead. Short-term analysis can be 1 day, 3 days to 1 week ahead. If an outage could jeopardize system reliability, it will be canceled or rescheduled. Outage analysis directly mitigates system operation risk.

1.1.3 New Trends of Power System Operation

Power systems are under significant changes in the twenty-first century globally, with the goals of improving efficiency of electricity production, transmission, and consumption. Rapid technology innovations such as smart grid technologies, new transmission and power electronic devices, and high-efficiency energy consumption technologies are emerging and have been utilized in today's power system planning and operation.

New trends in sustainable energy system development are also observed worldwide. Environmental issues, from pollution control of fossil fuel power generation and reliability enhancement of nuclear generation facilities, to massive integration of renewable energy resources, have brought in deep social and economic impact in today's system planning and operation practices.

Economic considerations have been coherent factors in power system planning and operation. Classic stories, such as AC/DC system competition in 1900s and the emerging of power pools, have educated many generations of power engineers on the integration of power system facilities. Growth of demands in overall energy consumption, increasing constraints of nature resources, and enhanced regional (and even global) system integration are still hot topics in the planning fields. Meanwhile, thanks to the diversified energy resources and modern power electronic technologies, micro-grids have been recognized as plausible approaches to modernized power system at or near the demand side. Hence, in order to adequately depict today's power grids for planners and operators, system models are becoming more and more complicated with details of new facilities, as well as dynamics and price elasticity characteristics of demands.

Electricity markets, which have been successfully implemented in many regions, have deeply reshaped power system planning and operation, philosophically and practically. Wholesale electricity markets not only provide platforms for energy transactions in forward and real-time (RT) markets, but also play key roles in system operation. Demand responses have shown significant effects on system reliability and market efficiency. Electricity markets need to be continuously developed and evolved to adapt to significant renewable resource penetration.

With these changes as background, power system planners, operation engineers, researchers, and policy makers are faced with the need of reviewing the upfront challenges in today's industry to be prepared for the future.

1.2 INTEGRATED SYSTEM AND MARKET OPERATION: THE BASICS

Electricity market operation needs to be tightly integrated with system operation, to reinforce reliable operation of the systems through strong financial incentives and bring efficiency to system operation.

1.2.1 Integrated Operation Philosophy

The objective of electricity markets is to improve economic efficiency, while risk mitigation remains the main focus of power system operation, as discussed in Section 1.1. These two different objectives often have opposite impact on resource scheduling, dispatch, and pricing. As shown in Figure 1.2, both objectives need to be respected in the integrated system and market operation. Figure 1.2 shows the integrated operation philosophy, not representing time sequences. The ultimate goal is to achieve market equilibrium, a balance between the two opposite objectives, that is, maximize total social surplus and minimize the total cost of operation risk.

Figure 1.2 Integrated system and market operation.

Operating criteria drive system operation practices. They are often formulated as system operation constraints in the market operation administered by ISO/RTOs. The resulting prices and dispatch signals reflect system conditions related to the modeled constraints. By responding to prices, market participants, such as generation companies, load serving entities, distribution companies, transmission